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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 SeptemberJune 30, 20142015
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from           to            
 
Commission
File Number
 
Registrant, State of Incorporation,
Address and Telephone Number
 
I.R.S. Employer
Identification No.
1-3526 
The Southern Company
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
 58-0690070
     
1-3164 
Alabama Power Company
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35203
(205) 257-1000
 63-0004250
     
1-6468 
Georgia Power Company
(A Georgia Corporation)
241 Ralph McGill Boulevard, N.E.
Atlanta, Georgia 30308
(404) 506-6526
 58-0257110
     
001-31737 
Gulf Power Company
(A Florida Corporation)
One Energy Place
Pensacola, Florida 32520
(850) 444-6111
 59-0276810
     
001-11229 
Mississippi Power Company
(A Mississippi Corporation)
2992 West Beach Boulevard
Gulfport, Mississippi 39501
(228) 864-1211
 64-0205820
     
333-98553 
Southern Power Company
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
 58-2598670



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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No ¨
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 ¨
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):
Registrant 
Large
Accelerated
Filer
 
Accelerated
Filer
 
Non-
accelerated
Filer
 
Smaller
Reporting
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.)Act). Yes ¨ No þ (Response applicable to all registrants.)
 
Registrant 
Description of
Common Stock
 Shares Outstanding at SeptemberJune 30, 20142015
The Southern Company Par Value $5 Per Share 899,812,716908,424,808
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 5,442,7175,642,717
Mississippi Power Company Without Par Value 1,121,000
Southern Power Company Par Value $0.01 Per Share 1,000
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
SeptemberJune 30, 20142015


  
Page
Number
   
 PART I—FINANCIAL INFORMATION 
   
Item 1.Financial Statements (Unaudited) 
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations 
  
 
 
 
 
 
  
 
 
 
 
 
  
 
 
 
 
 
  
 
 
 
 
 
  
 
 
 
 
 
  
 
 
 
 
 
 
Item 3.
Item 4.

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q
SeptemberJune 30, 20142015


  
Page
Number
  
Item 1.
Item 1A.
Item 2.Inapplicable
Item 3.Defaults Upon Senior SecuritiesInapplicable
Item 4.Mine Safety DisclosuresInapplicable
Item 5.Other InformationInapplicable
Item 6.
 


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DEFINITIONS
 
TermMeaning
  
2012 MPSC CPCN OrderA detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
2013 ARPAlternative Rate Plan approved by the Georgia PSC for Georgia Power for the years 2014 through 2016
AFUDCAllowance for Funds Used During Constructionfunds used during construction
Alabama PowerAlabama Power Company
ASCAccounting Standards Codification
Baseload ActState of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
Chancery CourtCCRChancery Court of Harrison County, MississippiCoal combustion residuals
Clean Air ActClean Air Act Amendments of 1990
ContractorWestinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.), a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V.
CO2
Carbon dioxide
CPCNCertificate of Public Conveniencepublic convenience and Necessitynecessity
CWIPConstruction work in progress
DOEU.S. Department of Energy
ECO PlanMississippi Power's Environmental Compliance Overview Plan
Eligible Project CostsCertain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program
EPAU.S. Environmental Protection Agency
FERCFederal Energy Regulatory Commission
FFBFederal Financing Bank
FitchFitch Ratings, Inc.
Form 10-KCombined 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, 20132014
GAAPGenerally accepted accounting principles
Georgia PowerGeorgia Power Company
GHGGreenhouse gas
Gulf PowerGulf Power Company
IGCCIntegrated coal gasification combined cycle
IICIntercompany Interchange Contractinterchange contract
Internal Revenue CodeInternal Revenue Code of 1986, as amended
IRSInternal Revenue Service
ITCsITCInvestment tax creditscredit
Kemper IGCCIGCC facility under construction in Kemper County, Mississippi
KWHKilowatt-hour
LIBORLondon Interbank Offered Rate
MATS ruleMercury and Air Toxics Standards rule
Mirror CWIPA regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers
Mississippi PowerMississippi Power Company
mmBtuMillion British thermal unitunits
Moody'sMoody's Investors Service, Inc.
MWMegawatt
NCCRNuclear Construction Cost Recovery
NRCU.S. Nuclear Regulatory Commission
OCIOther comprehensive income

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DEFINITIONS
(continued)
TermMeaning
  
NCCRGeorgia Power's Nuclear Construction Cost Recovery
NRCU.S. Nuclear Regulatory Commission
OCIOther comprehensive income
PEPMississippi Power's Performance Evaluation Plan
Plant Vogtle Units 3 and 4Two new nuclear generating units under construction at Plant Vogtle
power poolThe operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power Company are subject to joint commitment and dispatch in order to serve their combined load obligations
PPAPower purchase agreement
PSCPublic Service Commission
Rate CNPAlabama Power's Rate Certificated New Plant
Rate CNP ComplianceAlabama Power's Rate Certificated New Plant Compliance
Rate CNP EnvironmentalAlabama Power's Rate Certificated New Plant Environmental
Rate CNP PPAAlabama Power's Rate Certificated New Plant Power Purchase Agreement
registrantsSouthern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company
ROEReturn on equity
S&PStandard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
scrubberFlue gas desulfurization system
SECU.S. Securities and Exchange Commission
SMEPASouth Mississippi Electric Power Association
Southern CompanyThe Southern Company
Southern Company systemSouthern Company, the traditional operating companies, Southern Power, Southern Electric Generating Company, Southern Nuclear, Southern Company Services, Inc. (the Southern Company system service company), Southern Communications Services, Inc., and other subsidiaries
Southern NuclearSouthern Nuclear Operating Company, Inc.
Southern PowerSouthern Power Company and its subsidiaries
S&PStandard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
traditional operating companiesAlabama Power, Georgia Power, Gulf Power, and Mississippi Power
Vogtle OwnersGeorgia 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
WestinghouseWestinghouse Electric Company LLC
wholesale revenuesrevenues 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 retail rates, the strategic goals for the wholesale business, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the American Taxpayer Relief Act of 2012, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other capital 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, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, CO2, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
current and future litigation, regulatory investigations, proceedings, or inquiries, including pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS and state tax 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 last recession, population and business growth (and declines), the effects of energy conservation measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity factors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training, unforeseen engineering or design problems, delays associated with start-up activities (including major equipment failure and system integration), and/or operations;
ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any operational and environmental performance standards, including any PSC requirements and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of Southern Company's employee and retiree benefit plans and the Southern Company system's 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;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions and related legal proceedings involving the commercial parties;
actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of Mississippi Power's proposed rate recovery plan, as ultimately amended, which currently includes the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2014, and satisfaction of requirements to utilize ITCs and grants;
Mississippi PSC review of the prudence of Kemper IGCC costs;


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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 retail rates, the strategic goals for the wholesale business, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plan, and nuclear decommissioning trust fund contributions, financing activities, completion dates of acquisitions, construction projects, and changing fuel sources, filings with state and federal regulatory authorities, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and 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, environmental laws including regulation of water, CCR, and emissions of sulfur, nitrogen, CO2, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
current and future litigation, regulatory investigations, proceedings, or inquiries, including pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS and state tax 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 last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);
the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of Southern Company's employee and retiree benefit plans and the Southern Company system's 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;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions and related legal proceedings involving the commercial parties;
actions related to cost recovery for the Kemper IGCC, including actions relating to Mississippi PSC approval of a rate recovery plan, including Mississippi Power's request for interim rates, proposed securitization, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2015, and satisfaction of requirements to utilize ITCs and grants;
the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;
Mississippi PSC review of the prudence of Kemper IGCC costs;


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)
the outcomeultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's order implementing such decision, and any further related legal or regulatory proceedings regarding any settlement agreement between Mississippi Powerproceedings;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and the Mississippi PSC, the March 2013 rate order approving retail rate increases consistent with the termssuccessful performance of any settlement agreement, or the Baseload Act;necessary corporate functions;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
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 the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents, including cyber intrusion;incidents;
interest rate fluctuations and financial market conditions and the results of financing efforts, includingefforts;
changes in Southern Company's and any of its subsidiaries' credit ratings;ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any potential U.S. credit rating downgrade or other sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of Southern Company's subsidiaries to obtain additional generating capacity at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system'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 settingstandard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.


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THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

9

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
2014 2013 2014 20132015 2014 2015 2014
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$4,558
 $4,319
 $12,186
 $11,237
$3,714
 $3,770
 $7,256
 $7,628
Wholesale revenues600
 520
 1,719
 1,406
448
 515
 915
 1,119
Other electric revenues169
 166
 503
 477
162
 169
 325
 334
Other revenues12
 12
 42
 40
13
 13
 24
 30
Total operating revenues5,339
 5,017
 14,450
 13,160
4,337
 4,467
 8,520
 9,111
Operating Expenses:              
Fuel1,656
 1,580
 4,765
 4,216
1,200
 1,462
 2,412
 3,109
Purchased power194
 145
 514
 367
171
 133
 315
 320
Other operations and maintenance1,021
 928
 3,026
 2,849
1,100
 1,019
 2,222
 2,005
Depreciation and amortization514
 480
 1,515
 1,422
500
 504
 987
 1,001
Taxes other than income taxes258
 243
 751
 710
245
 246
 497
 493
Estimated loss on Kemper IGCC418
 150
 798
 1,140
23
 
 32
 380
Total operating expenses4,061
 3,526
 11,369
 10,704
3,239
 3,364
 6,465
 7,308
Operating Income1,278
 1,491
 3,081
 2,456
1,098
 1,103
 2,055
 1,803
Other Income and (Expense):              
Allowance for equity funds used during construction63
 53
 182
 139
39
 62
 102
 119
Interest expense, net of amounts capitalized(207) (202) (623) (628)(180) (210) (393) (416)
Other income (expense), net(7) (5) (20) (31)(12) (6) (19) (13)
Total other income and (expense)(151) (154) (461) (520)(153) (154) (310) (310)
Earnings Before Income Taxes1,127
 1,337
 2,620
 1,936
945
 949
 1,745
 1,493
Income taxes392
 468
 889
 657
302
 321
 576
 497
Consolidated Net Income735
 869
 1,731
 1,279
643
 628
 1,169
 996
Dividends on Preferred and Preference Stock of Subsidiaries17
 17
 51
 49
14
 17
 31
 34
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries$718
 $852
 $1,680
 $1,230
$629
 $611
 $1,138
 $962
Common Stock Data:              
Earnings per share (EPS) -       
Earnings per share (EPS) —       
Basic EPS$0.80
 $0.97
 $1.88
 $1.41
$0.69
 $0.68
 $1.25
 $1.08
Diluted EPS$0.80
 $0.97
 $1.87
 $1.40
$0.69
 $0.68
 $1.25
 $1.07
Average number of shares of common stock outstanding (in millions)              
Basic898
 878
 894
 874
909
 895
 910
 892
Diluted902
 881
 898
 879
912
 899
 914
 896
Cash dividends paid per share of common stock$0.5250
 $0.5075
 $1.5575
 $1.5050
$0.5425
 $0.5250
 $1.0675
 $1.0325
The accompanying notes as they relate to Southern Company are an integral part of these condensedconsolidated financial statements.


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
2014 2013 2014 20132015 2014 2015 2014
(in millions) (in millions)(in millions) (in millions)
Consolidated Net Income$735
 $869
 $1,731
 $1,279
$643
 $628
 $1,169
 $996
Other comprehensive income (loss):              
Qualifying hedges:              
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2 and $5, respectively1
 1
 4
 7
Changes in fair value, net of tax of $12, $-, $1, and $-, respectively19
 
 1
 
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $2, and $2, respectively
2
 1
 3
 2
Pension and other post retirement benefit plans:              
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2 and $3, respectively1
 1
 2
 4
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $1, respectively
1
 1
 3
 2
Total other comprehensive income (loss)2
 2
 6
 11
22
 2
 7
 4
Dividends on preferred and preference stock of subsidiaries(17) (17) (51) (49)(14) (17) (31) (34)
Comprehensive Income$720
 $854
 $1,686
 $1,241
$651
 $613
 $1,145
 $966
The accompanying notes as they relate to Southern Company are an integral part of these condensedconsolidated financial statements.


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Nine Months
Ended September 30,
For the Six Months
Ended June 30,
2014 20132015 2014
(in millions)(in millions)
Operating Activities:      
Consolidated net income$1,731
 $1,279
$1,169
 $996
Adjustments to reconcile consolidated net income to net cash provided from operating activities —      
Depreciation and amortization, total1,798
 1,725
1,171
 1,182
Deferred income taxes330
 263
783
 46
Allowance for equity funds used during construction(182) (139)(102) (119)
Stock based compensation expense51
 48
66
 40
Estimated loss on Kemper IGCC798
 1,140
32
 380
Income taxes receivable, non-current(444) 
Other, net(74) 76
(6) 23
Changes in certain current assets and liabilities —      
-Receivables(640) (407)(158) (579)
-Fossil fuel stock522
 471
136
 419
-Materials and supplies(45) 33
(21) (20)
-Other current assets(29) (1)(78) (88)
-Accounts payable(92) (140)(311) (231)
-Accrued taxes403
 268
(60) 72
-Accrued compensation96
 (198)(269)��(40)
-Mirror CWIP82
 67
-Other current liabilities20
 (7)117
 (78)
Net cash provided from operating activities4,687
 4,411
2,107
 2,070
Investing Activities:      
Property additions(3,903) (3,978)(2,647) (2,692)
Investment in restricted cash(11) (169)
Distribution of restricted cash37
 94
Nuclear decommissioning trust fund purchases(635) (744)(933) (445)
Nuclear decommissioning trust fund sales633
 742
928
 443
Cost of removal, net of salvage(106) (90)(87) (54)
Change in construction payables, net56
 89
Prepaid long-term service agreement(145) (79)(110) (93)
Other investing activities(27) 122
27
 (17)
Net cash used for investing activities(4,157) (4,102)(2,766) (2,769)
Financing Activities:      
Decrease in notes payable, net(1,117) (70)
Increase in notes payable, net184
 339
Proceeds —      
Long-term debt issuances2,715
 2,421
3,075
 1,314
Interest-bearing refundable deposit75
 

 75
Preference stock
 50
Common stock issuances484
 479
116
 318
Redemptions —   
Short-term borrowings320
 
Redemptions and repurchases—   
Long-term debt(437) (1,767)(939) (431)
Common stock repurchased(5) (19)
Interest-bearing refundable deposits(275) 
Preferred and preference stock(412) 
Common stock(115) (5)
Short-term borrowings(250) 
Payment of common stock dividends(1,391) (1,314)(972) (920)
Payment of dividends on preferred and preference stock of subsidiaries(51) (49)(36) (34)
Other financing activities(48) 14
66
 (33)
Net cash provided from (used for) financing activities225
 (255)
Net cash provided from financing activities762
 623
Net Change in Cash and Cash Equivalents755
 54
103
 (76)
Cash and Cash Equivalents at Beginning of Period659
 628
710
 659
Cash and Cash Equivalents at End of Period$1,414
 $682
$813
 $583
Supplemental Cash Flow Information:      
Cash paid during the period for —   
Interest (net of $80 and $67 capitalized for 2014 and 2013, respectively)$560
 $564
Cash paid (received) during the period for --   
Interest (net of $57 and $47 capitalized for 2015 and 2014, respectively)$374
 $365
Income taxes, net263
 149
(16) 212
Noncash transactions — accrued property additions at end of period415
 539
Noncash transactions — capital lease obligation
 83
Noncash transactions — Accrued property additions at end of period345
 509
The accompanying notes as they relate to Southern Company are an integral part of these condensedconsolidated financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets At September 30,
2014
 At December 31,
2013
 At June 30,
2015
 At December 31,
2014
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $1,414
 $659
 $813
 $710
Receivables —        
Customer accounts receivable 1,439
 1,027
 1,312
 1,090
Unbilled revenues 476
 448
 579
 432
Under recovered regulatory clause revenues 104
 58
 173
 136
Other accounts and notes receivable 259
 304
 209
 307
Accumulated provision for uncollectible accounts (20) (18) (17) (18)
Fossil fuel stock, at average cost 817
 1,339
 795
 930
Materials and supplies, at average cost 1,018
 959
 1,043
 1,039
Vacation pay 170
 171
 177
 177
Prepaid expenses 387
 489
 564
 665
Deferred income taxes, current 499
 506
Other regulatory assets, current 147
 124
 382
 346
Other current assets 47
 39
 76
 50
Total current assets 6,258
 5,599
 6,605
 6,370
Property, Plant, and Equipment:        
In service 68,545
 66,021
 71,462
 70,013
Less accumulated depreciation 23,846
 23,059
 23,918
 24,059
Plant in service, net of depreciation 44,699
 42,962
 47,544
 45,954
Other utility plant, net 218
 240
 87
 211
Nuclear fuel, at amortized cost 840
 855
 889
 911
Construction work in progress 7,410
 7,151
 8,487
 7,792
Total property, plant, and equipment 53,167
 51,208
 57,007
 54,868
Other Property and Investments:        
Nuclear decommissioning trusts, at fair value 1,510
 1,465
 1,572
 1,546
Leveraged leases 680
 665
 751
 743
Miscellaneous property and investments 245
 218
 232
 203
Total other property and investments 2,435
 2,348
 2,555
 2,492
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 1,488
 1,432
 1,533
 1,510
Prepaid pension costs 438
 419
Unamortized debt issuance expense 206
 139
 208
 202
Unamortized loss on reacquired debt 274
 293
 234
 243
Other regulatory assets, deferred 2,624
 2,557
 4,763
 4,334
Income taxes receivable, non-current 444
 
Other deferred charges and assets 764
 551
 832
 904
Total deferred charges and other assets 5,794
 5,391
 8,014
 7,193
Total Assets $67,654
 $64,546
 $74,181
 $70,923
The accompanying notes as they relate to Southern Company are an integral part of these condensedconsolidated financial statements.


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholders' Equity At September 30,
2014
 At December 31,
2013
 At June 30,
2015
 At December 31,
2014
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $2,398
 $469
 $3,643
 $3,333
Interest-bearing refundable deposit 225
 150
Interest-bearing refundable deposits 
 275
Notes payable 361
 1,482
 1,057
 803
Accounts payable 1,381
 1,376
 1,395
 1,593
Customer deposits 386
 380
 398
 390
Accrued taxes —        
Accrued income taxes 238
 13
 12
 151
Other accrued taxes 558
 456
 391
 487
Accrued interest 270
 251
 241
 295
Accrued vacation pay 213
 217
 222
 223
Accrued compensation 423
 303
 305
 576
Other regulatory liabilities, current 84
 92
Mirror CWIP 353
 271
Other current liabilities 353
 347
 677
 570
Total current liabilities 6,890
 5,536
 8,694
 8,967
Long-term Debt 21,699
 21,344
 22,674
 20,841
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 10,817
 10,563
 12,187
 11,568
Deferred credits related to income taxes 191
 202
 186
 192
Accumulated deferred investment tax credits 1,006
 966
 1,290
 1,208
Employee benefit obligations 1,474
 1,461
 2,375
 2,432
Asset retirement obligations 2,133
 2,006
 2,860
 2,168
Other cost of removal obligations 1,341
 1,270
 1,206
 1,215
Other regulatory liabilities, deferred 566
 475
 408
 398
Other deferred credits and liabilities 549
 584
 996
 594
Total deferred credits and other liabilities 18,077
 17,527
 21,508
 19,775
Total Liabilities 46,666
 44,407
 52,876
 49,583
Redeemable Preferred Stock of Subsidiaries 375
 375
 118
 375
Redeemable Noncontrolling Interest 41
 39
Stockholders' Equity:        
Common Stockholders' Equity:        
Common stock, par value $5 per share —        
Authorized — 1.5 billion shares        
Issued — September 30, 2014: 901 million shares    
— December 31, 2013: 893 million shares    
Treasury — September 30, 2014: 0.7 million shares    
— December 31, 2013: 5.7 million shares    
Issued — June 30, 2015: 912 million shares    
— December 31, 2014: 909 million shares    
Treasury — June 30, 2015: 3.3 million shares    
— December 31, 2014: 0.7 million shares    
Par value 4,500
 4,461
 4,555
 4,539
Paid-in capital 5,652
 5,362
 6,123
 5,955
Treasury, at cost (25) (250) (142) (26)
Retained earnings 9,800
 9,510
 9,767
 9,609
Accumulated other comprehensive loss (70) (75) (121) (128)
Total Common Stockholders' Equity 19,857
 19,008
 20,182
 19,949
Preferred and Preference Stock of Subsidiaries 756
 756
 609
 756
Noncontrolling Interest 355
 221
Total Stockholders' Equity 20,613
 19,764
 21,146
 20,926
Total Liabilities and Stockholders' Equity $67,654
 $64,546
 $74,181
 $70,923
The accompanying notes as they relate to Southern Company are an integral part of these condensedconsolidated financial statements.

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Table of Contents
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRDSECOND QUARTER 20142015 vs. THIRDSECOND QUARTER 20132014
AND
YEAR-TO-DATE 20142015 vs. YEAR-TO-DATE 20132014


OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – and Southern Power Company and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business of electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, 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" – Southern Power," and "Other" – Other Businesses" in Item 1 of the Form 10-K.
In addition, subsidiaries of Southern Company are constructingconstruction continues on Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and theMississippi Power's 582-MW Kemper IGCC (in which Mississippi Power is ultimately expected to hold an 85% ownership interest in the 582-MW facility).IGCC. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements herein.
Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects, 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. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding revisions to the cost estimate for the Kemper IGCC that have negatively impacted Southern Company's earnings per share, one of its key performance indicators, for 2014, as compared to the target.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$(134) (15.7) $450 36.6
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$18 2.9 $176 18.3
Southern Company's thirdsecond quarter 20142015 net income after dividends on preferred and preference stock of subsidiaries was $718$629 million ($0.800.69 per share) compared to $852$611 million ($0.970.68 per share) for the thirdsecond quarter 2013.2014. The increase was primarily due to an increase in retail revenues resulting from retail base rate increases and warmer weather in the second quarter 2015 as compared to the corresponding period in 2014, partially offset by the correction of an error affecting billings to certain Georgia Power commercial and industrial customers. Also contributing to the increase were state income tax benefits realized and a decrease in interest expense. The increase in net income was partially offset by increases in non-fuel operations and maintenance expenses and a decrease in AFUDC equity.
Southern Company's year-to-date 2015 net income after dividends on preferred and preference stock of subsidiaries was $1.1 billion ($1.25 per share) compared to $962 million ($1.08 per share) for the corresponding period in 2014. The increase was primarily the result of lower pre-tax charges of $32 million ($20 million after tax) recorded in 2015 compared to a $418 million pre-tax charge of $380 million ($258235 million after tax) recorded in the third quartercorresponding period in 2014 compared to a $150 million pre-tax charge ($93 million after tax) recorded in the third quarter 2013 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, as well as increases in non-fuel operations and maintenance expenses. The decrease was partially offset by an increase in revenues due to retail base rate increases and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.
Southern Company's year-to-date 2014 net income after dividends on preferred and preference stock of subsidiaries was $1.7 billion ($1.88 per share) compared to $1.2 billion ($1.41 per share) for the corresponding period in 2013. The increase was primarily the result of $798 million in pre-tax charges ($493 million after tax) recorded year-to-

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

date 2014 compared to $1.1 billion in pre-tax charges ($704 million after tax) recorded year-to-date 2013 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC. The increase was also related toIGCC, as well as an increase in revenues due to retail base rate increases as well as colder weatherrates. The increase in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013,net income was partially offset by increases in non-fuel operations and maintenance expenses.
Retail Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$239 5.5 $949 8.4
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(56) (1.5) $(372) (4.9)
In the thirdsecond quarter 2014,2015, retail revenues were $4.6$3.7 billion compared to $4.3$3.8 billion for the corresponding period in 2013.2014. For year-to-date 2014,2015, retail revenues were $12.2$7.3 billion compared to $11.2$7.6 billion for the corresponding period in 2013.2014.
Details of the changes in retail revenues were as follows:
 
Third
 Quarter 2014
 
Year-to-Date
 2014
 Second Quarter 2015 Year-to-Date 2015
 (in millions) (% change) (in millions) (% change) (in millions) (% change) (in millions) (% change)
Retail – prior year $4,319
   $11,237
   $3,770
   $7,628
  
Estimated change resulting from –                
Rates and pricing 89
 2.1
 242
 2.1
 30
 0.8
 107
 1.4
Sales growth 9
 0.2
 29
 0.3
 23
 0.6
 41
 0.5
Weather 87
 2.0
 238
 2.1
 46
 1.2
 8
 0.1
Fuel and other cost recovery 54
 1.2
 440
 3.9
 (155) (4.1) (528) (6.9)
Retail – current year $4,558
 5.5% $12,186
 8.4% $3,714
 (1.5)% $7,256
 (4.9)%
Revenues associated with changes in rates and pricing increased in the thirdsecond quarter and year-to-date 20142015 when compared to the corresponding periods in 20132014 primarily due to retailincreased revenues at Alabama Power associated with an increase in rates under rate increases at all of the traditional operating companies. The increases in revenuesstabilization and equalization (Rate RSE) and at Georgia Power were primarily duerelated to base tariff increases effective January 1, 2014, as approved by the Georgia PSC inunder the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, as well as higher contributions from market-driven rates fromall effective January 1, 2015. The increase was partially offset by the correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers. Also contributingcustomers under a rate plan allowing for variable demand-driven pricing at Georgia Power. See Note (A) to the increases were increased revenues at Alabama Power associated with Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assetsCondensed Financial Statements herein and increased revenues at Gulf Power primarily resulting from the retail base rate increase effective January 2014, as approved by the Florida PSC. In addition, the year-to-date 2014 increase also reflects increased revenues at Mississippi Power related to the collection of Kemper IGCC cost recovery revenues, the majority of which were deferred to a regulatory liability, and a PEP base rate increase, which both became effective in March 2013.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power Rate RSE" and "Retail Regulatory Matters Georgia Power Rate Plans," "Retail Regulatory Matters – Alabama Power Rate CNP," and "Retail Regulatory Matters Gulf Power – Retail Base Rate Case"Plans" in Item 8 of the Form 10-K for additional information. Also see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power – Performance Evaluation Plan" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
Revenues attributable to changes in sales increased in the thirdsecond quarter and year-to-date 20142015 when compared to the corresponding periodsperiod in 2013.2014. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales increased 1.2% and 0.7%, respectively, in the second quarter 2015, both as a result of customer growth. Industrial KWH energy sales increased 4.8%0.2% in the thirdsecond quarter and 3.6% for year-to-date 20142015 primarily due to increased sales in the non-manufacturing, transportation, and pipeline sectors, partially offset by decreased sales in the primary metals, chemicals, and paper sectors.
Revenues attributable to changes in sales increased for year-to-date 2015 when compared to the corresponding period in 2014. Industrial KWH sales increased 1.1% for year-to-date 2015 primarily due to increased sales in the non-manufacturing, transportation, pipeline, and stone, clay,petroleum sectors, partially offset by decreased sales in the primary metals and glasschemicals sectors. Weather-adjusted commercial KWH energy sales decreased 1.1% in the third quarter and 0.5%increased 0.7% for year-to-date 20142015 primarily due to decreased customer usage,growth. Weather-adjusted residential KWH sales increased 0.7% for year-to-date 2015 as a result of customer growth, partially offset by decreased customer usage.
In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled second quarter and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without

16

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

customer growth. Weather-adjustedthis adjustment, second quarter 2015 weather-adjusted residential sales increased 1.4%, weather-adjusted commercial sales increased 0.5%, and industrial KWH sales remained relatively flatincreased 0.1% as compared to the corresponding period in 2014. Also, without this adjustment, year-to-date 2015 weather-adjusted residential sales increased 0.6%, weather-adjusted commercial sales increased 0.4%, and industrial KWH sales increased 1.0% as compared to the third quarter and for year-to-date 2014 as a result of customer growth offset by decreased customer usage. Household income, one of the primary drivers of residential customer usage, has been flatcorresponding period in 2014.
Fuel and other cost recovery revenues increased $54decreased $155 million and $528 million in the thirdsecond quarter 2014and year-to-date 2015, respectively, when compared to the corresponding period in 2013 primarily due to increased energy sales as a result of warmer weather in the third quarter 2014 as compared to the corresponding period in 2013. Fuel and other cost recovery revenues increased $440 million for year-to-date 2014 when compared to the corresponding period in 2013 primarily due to higher natural gas prices and increased energy sales as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013.2014 primarily due to a decrease in fuel prices.
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 energy component of purchased power costs, and do not affect net income. The traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPAs.
Wholesale Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$80 15.4 $313 22.3
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(67) (13.0) $(204) (18.2)
Wholesale revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale revenues from PPAs (other than solar PPAs) have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's 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. Wholesale revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the thirdsecond quarter 2014,2015, wholesale revenues were $600$448 million compared to $520$515 million for the corresponding period in 2013 primarily2014 related to an $82a $44 million increase in energy revenues. The increasedecrease in energy revenues was primarily related to new solar PPAs and requirements contracts and increased revenue under existing contracts primarily at Southern Power, as well as an increasea $23 million decrease in KWH sales resulting from utilization of the Southern Company system's lower cost generation.
capacity revenues. For year-to-date 2014,2015, wholesale revenues were $1.7 billion$915 million compared to $1.4$1.1 billion for the corresponding period in 2013, reflecting2014 related to a $303$162 million increasedecrease in energy revenues and a $10$42 million increasedecrease in capacity revenues. The increasedecreases in energy revenues waswere primarily related to increased revenue under existing contracts as well aslower fuel costs, partially offset by increases in energy revenues from new solar PPAs and requirements contracts primarily at Southern Power, increased demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013, and an increase in the average cost of natural gas.Power. The increasedecreases in capacity revenues waswere primarily due to the expiration of wholesale base rate increasescontracts in December 2014 at MississippiGeorgia Power, partially offset by a decrease in capacity revenuesunit retirements at Georgia Power, and PPA expirations at Southern Power.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Electric Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$3 1.8 $26 5.5
For year-to-date 2014, other electric revenues were $503 million compared to $477 million for the corresponding period in 2013. The increase was primarily due to a $19 million increase in open access transmission tariff revenues at Alabama Power and Georgia Power and a $6 million increase in solar application fee revenue at Georgia Power.
Fuel and Purchased Power Expenses
 
Third Quarter 2014
vs.
Third Quarter 2013
 
Year-to-Date 2014
vs.
Year-to-Date 2013
  Second Quarter 2015
vs.
Second Quarter 2014
  Year-to-Date 2015
vs.
Year-to-Date 2014
 (change in millions) (% change) (change in millions) (% change) (change in millions) (% change) (change in millions) (% change)
Fuel $76
 4.8 $549
 13.0 $(262) (17.9) $(697) (22.4)
Purchased power 49
 33.8 147
 40.1 38
 28.6 (5) (1.6)
Total fuel and purchased power expenses $125
 $696
  $(224) $(702) 
In the thirdsecond quarter 2014,2015, total fuel and purchased power expenses were $1.9$1.4 billion compared to $1.7$1.6 billion for the corresponding period in 2013.2014. The increasedecrease was primarily the result of a $139$337 million increase in the volume of KWHs generated primarily due to increased demand resulting from warmer weather in the third quarter 2014 compared to the corresponding period in 2013, a $41 million increase in the average cost of purchased power, and a $16 million increase in the volume of KWHs purchased, partially offset by a $71 million decrease in the average cost of fuel primarily due to lower coal prices.
For year-to-date 2014, total fuel and purchased power expenses were $5.3 billion compared to $4.6 billion for the corresponding period in 2013. The increase was primarily the result of a $439 million increase in the volume of KWHs generated primarily due to increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 compared to the corresponding periods in 2013 and a $298 million increase in the average cost of fuel and purchased power primarily due to higherlower coal and natural gas prices. These increases wereprices, partially offset by a $41$113 million decreaseincrease in the volume of KWHs generated and purchased primarily due to increased demand resulting from warmer weather in the second quarter 2015 as compared to the marginalcorresponding period in 2014.
For year-to-date 2015, total fuel and purchased power expenses were $2.7 billion compared to $3.4 billion for the corresponding period in 2014. The decrease was primarily the result of a $792 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $90 million increase in the Southern Company system's generation available was lower than the market costvolume of available energy.KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "PSC"Retail Regulatory 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 impact net income.
Details of the Southern Company system's generation and purchased power were as follows:
  Second Quarter
2015
 Second Quarter
2014
 Year-to-Date 2015 Year-to-Date 2014
Total generation (billions of KWHs)
 46 47 92 94
Total purchased power (billions of KWHs)
 4 2 6 5
Sources of generation (percent) —
        
Coal 39 44 36 45
Nuclear 15 17 16 16
Gas 42 36 44 35
Hydro 3 3 3 4
Renewables 1  1 
Cost of fuel, generated (cents per net KWH) 
        
Coal 3.37 3.79 3.52 4.00
Nuclear 0.84 0.89 0.75 0.89
Gas 2.76 3.82 2.73 4.00
Average cost of fuel, generated (cents per net KWH)
 2.70 3.28 2.70 3.46
Average cost of purchased power (cents per net KWH)(*)
 5.63 7.41 6.26 8.20
(*)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the Southern Company system's generation and purchased power were as follows:
  Third Quarter
2014
 Third Quarter
2013
 Year-to-Date 2014 Year-to-Date 2013
Total generation (billions of KWHs)
 54 50 147 136
Total purchased power (billions of KWHs)
 3 3 9 10
Sources of generation (percent) —
        
Coal 44 44 45 40
Nuclear 15 16 16 17
Gas 40 37 36 39
Hydro 1 3 3 4
Cost of fuel, generated (cents per net KWH) 
        
Coal 3.63 4.06 3.87 4.08
Nuclear 0.84 0.87 0.87 0.87
Gas 3.42 3.27 3.77 3.30
Average cost of fuel, generated (cents per net KWH)
 3.13 3.24 3.34 3.21
Average cost of purchased power (cents per net KWH)(a)
 6.77 5.66 7.60 5.22
(a)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
Fuel
In the thirdsecond quarter 2014,2015, fuel expense was $1.7$1.2 billion compared to $1.6$1.5 billion for the corresponding period in 2013.2014. The increasedecrease was primarily due to a 68.3%27.8% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall and a 9.9% increase in the volume of KWHs generated by fossil fuel, partially offset by a 10.6% decrease in the average cost of coal per KWH generated.
For year-to-date 2014, fuel expense was $4.8 billion compared to $4.2 billion for the corresponding period in 2013. The increase was primarily due to a 21.6% increase in the volume of KWHs generated by coal, a 14.2% increase in the average cost of natural gas per KWH generated, an 11.1% decrease in the average cost of coal per KWH generated, and a 31.5%10.6% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall.coal, partially offset by a 19.7% increase in the volume of KWHs generated by natural gas.
For year-to-date 2015, fuel expense was $2.4 billion compared to $3.1 billion for the corresponding period in 2014. The decrease was primarily due to a 31.8% decrease in the average cost of natural gas per KWH generated, a 21.2% decrease in the volume of KWHs generated by coal, and a 12.0% decrease in the average cost of coal per KWH generated, partially offset by a 32.3% increase in the volume of KWHs generated by natural gas.
Purchased Power
In the thirdsecond quarter 2014,2015, purchased power expense was $194$171 million compared to $145$133 million for the corresponding period in 2013.2014. The increase was primarily due to a 19.6% increase in the average cost per KWH purchased primarily as a result of higher natural gas prices and an 8.3%50.0% increase in the volume of KWHs purchased primarily as a result of increased demand from warmer weather in the thirdsecond quarter 20142015 as compared to the corresponding period in 2013.2014, partially offset by a 24.0% decrease in the average cost per KWH purchased.
For year-to-date 2014,2015, purchased power expense was $514$315 million compared to $367$320 million for the corresponding period in 2013.2014. The increasedecrease was primarily due to a 45.6% increase23.7% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by an 8.3% decrease18.0% increase in the volume of KWHs purchased as the marginal cost of the Southern Company system's generation available was lower than the market cost of available energy primarily due to higher natural gas prices.purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$93 10.0 $177 6.2
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$81 7.9 $217 10.8
In the thirdsecond quarter 2014,2015, other operations and maintenance expenses were $1.0$1.1 billion compared to $928 million$1.0 billion for the corresponding period in 2013.2014. The increase was primarily due to a $30$32 million increase in transmission and distribution costsgeneration expenses primarily related to overhead linenon-outage operations and maintenance, a $29$23 million increase in scheduled outage and maintenance costs at generation facilities, a $14 million increase in commodity and contract labor costs, a $12 million net increase in employee compensation and benefits including pension costs, and a $6 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs. The increase in scheduled outage and maintenance costs wasprograms, partially offset by a $7 million decrease in transmission and distribution costs primarily related to overhead line maintenance. In addition, in the second quarter 2014, Alabama Power deferred approximately $16 million deferral of certain non-nuclear outage expenditures under an accounting order at Alabama Power.order.
For year-to-date 2014,2015, other operations and maintenance expenses were $3.0$2.2 billion compared to $2.8$2.0 billion for the corresponding period in 2013.2014. The increase was primarily due to an $80a $58 million increase in employee compensation and benefits including pension costs, a $41 million increase in generation expenses primarily related to non-outage operations and maintenance, a $30 million increase in scheduled outage and maintenance costs at generation facilities, and a $53 million increase in transmission and distribution costs primarily related to overhead line maintenance, a $29 million increase in commodity and contract labor costs, a $15 million net increase in employee compensation and benefits including pension costs, a $10$22 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand-sidedemand side management programs, and a $7programs. In addition, in the first half of 2014, Alabama Power deferred approximately $41 million increase in litigation expense. The increase in scheduled outage and maintenance costs was partially offset by a $57 million deferral of certain non-nuclear outage expenditures under an accounting order at Alabama Power.order.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Non-Nuclear Outage Accounting Order" in Item 8 of the Form 10-K for additional information related to non-nuclear outage expenditures. Also see Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
Depreciation and Amortization
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$34 7.1 $93 6.5
In the third quarter 2014, depreciation and amortization was $514 million compared to $480 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $1.5 billion compared to $1.4 billion for the corresponding period in 2013. The increases were primarily due to an increase in plant in service at Southern Power related to the additions of solar facilities in 2013 and 2014 and additional component depreciation at Southern Power as a result of production being greater during the summer months, as well as the completion of amortization of a regulatory liability related to state income tax credits in December 2013 at Georgia Power. Also contributing to the year-to-date increase was an increase in depreciation rates related to environmental assets at Alabama Power. These increases were partially offset by a decrease in depreciation and amortization at Georgia Power, as authorized in the 2013 ARP. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate CNP" of Southern Company in Item 7 of the Form 10-K for additional information regarding Alabama Power's revision to Rate CNP Environmental. Also see Note (A) to the Condensed Financial Statements under "Depreciation" herein for additional information related to component depreciation at Southern Power.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income TaxesDepreciation and Amortization
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$15 6.2 $41 5.8
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(4) (0.8) $(14) (1.4)
In the third quarter 2014, taxes other than income taxes were $258For year-to-date 2015, depreciation and amortization was $987 million compared to $243 million$1.0 billion for the corresponding period in 2013. For year-to-date 2014, taxes2014. The decrease was primarily due to a $49 million reduction in depreciation rates at Alabama Power, a $14 million reduction in depreciation at Gulf Power, as approved by the Florida PSC, and a $9 million reduction in other than income taxes were $751cost of removal at Georgia Power, partially offset by a $49 million compared to $710 million for the corresponding period in 2013. The increases were primarily theincrease as a result of increasesadditional plant in service at the traditional operating companies and Southern Power. See Note 3 to the financial statements of $7 millionSouthern Company under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" in Item 8 of the Form 10-K and $29 million in municipal franchise fees relatedNote (B) to higher retail revenues in 2014 and $5 million and $9 million in payroll taxes primarily related to higher employee benefits in the third quarter and year-to-date 2014, respectively.Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" herein for additional information.
Estimated Loss on Kemper IGCC
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$268 N/M $(342) (30.0)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$23 N/M $(348) (91.6)
N/M – Not meaningful
In the thirdsecond quarter 20142015, an estimated probable loss on the Kemper IGCC of $23 million was recorded at Southern Company. For year-to-date 2015 and 2013,2014, estimated probable losses on the Kemper IGCC of $418$32 million and $150$380 million, respectively, were recorded at Southern Company. For year-to-date 2014 and 2013, estimated probable losses on the Kemper IGCC of $798 million and $1.1 billion, respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). See FUTURE EARNINGS POTENTIAL – "Construction Program"Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$10 18.9 $43 30.9
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(23) (37.1) $(17) (14.3)
In the thirdsecond quarter 2014,2015, AFUDC equity was $63$39 million compared to $53$62 million for the corresponding period in 2013. The increase was primarily related to additional capital expenditures at Alabama Power.
2014. For year-to-date 2014,2015, AFUDC equity was $182$102 million compared to $139$119 million for the corresponding period in 2013.2014. The increase wasdecreases were primarily due to an increase in CWIP related to Mississippi Power'sPower placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and additional capital expenditureslower AFUDC equity at AlabamaGeorgia Power. Additionally, for year-to-date 2015, the decrease in AFUDC equity was partially offset by environmental and transmission projects at the traditional operating companies. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

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Interest Expense, Net of Amounts Capitalized
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$5 2.5 $(5) (0.8)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(30) (14.3) $(23) (5.5)
In the thirdsecond quarter 2014,2015, interest expense, net of amounts capitalized was $207$180 million compared to $202$210 million in the corresponding period in 2013. The increase was primarily due to a $17 million increase related to a higher amount of outstanding long-term debt, partially offset by a $12 million decrease related to the refinancing of long-term debt at lower rates.
2014. For year-to-date 2014,2015, interest expense, net of amounts capitalized was $623$393 million compared to $628$416 million in the corresponding period in 2013.2014. The decrease wasdecreases were primarily due to a $30$41 million decrease related to the refinancingtermination of the asset purchase agreement (APA) between Mississippi Power and SMEPA which required the return of SMEPA's deposits at a lower rate of interest than accrued, partially offset by an increase in outstanding long-term debt at lower rates and a $13 milliondebt. Also contributing to the year-to-date decrease was an increase in capitalized interest partially offset by a $34 million increaseprimarily resulting from AFUDC debt and carrying costs related to a higher amount of outstanding long-term debt and a $7 million increase in interest expense resulting from the deposit received by Mississippi Power in January 2014 related to SMEPA's pending purchase of an undivided interest in the Kemper IGCC. See Note (E) to the Condensed Financial Statements herein for additional information. Also see Note (B) "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
Other Income (Expense), Net
Taxes
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$(2) N/M $11 35.5
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(19) (5.9) $79 15.9
N/M – Not meaningful
For year-to-date 2014, otherIn the second quarter 2015, income (expense), net was $(20)taxes were $302 million compared to $(31)$321 million for the corresponding period in 2013.2014. The decrease in expense wasis primarily due to a $26 million chargestate income tax benefits realized in 2015 and increased federal income tax benefits related to the restructuring of a leveraged lease investmentITCs in the first quarter 2013,2015 at Southern Power, partially offset by a $7 million charge related to a settlement with the Sierra Club at Mississippi Powerdecrease in 2014. See Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.non-taxable AFUDC equity, higher pre-tax earnings, and beneficial changes that impacted 2014 state income taxes.
Income Taxes
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$(76) (16.2) $232 35.3
In the third quarter 2014,For year-to-date 2015, income taxes were $392$576 million compared to $468$497 million for the corresponding period in 2013.2014. The decrease wasincrease primarily due to higherreflects a reduction in tax benefits in 2014 related to the estimated probable losses recorded on Mississippi Power's construction of the Kemper IGCC recorded in 2014, beneficial changes that impacted 2014 state income taxes, and a decrease in non-taxable AFUDC equity, partially offset by higher pre-tax earnings.
For year-to-date 2014, income taxes were $889 million compared to $657 million for the corresponding period in 2013. The increase was primarily due to higherotherwise lower pre-tax earnings and lowerin 2015, state income tax benefits realized in 20142015, and increased federal income tax benefits related to ITCs in 2015 at Southern Power.
See Note (G) to the estimated probable losses recorded on Mississippi Power's construction of the Kemper IGCC.Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system'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 and the

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. AnotherOther major factor isfactors include the profitability of the competitive wholesale business.business and successfully expanding investments in renewable energy projects. Future earnings for the electricity business in the near term will depend, in part, upon maintaining and growing sales which isare subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale business also depends on numerous factors including creditworthiness of customers, total generating capacity available and related costs, future acquisitions and

21

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

construction of generating facilities, including the impact of ITCs, and the successful remarketing of capacity as current contracts expire. Changes in regional and global economic conditions may impact sales for the traditional operating companies and Southern Power as 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 federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis.basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See Note 3 to the financial statements of Southern Company under "Environmental Matters New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations," "PSC"Retail Regulatory Matters Alabama Power Environmental Accounting Order," and "PSC"Retail Regulatory Matters Georgia Power Integrated Resource Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Other Matters Sierra Club Settlement Agreement" in Item 8 of the Form 10-K and "PSC Matters Alabama Power Environmental Accounting Order" and "PSC Matters Georgia Power Integrated Resource Plan" herein for additional information regarding the plans ofon planned unit retirements and fuel conversions at Alabama Power, and Georgia Power, for compliance with environmental statutes and regulations.Mississippi Power.
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, Mississippi, North Carolina, and the EPA's proposed rulesTexas) to revise or remove state implementation plan (SIP) provisions regarding the regulation of excess emissions that occur during periods of startup, shutdown, or malfunction (SSM).
On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR.SSM by no later than November 22, 2016. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama, Florida, Georgia, Mississippi, and North Carolina) to revise their SSM provisions within 18 months after issuance of the final rule. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On June 29, 2015, the U.S. Supreme Court issued a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate outcomeimpact of these mattersthis decision cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, Florida, Georgia, North Carolina, and Texas. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On April 21, 2014,June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a proposedfinal rule to reviserevising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs,CWA programs. The final rule significantly expandingexpands the scope of federal jurisdiction under the CWA. If finalized as proposed,CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, theThe rule as proposed could have significant impacts on economic development projects which could affect customer demand growth.becomes effective August 28, 2015. The ultimate impact of the proposedfinal rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations – Water Quality" Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.regulation of CCR.
On August 15, 2014,April 17, 2015, the EPA published athe Disposal of Coal Combustion Residuals from Electric Utilities final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became(CCR Rule) in the Federal Register, setting October 19, 2015 as the effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementationdate of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units.CCR Rule. The ultimate impact of this rule will depend on the outcome of any legal challenges andCCR Rule cannot be determined at this time.timeand will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Southern Company recorded incremental asset retirement obligations (ARO) of approximately $700 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding these AROs.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.
On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address CO2 emissions from existing fossil fuel-firedfossil-fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO2 emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposed CO2 performance standards for modified and reconstructed fossil fuel-fired electric generating units. The proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, that could impact unit retirement and replacement decisions. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through market-based contracts. Further, any resulting 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.
On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market-based contracts. However, the ultimate financial and operational impact of the Clean Power Plan proposed guidelinesfinal rules on the Southern Company system cannot be determined at this time and will be dependent upondepend on numerous factors. These factors include:including the structure, timing, and contentSouthern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-relatedemissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
FERC Matters
The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On June 23, 2014,April 27, 2015, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit andFERC issued an order finding that the EPA didtraditional operating companies' and Southern Power's existing tailored mitigation may not haveeffectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to tailorshow why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the statutory permitting thresholds.FERC. The ultimate impactoutcome of the U.S. Supreme Court's decisionthis matter cannot be determined at this time.
PSCRetail Regulatory Matters
Retail Fuel Cost Recovery
The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional operating companies continuously monitor their under or over recovered fuel cost balances. At September 30, 2014, Georgia Power Gulf Power, and Mississippi Power had total under recoveredexpects to file its next fuel costs included on Southern Company's Condensed Balance Sheet hereincase in September 2015. The ultimate outcome of approximately $230 million. At December 31, 2013, Gulf Power had under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $21 million. The total over recovered fuel balancethis matter cannot be determined at Alabama Power included on Southern Company's Condensed Balance Sheet herein was approximately $44 million at September 30, 2014 compared to the total over recovered fuel balance at Alabama Power, Georgia Power, and Mississippi Power at December 31, 2013 of approximately $115 million.this time.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Retail Energy Cost Recovery"Rate ECR" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Alabama Power
Environmental Accounting OrderAlabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business

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See SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesOF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

primarily through its Rate RSE, Rate CNP, rate energy cost recovery, and Regulations" and – "PSCnatural disaster reserve rate. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order" of Southern CompanyPower" in Item 78 of the Form 10-K for additional information regarding Alabama Power's planrate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Rate CNP
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism and the normal purchases and normal sales (NPNS) exception for wind PPAs.
On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with environmental statutesthe revised rate now defined as Rate CNP Compliance. Alabama Power incurred $30 million of non-environmental compliance costs during the first six months of 2015 and regulations.will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under recovered position for Rate CNP Compliance during 2015.
AsIn April 2015, the Financial Accounting Standards Board (FASB) proposed new accounting guidance to allow the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power currently accounts for its two wind PPAs. On July 9, 2015, the FASB ratified the consensus reached by the Emerging Issues Task Force to allow the exception in such cases and voted to issue a final accounting standard.
Environmental Accounting Order
In April 2015, as part of its environmental compliance strategy, Alabama Power plans to retireretired Plant Gorgas Units 6 and 7. These units representrepresented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power also plans to ceaseceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally,No later than April 2016, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expectedSubject to be effective no later than April 2016.the final approval of the New Source Review stipulation, Alabama Power will also retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See Note (B) to the Condensed Financial Statements herein for additional information regarding the New Source Review actions.
In accordance with an accounting order from the Alabama PSC, Alabama Power will transfertransferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements.
Renewable Energy
On June 25, 2015, Alabama Power filed a petition with the Alabama PSC for a Renewable Generation Certificate (RGC). The RGC would develop a process that allows Alabama Power to build its own renewable projects each less than 80 MWs or purchase power from other renewable-generated sources up to 500 MWs. The Alabama PSC is expected to rule on this matter in August 2015. The ultimate outcome of this matter cannot be determined at this time.

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Nuclear Waste Fund Accounting OrderGeorgia Power
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K and "Other Matters" herein for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero.
On August 5, 2014, the Alabama PSC issued an order to provide for the continued recoveryGeorgia Power's revenues from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power is authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customersregulated retail operations are collected through various rate mechanisms subject to the approvaloversight of the AlabamaGeorgia PSC.The ultimate outcome of this matter cannot be determined at this time.
Cost of Removal Accounting Order
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power" of Southern Company in Item 7 of the Form 10-K regarding the previously approved compliance and pension costs accounting order and non-nuclear outage accounting order.
On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, projected to be $120 million at December 31, 2014. This amortization expense will be offset by the amortization of up to $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances to be fully amortized as of December 31, 2014 represent costs deferred under the compliance and pension cost accounting order as well as the non-nuclear outage accounting order, which were approved by the Alabama PSC in November 2012 and August 2013, respectively. This accounting order also requires Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order and the non-nuclear outage accounting order. Consequently, Alabama Power will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders.
Georgia Power
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 and Note 3 tocurrently recovers its costs from the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information on Georgia Power's 2013 ARP.
In accordance with the terms ofregulated retail business through the 2013 ARP, on October 3, 2014, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2015 pending its approval:
Increase thewhich includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, by approximately $107 millionEnvironmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to cover additional capacity costs;
Increase the environmental complianceconstruction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariff by approximately $32 million;
Increase the demand-side management tariffs by approximately $3 million; and
Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.
tariffs. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction"Power" in Item 8 of the Form 10-K for additional informationinformation.
Renewables Development
As part of the Georgia Power Advanced Solar Initiative program, Georgia Power executed ten PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. These PPAs are expected to commence in December 2015 and 2016 and have terms ranging from 20 to 30 years. As a result of certain acquisitions by Southern Power, Georgia Power expects that 249 MWs of the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.
On June 15, 2015, Georgia Power executed a PPA to purchase a total of 58 MWs of biomass capacity and energy from a 79-MW facility in Georgia that will begin in 2017 and end in 2047. This PPA was approved by the Georgia PSC on April 15, 2015. Georgia Power also entered into an energy-only PPA for the remaining 21 MWs from the same facility.
On July 21, 2015, the Georgia PSC approved Georgia Power's NCCR tariff. request to build, own, and operate a 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia by the end of 2016.
Integrated Resource Plan
To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) and its decertification will be requested in connection with the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Units 7 and 6 and the units were returned to service on May 4, 2015 and June 27, 2015, respectively.
Gulf Power
Renewables
On October 31, 2014, GeorgiaApril 16, 2015, the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. On May 5, 2015, the Florida PSC approved an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma. Purchases under these agreements will be for energy only and will be recovered through Gulf Power's fuel cost recovery mechanism.
Mississippi Power
2015 Rate Case
On May 15, 2015 and July 10, 2015, Mississippi Power filed alternative rate proposals related to increaserecovery of Kemper IGCC-related costs with the NCCR tariff by approximately $27 million effective JanuaryMississippi PSC. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle Rate Recovery of Kemper IGCC Costs 2015 Rate Case" herein for additional information.

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1,Renewables
In April and May 2015, pending GeorgiaMississippi Power entered into separate PPAs for three solar facilities for a combined total of approximately 105 MWs. Mississippi Power would purchase all of the energy produced by the solar facilities for the 25-year term of the contracts. If approved by the Mississippi PSC, approval. See Note (B)the projects are expected to be in service by the Condensed Financial Statements under "Retail Regulatory Matters Georgia Power Nuclear Construction" herein for additional information.
end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Renewables Development
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Renewables Development" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Renewables Development" in Item 8 of the Form 10-K for additional information.
On May 20, 2014, the Georgia PSC approved Georgia Power's application for the certification of two PPAs executed in April 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.
As a result of biomass PPA amendments executed by Georgia Power during 2014, total estimated purchased power contractual obligations decreased $392 million from December 31, 2013. Estimated purchased power contractual obligations have been updated for Southern Company to $669million for 2015 and 2016, $757 million for 2017 and 2018, and $3.9 billion after 2018. Estimated purchased power contractual obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations – Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for additional information.
On October 8, 2014, Georgia Power executed PPAs to purchase energy from 515 MWs of solar capacity as part of the Georgia Power Advanced Solar Initiative program. These PPAs are expected to commence in 2015 and 2016, have terms ranging from 20 to 30 years, and are subject to Georgia PSC approval.
On October 23, 2014, the Georgia PSC approved Georgia Power's request to build, own, and operate three 30-MW solar generation facilities at three U.S. Army bases by the end of 2016. In addition, Georgia Power has entered into a memorandum of understanding with the U.S. Navy to pursue a similar solar project pending Georgia PSC review.
The ultimate outcome of these matters cannot be determined at this time.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Integrated Resource Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information.
Georgia Power filed a request with the Georgia PSC on January 10, 2014 to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan in 2016. Georgia Power plans to continue to operate the unit as needed until the Mercury and Air Toxics Standards rule becomes effective in April 2015.
Storm Damage Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Storm Damage Recovery" of Southern Company in Item 7 of the Form 10-K for additional information.
Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage

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was $105 million and $37 million, respectively. The increase was primarily the result of an ice storm in February 2014. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Southern Company's financial statements.
Income Tax Matters
See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information about the Kemper IGCC. The ultimate outcome of these tax matters cannot be determined at this time.
Bonus Depreciation
In January 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which will apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million.
Investment Tax Credits
The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through September 30, 2014, Southern Company had recorded tax benefits totaling $276.4 million for the Phase II credits, of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's purchase of an undivided interest in the Kemper IGCC.
Section 174 Research and Experimental Deduction
For the 2013 tax year, Southern Company included in its consolidated federal income tax return a deduction for research and experimental (R&E) expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Southern Company recorded an unrecognized tax benefit of approximately $100 million as of September 30, 2014. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits" herein for additional information.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new generating facilities, as well as adding or changing fuel sources for certain existing units, 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 approvalsapproval 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.
The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and theMississippi Power's 582-MW Kemper IGCC (in which Mississippi Power is ultimately expected to hold an 85% ownership interest).IGCC. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for the cost estimate of the Southern Company system's construction program, which includes the revised construction cost estimate to complete the Kemper IGCC. Also see Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined

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Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters Georgia Power Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of solarrenewable energy facilities, see Note (I) to the Condensed Financial Statements herein.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Integrated Coal Gasification Combined Cycle
From 2013 through SeptemberJune 30, 2014,2015, Southern Company has recorded pre-tax charges totaling $1.98$2.08 billion ($1.221.28 billion after tax) for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.
On February 12, 2015, the Mississippi Supreme Court issued its decision in a legal challenge with respect to the Mississippi PSC's March 2013 order that authorized Mississippi Power's collection of $156 million annually to be recorded as Mirror CWIP. Among other things, the Mississippi Supreme Court reversed this order and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts collected. As of June 30, 2015, $331 million had been collected by Mississippi Power. The Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015.
On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.

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The return of approximately $301 million to SMEPA in June 2015 in connection with the termination of the APA, the required refund of the approximately $353 million of Mirror CWIP rate collections, including associated carrying costs, and the termination of the Mirror CWIP rates have adversely impacted Mississippi Power's ability to obtain financing needed for its business operations. As a result, on July 10, 2015, Mississippi Power submitted a request for interim rates designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. These interim rates are designed to collect approximately $159 million annually. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015. The ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).
While Georgia Power has not agreed to any change to the guaranteed substantial completion dates (April 2016 for Unit 3 and April 2017 for Unit 4) included in the engineering, procurement, and construction agreement relating to Plant Vogtle Units 3 and 4, Georgia Power's twelfth Vogtle Construction Monitoring (VCM) report, filed February 27, 2015, included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month Contractor delay, and to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $5.0 billion. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3. The Georgia PSC recognized that the certified cost does not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.
Additionally, there are certain risks associated with the construction program in general and certain risks associated with the licensing, construction, and operation of nuclear generating units in particular, 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.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K for additional information.
Section 174 Research and Experimental Deduction
Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Southern Company under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Benefits Section 174 Research and Experimental Deduction," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has increased generallyoccurred throughout the U.S. In particular, personal injury, property damage, and otherThis litigation has included claims for damages alleged to have been caused by CO2 and other emissions, coal combustion residuals,CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.matters.
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 in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See the NotesNote (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011.
Additionally, there are 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.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On June 17, 2014, the Georgia PSC approved Georgia Power's request to credit customers the portion of fuel cost related to the nuclear waste fund fee. The nuclear waste fund rider became effective July 1, 2014. See "PSC Matters – Alabama Power – Nuclear Waste Fund Accounting Order" herein for information regarding an accounting order issued by the Alabama PSC which provides for continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. The ultimate outcome of this matter cannot be determined at this time.

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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, and Pension and Other Postretirement Benefits.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2014,2015, Mississippi Power further extended the scheduled in-service date for the Kemper IGCC to the first half of 2016 and revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery or any joint owner contributions for any costs related coststo the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.
As a result of the revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $418.0$23 million ($258.114 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380.0$380 million ($234.7235 million after tax) in the first quarter 2014, $40.0$40 million ($24.725 million after tax) in the fourth quarter 2013, $150.0$150 million ($92.693 million after tax) in the third quarter 2013, $450.0$450 million ($277.9278 million after tax) in the second quarter 2013, and $540.0$540 million ($333.5333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $1.98$2.08 billion ($1.221.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through SeptemberJune 30, 2014.2015.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions will be reflected in Southern Company's statements of income and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations.operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $20$25 million to $30 million per month, whichwhich includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.
Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of the nuclear facilities - Alabama Power's Plant Farley and Georgia Power's ownership interests in Plants Hatch and Vogtle - and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based

30

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates. Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Recently Issued Accounting Standards
On May 28, 2014, the Financial Accounting Standards Board issuedThe FASB's ASC 606, Revenue from Contracts with Customers. ASC 606, revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016.2017. Southern Company is currently evaluatingcontinues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Company.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Although earnings for the nine months ended September 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC, Southern Company's financial condition remained stable at SeptemberJune 30, 2014.2015. Through SeptemberJune 30, 2014,2015, Southern Company has incurred non-recoverable cash expenditures of $1.18$1.62 billion and is expected to incur approximately $0.8$0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangementsagreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $4.7$2.1 billion for the first ninesix months of 2014,2015, an increase of $276$37 million from the corresponding period in 2013.2014. The increase in net cash provided from operating activities was primarily due to an increase in revenue due to rate increases and the effects of weather and a reduction in fossil fuel stock resulting from an increase in KWH generation,cost recovery, partially offset by a decrease in receivables due to under recovered fuel costs.timing of accounts payable. Net cash used for investing activities totaled $4.2$2.8 billion for the first ninesix months of 20142015 primarily due to gross property additions for installation of equipment to utility plant.comply with environmental standards, construction of generation, transmission, and distribution facilities, and acquisitions of solar facilities. Net cash provided from financing activities totaled $225$762 million for the first ninesix months of 2014.2015. This was primarily due to issuances of long-term debt, and common stock, partially offset by common stock dividend payments and a reduction in short-term debt.redemptions of long-term debt and preferred and preference stock. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20142015 include an increase of $2.0$2.1 billion in total property, plant, and equipment forto comply with environmental standards and construction of generation, transmission, and distribution facilities, a $444 million increase in income taxes receivable, non-current associated with federal income tax benefits for deductions primarily related to R&E expenditures for the Kemper IGCC, and an increase of $755$406 million in cash and cash equivalents.accounts receivable primarily related to increases in customer billings as compared to

31

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

December 31, 2014. Other significant changes include a $1.2$2.1 billion increase in short-term and long-term debt to fund the Southern Company subsidiaries' continuous construction programs and for other general corporate purposes, and an $849a $692 million increase in total stockholders' equity.AROs primarily related to the CCR Rule, and a $619 million increase in accumulated deferred income taxes for deductions primarily related to R&E expenditures for the Kemper IGCC. See Notes (A), (B), and (G) to the Condensed Financial Statements herein for additional information regarding AROs, the Kemper IGCC, and R&E expenditures, respectively.
At the end of the thirdsecond quarter 2014,2015, the market price of Southern Company's common stock was $43.65$41.90 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.07$22.22 per share, representing a market-to-book ratio of 198%189%, compared to $41.11, $21.43,$49.11, $21.98, and 192%223%, respectively, at the end of 2013.2014. Southern Company's common stock dividend for the thirdsecond quarter 20142015 was $0.5250$0.5425 per share compared to $0.5075$0.5250 per share in the thirdsecond quarter 2013.2014.
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 the Southern Company system, including estimated capital expenditures for new generating facilities and to comply with existing environmental statutes and regulations, 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 $2.4$3.7 billion will be required through SeptemberJune 30, 20152016 to fund maturities and announced redemptions of long-term debt. See FUTURE EARNINGS POTENTIAL "PSC Matters Georgia Power

31

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Renewables Development"Capital" herein for additional information regarding estimated purchased power contractual obligations.
The Southern Company system's construction program is currently estimated to be $7.2 billion for 2014, $5.8 billion for 2015, and $4.4 billion for 2016, which includes expenditures related to construction and start-up of the Kemper IGCC of $1.3 billion for 2014, $551 million for 2015, and $75 million for 2016 and expenditures related to Southern Power's acquisition of a solar facility of $508 million for 2014. The amounts related to the construction and start-up of the Kemper IGCC exclude SMEPA's proposed acquisition of a 15% ownership share of the Kemper IGCC for approximately $569 million (including construction costs for all prior periods relating to its proposed ownership interest). The Southern Company system's amounts include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements.
Southern Company anticipates that the Southern Company system's capital expenditure requirements will continue to decline through the middle of the decade, before rising again to meet additional requirements for environmental compliance and new generation.information.
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; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in the expected environmental compliance program; 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. Additionally, planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.
Sources of Capital
Southern Company intends to meet its future capital needs through internaloperating cash flow,flows, short-term debt, term loans, 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 any additional equity capital and debt to be raised in 2014,2015, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements.
Except as described herein, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
On February 20, 2014, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement), pursuant to which the DOE agreed to guarantee borrowings to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and also are secured by a first priority lien on (i) Georgia Power's 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit

32

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Facility,In addition, Georgia Power may make term loan borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the FFB. ProceedsDOE, the proceeds of borrowings made under the FFB Credit Facility willwhich may be used to reimburse Georgia Power for a portionEligible Project Costs incurred in connection with its construction of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under4. Under the Loan Guarantee Agreement, (Eligiblethe DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs). Aggregate to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through June 30, 2015 would allow for borrowings of up to $2.2 billion under the FFB Credit Facility, may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46which Georgia Power has borrowed $1.8 billion. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Eligible Project Costs incurred through September 30, 2014 would allow for borrowings of up to $2.0 billion under the FFB Credit Facility. Through September 30, 2014, Georgia Power has borrowed $1.0 billion under the FFB Credit Facility, leaving $1.0 billion of available borrowing ability.
Mississippi Power has received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
As of June 30, 2015, Southern Company's current liabilities frequently exceedexceeded current assets by $2.1 billion, primarily due to long-term debt that is due within one year as well as cash needs, which can fluctuate significantly due to the seasonality of the business of the$3.6 billion, including approximately $0.4 billion at Southern Company, system.$0.6 billion at Alabama Power, $1.7 billion at Georgia Power, $0.4 billion at Mississippi Power, and $0.5 billion at Southern Power. In addition, Mississippi Power has $0.5 billion in short-term bank loans scheduled to mature on April 1, 2016. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets includingand financial institutions. Southern Company, the traditional operating companies, and Southern Power intend to utilize operating cash flows, as well as commercial paper, programs which are backedlines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional operating companies and Southern Power, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, for the remainder of 2015, Georgia Power expects to utilize borrowings through the FFB Credit Facility as its primary source of long-term borrowed funds.
The financial condition of Mississippi Power was adversely affected by bankthe return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC. Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows and lines of credit facilities.(to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

33

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At SeptemberJune 30, 2014,2015, Southern Company and its subsidiaries had approximately $1.4$0.8 billion of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20142015 were as follows:
 Expires   
Executable Term
Loans
 
Due Within One
Year
 Expires   
Executable Term
Loans
 
Due Within One
Year
Company 2014 2015 2016 2017 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
 2015 2016 2017 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
 (in millions) (in millions) (in millions) (in millions) (in millions) (in millions) (in millions) (in millions)
Southern Company $
 $
 $
 $
 $1,000
 $1,000
 $1,000
 $
 $
 $
 $
 $
 $
 $
 $1,000
 $1,000
 $1,000
 $
 $
 $
 $
Alabama Power 70
 158
 50
 
 1,030
 1,308
 1,308
 58
 
 58
 170
 154
 124
 
 1,030
 1,308
 1,307
 58
 
 58
 170
Georgia Power 
 
 150
 
 1,600
 1,750
 1,736
 
 
 
 
 
 150
 
 1,600
 1,750
 1,737
 
 
 
 150
Gulf Power 20
 60
 165
 30
 
 275
 275
 50
 
 50
 30
 20
 225
 30
 
 275
 275
 50
 
 50
 195
Mississippi Power 15
 120
 165
 
 
 300
 300
 25
 40
 65
 70
 40
 255
 
 
 295
 265
 30
 40
 70
 225
Southern Power 
 
 
 
 500
 500
 499
 
 
 
 
 
 
 
 500
 500
 466
 
 
 
 
Other 
 70
 
 
 
 70
 70
 20
 
 20
 50
 25
 45
 
 
 70
 70
 20
 
 20
 50
Total $105
 $408
 $530
 $30
 $4,130
 $5,203
 $5,188
 $153
 $40
 $193
 $320
 $239
 $799
 $30
 $4,130
 $5,198
 $5,120
 $158
 $40
 $198
 $790
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.
A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies' variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20142015 was approximately $1.8$1.9 billion. In addition, at SeptemberJune 30, 2014,2015, the traditional operating companies had $423$368 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketedreoffered within the next 12 months.
Southern Company and its subsidiaries expect to renew their bank credit arrangements as needed, prior to expiration.

33

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Southern Company, the traditional operating companies, and Southern Power are currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements, as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.

34

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:
 
Short-term Debt at
September 30, 2014
 
Short-term Debt During the Period(a)
 
Short-term Debt at
June 30, 2015
 
Short-term Debt During the Period(*)
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 (in millions)   (in millions)   (in millions) (in millions)   (in millions)   (in millions)
Commercial paper $361
 0.3% $848
 0.2% $1,528
 $512
 0.3% $1,155
 0.3% $1,563
Short-term bank debt 
  150
 0.8% 250
 545
 1.3% 717
 1.2% 795
Total $361
 0.3% $998
 0.3%   $1,057
 0.7% $1,872
 0.7%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.
(a)    Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2014.
ManagementSouthern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank notes, and cash.operating cash flows.
Credit Rating Risk
Southern Company and its subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain 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, energy price risk management, interest rate derivatives, and construction of new generation at Georgia Power's Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20142015 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and Baa2$9
$9
At BBB- and/or Baa3454
488
Below BBB- and/or Baa32,289
2,407
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.
On June 5, 2015, Fitch downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power and revised the ratings outlook for Southern Company from stable to negative.
Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies on CreditWatch with negative implications.
Financing Activities
During the first six months of 2015, Southern Company issued approximately 3.2 million shares of common stock primarily through the employee equity compensation plan and received proceeds of approximately $116 million. Southern Company is not currently issuing shares of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by independent plan administrators.

3435

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities
During the first nine months of 2014,On March 2, 2015, Southern Company issued approximately 7.8announced a program to repurchase up to 20 million shares of Southern Company common stock for approximately $295.5 million throughto offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock plans,option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through June 30, 2015 at a total cost of which 150,000 shares relatedapproximately $115 million. Pursuant to Southern Company's performance share plan.
Since August 2013,board approval, Southern Company has usedmay repurchase shares heldthrough open market purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in treasury, to the extent available, to satisfy the requirements under the Southern Investment Plan and the employee savings plan and during the first nine months of 2014, issued approximately 5.0 million treasury shares for approximately $215.5 million. Beginning in June 2014, Southern Company used newly issued shares, as necessary, to satisfy the requirements.accordance with applicable securities laws.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first ninesix months of 2014:2015:
Company(a)
Senior
Note Issuances
 
Senior
Note Maturities
 
Revenue
Bond
Issuances and
Remarketings
of Purchased
Bonds(a)
 
Revenue
Bond
Redemptions
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt
Redemptions(b)
Senior
Note Issuances
 
Senior
Note Redemptions
 
Revenue
Bond
Issuances and
Reofferings
of Purchased
Bonds(b)
 
Revenue
Bond
Maturities and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt Redemptions
and
Maturities(c)
(in millions)(in millions)
Southern Company$750
 $350
 $
 $
 $
 $
$600
 $
 $
 $
 $
 $
Alabama Power400
 
 
 
 
 
975
 250
 80
 134
 
 
Georgia Power
 
 40
 37
 1,000
 4

 125
 170
 65
 600
 5
Gulf Power200
 
 42
 29
 
 
Mississippi Power
 
 
 
 493
 222

 
 
 
 
 351
Southern Power
 
 
 
 10
 1
650
 
 
 
 
 
Other
 
 
 
 
 15

 
 
 
 
 9
Elimination(c)

 
 
 
 (220) (220)
Total$1,350
 $350
 $82
 $66
 $1,283
 $22
$2,225
 $375
 $250
 $199
 $600
 $365
(a)Includes remarketing by Gulf Power did not issue or redeem any long-term debt during the first six months of $132015.
(b)Includes reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds previously purchased and held by GulfAlabama Power since December 2013April 2015 and remarketingreofferings by Georgia Power of $40$104.6 million and $65 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2010.2013 and April 2015, respectively.
(b)(c)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
(c)Intercompany loan from Southern Company to Mississippi Power eliminated in Southern Company's Condensed Consolidated Financial Statements. This loan was repaid on September 29, 2014.
In August 2014,June 2015, Southern Company issued $400$600 million aggregate principal amount of Series 2014A 1.30%2015A 2.750% Senior Notes due AugustJune 15, 2017 and $350 million aggregate principal amount of Series 2014B 2.15% Senior Notes due September 1, 2019.2020. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.
Southern Company's subsidiaries used the proceeds of the debt issuancesissuance shown in the table above for their respective redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their respective continuous construction programs.programs and, for Southern Power, its growth strategy.
In addition to the amountsAlabama Power's "Senior Note Issuances" reflected in the table above includes issuances in June 2014, Southern Company entered into a 90-day floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was forApril 2015 of $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used to redeem in May 2015 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for working capital and other general corporate purposes, including the investment by Southern Company in its subsidiaries. This bank loan was repaid in August 2014.
In addition to the amounts reflected in the table above, in January 2014 and subsequent to September 30, 2014, Mississippi Power received an additional $75 million and $50 million, respectively, of interest-bearing refundableAlabama Power's continuous construction program.

3536

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" for additional information.
Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion$600 million in February 2014.June 2015. The interest rate applicable to $500the $600 million of the initial advance under the FFB Credit Facilityprincipal amount is 3.860%3.283% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029 and is expected to be reset from time to time thereafter through 2044. The final maturity date for all advances under the FFB Credit Facility isof February 20, 2044. The proceeds of the initial borrowings under the FFB Credit Facility were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costssettled $350 million of interest rate swaps related to this borrowing for approximately $66$6 million, which will be amortized to interest expense over the life of the borrowings under the FFB Credit Facility.10 years.
Under the Loan Guarantee Agreement,In March 2015, Georgia Power is subject to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of Georgia Power or Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. See Note 6 to the financial statements of Southern Company in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.
In February 2014, Georgia Power repaid three four-monthentered into a $250 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes and the loan was repaid at maturity.
In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $400 million.$275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In June 2015, Gulf Power entered into a three-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $40 million aggregate principal amount and the proceeds were used for credit support, working capital, and other general corporate purposes.
In addition to the amounts reflected in the table above, Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month floating rate promissory note to Southern Company in an aggregate principal amount of approximately $301 million bearing interest based on one-month LIBOR. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
Subsequent to SeptemberJune 30, 2014, Gulf Power's $752015, Southern Power Company repaid at maturity $525 million aggregate principal amount of Series K 4.90%its 4.875% Senior Notes was paid at maturity.on July 15, 2015.
SubsequentAlso subsequent to SeptemberJune 30, 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional2015, $97.925 million aggregate principal amount of the swaps totaled $100 million.Development Authority of Putnam County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Branch Project), First Series 1996, First Series 1997, Second Series 1997, and First Series 1998 were redeemed.
SubsequentAlso subsequent to June 30, 2015, Gulf Power announced the redemption in September 30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional2015 of $60 million aggregate principal amount of the swaps totaled $900 million.its Series L 5.65% Senior Notes due September 1, 2035.
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.

3637



PART I
Item 3. Quantitative Andand Qualitative Disclosures About Market Risk.
During the ninesix months ended SeptemberJune 30, 2014,2015, there were no material changes to each registrant's disclosures about market risk. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K 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 Company 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 Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the thirdsecond quarter 20142015 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 Company's internal control over financial reporting.

3738



ALABAMA POWER COMPANY

3839



ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
2014 2013 2014 20132015 2014 2015 2014
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$1,512
 $1,438
 $4,058
 $3,800
$1,326
 $1,249
 $2,594
 $2,546
Wholesale revenues, non-affiliates72
 66
 222
 186
57
 65
 123
 150
Wholesale revenues, affiliates31
 47
 168
 163
20
 68
 35
 137
Other revenues54
 53
 166
 155
52
 55
 104
 112
Total operating revenues1,669
 1,604
 4,614
 4,304
1,455
 1,437
 2,856
 2,945
Operating Expenses:              
Fuel442
 467
 1,288
 1,240
343
 414
 653
 846
Purchased power, non-affiliates57
 36
 153
 84
45
 39
 86
 96
Purchased power, affiliates54
 30
 140
 102
49
 37
 103
 86
Other operations and maintenance334
 316
 989
 965
370
 330
 768
 655
Depreciation and amortization174
 170
 521
 487
160
 172
 318
 347
Taxes other than income taxes88
 85
 265
 262
90
 88
 184
 177
Total operating expenses1,149
 1,104
 3,356
 3,140
1,057
 1,080
 2,112
 2,207
Operating Income520
 500
 1,258
 1,164
398
 357
 744
 738
Other Income and (Expense):              
Allowance for equity funds used during construction15
 7
 36
 23
14
 11
 29
 21
Interest expense, net of amounts capitalized(63) (65) (188) (196)(69) (63) (134) (125)
Other income (expense), net3
 
 (5) 1
(14) (3) (18) (8)
Total other income and (expense)(45) (58) (157) (172)(69) (55) (123) (112)
Earnings Before Income Taxes475
 442
 1,101
 992
329
 302
 621
 626
Income taxes183
 174
 429
 390
122
 119
 235
 246
Net Income292
 268
 672
 602
207
 183
 386
 380
Dividends on Preferred and Preference Stock10
 10
 30
 30
7
 10
 17
 20
Net Income After Dividends on Preferred and Preference Stock$282
 $258
 $642
 $572
$200
 $173
 $369
 $360

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
 2014 2013 2014 2013
 (in millions) (in millions)
Net Income$292
 $268
 $672
 $602
Other comprehensive income (loss):       
Qualifying hedges:       
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $1 and $1, respectively
 
 1
 1
Total other comprehensive income (loss)
 
 1
 1
Comprehensive Income$292
 $268
 $673
 $603
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

39



ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2014 2013
 (in millions)
Operating Activities:   
Net income$672
 $602
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total631
 616
Deferred income taxes68
 200
Allowance for equity funds used during construction(36) (23)
Regulatory deferrals(62) (14)
Other, net29
 15
Changes in certain current assets and liabilities —   
-Receivables(139) (98)
-Fossil fuel stock106
 173
-Materials and supplies(8) 16
-Other current assets(32) (18)
-Accounts payable(64) (109)
-Accrued taxes210
 105
-Accrued compensation18
 (36)
-Retail fuel cost over recovery2
 42
-Other current liabilities3
 (2)
Net cash provided from operating activities1,398
 1,469
Investing Activities:   
Property additions(966) (779)
Nuclear decommissioning trust fund purchases(178) (162)
Nuclear decommissioning trust fund sales178
 162
Cost of removal, net of salvage(50) (29)
Change in construction payables39
 12
Other investing activities(26) 35
Net cash used for investing activities(1,003) (761)
Financing Activities:   
Proceeds —   
Senior note issuances400
 
Capital contributions from parent company20
 18
Payment of preferred and preference stock dividends(30) (30)
Payment of common stock dividends(412) (397)
Other financing activities(6) 
Net cash used for financing activities(28) (409)
Net Change in Cash and Cash Equivalents367
 299
Cash and Cash Equivalents at Beginning of Period295
 137
Cash and Cash Equivalents at End of Period$662
 $436
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $13 and $8 capitalized for 2014 and 2013, respectively)$174
 $182
Income taxes, net227
 154
Noncash transactions — accrued property additions at end of period57
 43
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Net Income$207
 $183
 $386
 $380
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of $3, $-, $- and $-, respectively5
 
 1
 
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $-, respectively

 
 1
 1
Total other comprehensive income (loss)5
 
 2
 1
Comprehensive Income$212
 $183
 $388
 $381
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

40



ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
 
Assets At September 30,
2014
 At December 31,
2013
  (in millions)
Current Assets:    
Cash and cash equivalents $662
 $295
Receivables —    
Customer accounts receivable 442
 341
Unbilled revenues 133
 142
Under recovered regulatory clause revenues 34
 
Other accounts and notes receivable 38
 30
Affiliated companies 36
 54
Accumulated provision for uncollectible accounts (9) (8)
Fossil fuel stock, at average cost 223
 329
Materials and supplies, at average cost 397
 375
Vacation pay 63
 63
Prepaid expenses 83
 57
Other regulatory assets, current 8
 7
Other current assets 9
 6
Total current assets 2,119
 1,691
Property, Plant, and Equipment:    
In service 22,688
 22,092
Less accumulated provision for depreciation 8,430
 8,114
Plant in service, net of depreciation 14,258
 13,978
Nuclear fuel, at amortized cost 324
 332
Construction work in progress 995
 748
Total property, plant, and equipment 15,577
 15,058
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 67
 54
Nuclear decommissioning trusts, at fair value 738
 714
Miscellaneous property and investments 83
 80
Total other property and investments 888
 848
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 528
 519
Prepaid pension costs 290
 276
Deferred under recovered regulatory clause revenues 46
 25
Other regulatory assets, deferred 703
 692
Other deferred charges and assets 142
 142
Total deferred charges and other assets 1,709
 1,654
Total Assets $20,293
 $19,251
 For the Six Months
Ended June 30,
 2015 2014
 (in millions)
Operating Activities:   
Net income$386
 $380
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total387
 416
Deferred income taxes60
 49
Allowance for equity funds used during construction(29) (21)
Other, net(23) (40)
Changes in certain current assets and liabilities —   
-Receivables(115) (120)
-Fossil fuel stock19
 94
-Materials and supplies3
 (2)
-Other current assets(55) (57)
-Accounts payable(212) (94)
-Accrued taxes177
 104
-Accrued compensation(66) (17)
-Retail fuel cost over recovery25
 (23)
-Other current liabilities40
 5
Net cash provided from operating activities597
 674
Investing Activities:   
Property additions(612) (637)
Nuclear decommissioning trust fund purchases(278) (121)
Nuclear decommissioning trust fund sales278
 121
Cost of removal, net of salvage(28) (30)
Change in construction payables28
 71
Other investing activities(14) (13)
Net cash used for investing activities(626) (609)
Financing Activities:   
Increase in notes payable, net
 27
Proceeds —   
Senior notes issuances975
 
Capital contributions from parent company10
 12
Pollution control revenue bonds80
 
Redemptions and repurchases —   
Preferred and preference stock(412) 
Pollution control revenue bonds(134) 
Senior notes(250) 
Payment of preferred and preference stock dividends(22) (20)
Payment of common stock dividends(286) (275)
Other financing activities(10) 1
Net cash used for financing activities(49) (255)
Net Change in Cash and Cash Equivalents(78) (190)
Cash and Cash Equivalents at Beginning of Period273
 295
Cash and Cash Equivalents at End of Period$195
 $105
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $10 and $8 capitalized for 2015 and 2014, respectively)$118
 $114
Income taxes, net47
 141
Noncash transactions — Accrued property additions at end of period35
 89
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.


41



ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity At September 30,
2014
 At December 31,
2013
  (in millions)
Current Liabilities:    
Securities due within one year $54
 $
Accounts payable —    
Affiliated 245
 198
Other 273
 339
Customer deposits 86
 85
Accrued taxes —    
Accrued income taxes 146
 11
Other accrued taxes 114
 33
Accrued interest 62
 61
Accrued vacation pay 53
 53
Accrued compensation 98
 74
Other regulatory liabilities, current 49
 37
Other current liabilities 44
 41
Total current liabilities 1,224
 932
Long-term Debt 6,577
 6,233
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 3,670
 3,603
Deferred credits related to income taxes 72
 75
Accumulated deferred investment tax credits 127
 133
Employee benefit obligations 203
 195
Asset retirement obligations 813
 730
Other cost of removal obligations 864
 828
Other regulatory liabilities, deferred 242
 259
Deferred over recovered regulatory clause revenues 
 15
Other deferred credits and liabilities 54
 61
Total deferred credits and other liabilities 6,045
 5,899
Total Liabilities 13,846
 13,064
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 2,292
 2,262
Retained earnings 2,273
 2,044
Accumulated other comprehensive loss (25) (26)
Total common stockholder's equity 5,762
 5,502
Total Liabilities and Stockholder's Equity $20,293
 $19,251
Assets At June 30,
2015
 At December 31,
2014
  (in millions)
Current Assets:    
Cash and cash equivalents $195
 $273
Receivables —    
Customer accounts receivable 393
 345
Unbilled revenues 170
 138
Under recovered regulatory clause revenues 28
 74
Other accounts and notes receivable 31
 23
Affiliated companies 41
 37
Accumulated provision for uncollectible accounts (9) (9)
Fossil fuel stock, at average cost 249
 268
Materials and supplies, at average cost 415
 406
Vacation pay 65
 65
Prepaid expenses 168
 244
Other regulatory assets, current 115
 84
Other current assets 10
 5
Total current assets 1,871
 1,953
Property, Plant, and Equipment:    
In service 23,812
 23,080
Less accumulated provision for depreciation 8,565
 8,522
Plant in service, net of depreciation 15,247
 14,558
Nuclear fuel, at amortized cost 338
 348
Construction work in progress 1,017
 1,006
Total property, plant, and equipment 16,602
 15,912
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 68
 66
Nuclear decommissioning trusts, at fair value 758
 756
Miscellaneous property and investments 88
 84
Total other property and investments 914
 906
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 526
 525
Deferred under recovered regulatory clause revenues 97
 31
Other regulatory assets, deferred 1,054
 1,063
Other deferred charges and assets 156
 162
Total deferred charges and other assets 1,833
 1,781
Total Assets $21,220
 $20,552
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.


42



ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity At June 30,
2015
 At December 31,
2014
  (in millions)
Current Liabilities:    
Securities due within one year $600
 $454
Accounts payable —    
Affiliated 244
 248
Other 267
 443
Customer deposits 88
 87
Accrued taxes —    
Accrued income taxes 3
 2
Other accrued taxes 88
 37
Accrued interest 75
 66
Accrued vacation pay 54
 54
Accrued compensation 66
 131
Other current liabilities 105
 82
Total current liabilities 1,590
 1,604
Long-term Debt 6,699
 6,176
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 3,937
 3,874
Deferred credits related to income taxes 71
 72
Accumulated deferred investment tax credits 121
 125
Employee benefit obligations 308
 326
Asset retirement obligations 1,252
 829
Other cost of removal obligations 742
 744
Other regulatory liabilities, deferred 219
 239
Deferred over recovered regulatory clause revenues 72
 47
Other deferred credits and liabilities 79
 79
Total deferred credits and other liabilities 6,801
 6,335
Total Liabilities 15,090
 14,115
Redeemable Preferred Stock 85
 342
Preference Stock 196
 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 2,324
 2,304
Retained earnings 2,331
 2,255
Accumulated other comprehensive loss (28) (29)
Total common stockholder's equity 5,849
 5,752
Total Liabilities and Stockholder's Equity $21,220
 $20,552
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

4243

ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



THIRDSECOND QUARTER 20142015 vs. THIRDSECOND QUARTER 20132014
AND
YEAR-TO-DATE 20142015 vs. YEAR-TO-DATE 20132014


OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located within the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama 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 costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Alabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2014 vs. Third Quarter 2013
Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change)
(change in millions)
(% change)
$24 9.3 $70 12.2
Second Quarter 2015 vs. Second Quarter 2014
Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change)
(change in millions)
(% change)
$27 15.6 $9 2.5
Alabama Power's net income after dividends on preferred and preference stock for the thirdsecond quarter 20142015 was $282$200 million compared to $258$173 million for the corresponding period in 2013.2014. The increase in net income was primarily related to an increase in revenue primarily due torates under rate stabilization and equalization (Rate RSE) effective January 1, 2015, warmer weather in the thirdsecond quarter 2014 as2015 compared to the corresponding period in 20132014, and a decrease in depreciation, partially offset by an increase in AFUDC equity, partially offset by increases in operatingnon-fuel operations and maintenance expenses.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 20142015 was $642$369 million compared to $572$360 million for the corresponding period in 2013.2014. The increase in net income was primarily related to an increase under Rate RSE and a decrease in revenue primarily due to colder weather in the first quarter 2014 and warmer weather in the second and third quarters of 2014 as compared to the corresponding periods in 2013 anddepreciation, partially offset by an increase in AFUDC equity, partially offset by increases in operatingnon-fuel operations and maintenance expenses.
Retail Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$74 5.1 $258 6.8
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$77 6.2 $48 1.9
In the thirdsecond quarter 2014,2015, retail revenues were $1.51$1.33 billion compared to $1.44$1.25 billion for the corresponding period in 2013.2014. For year-to-date 2014,2015, retail revenues were $4.06$2.59 billion compared to $3.80$2.55 billion for the corresponding period in 2013.2014.

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Details of the changes in retail revenues were as follows:
 
Third Quarter
2014

Year-to-Date
2014
 
Second Quarter
2015

Year-to-Date
2015
 (in millions)
(% change)
(in millions)
(% change) (in millions)
(% change)
(in millions)
(% change)
Retail – prior year $1,438
   $3,800
   $1,249
   $2,546
  
Estimated change resulting from –                
Rates and pricing 8
 0.5
 45
 1.2
 56
 4.5
 103
 4.1
Sales growth 6
 0.4
 2
 0.1
 1
 0.1
 10
 0.4
Weather 32
 2.2
 91
 2.4
 18
 1.5
 (2) (0.1)
Fuel and other cost recovery 28
 2.0
 120
 3.1
 2
 0.1
 (63) (2.5)
Retail – current year $1,512
 5.1% $4,058
 6.8% $1,326
 6.2% $2,594
 1.9%
Revenues associated with changes in rates and pricing increased in the thirdsecond quarter 2015 and year-to-date 20142015 when compared to the corresponding periods in 20132014 primarily due to increased revenues associated witha Rate CNP Environmental primarily resulting fromRSE increase effective January 1, 2015. See Note 3 to the inclusion of pre-2005 environmental assets. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate CNP"financial statements of Alabama Power under "Retail Regulatory Matters" in Item 78 of the Form 10-K for additional information regarding the revision to Rate CNP Environmental.information.
Revenues attributable to changes in sales increasedremained relatively flat in the thirdsecond quarter 2015 and increased slightly year-to-date 20142015 when compared to the corresponding periods in 2013.2014. Industrial KWH energy sales slightly increased 6.5% in the third quarter and 4.3% for0.2% year-to-date 20142015 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, forest products, automotive and plastics, andpipelines, stone, clay, and glass, automotive, and plastics sectors, offset by a decrease in demand in the primary metals and forest products sectors. Weather-adjusted residential KWH energy sales decreased 1.7% in the third quarter and 1.1% for year-to-date 2014 as a result of decreased customer usage. Weather-adjusted commercial KWH energy sales decreased 2.1% in the third quarter and 1.2%were relatively flat for year-to-date 2014 as a result of decreased customer usage. Household income, one of the primary drivers of residential customer usage, has been flat in 2014.2015.
Revenues resulting from changes in weather increased in the thirdsecond quarter 20142015 due to warmer weather experienced in Alabama Power's service territory in the second quarter 2015 as compared to the corresponding period in 2013.2014. For the thirdsecond quarter 2014,2015, the resulting increases were 3.8%2.6% and 1.9%1.5% for residential and commercial sales revenue,revenues, respectively.
Revenues resulting from changes in weather increasedremained relatively flat year-to-date 20142015 primarily due to coldermilder weather experienced in Alabama Power's service territory in the first quarter 2014 and2015 offset by warmer weather in the second and third quarters 2014 whenquarter 2015 as compared to the corresponding periods in 2013. For year-to-date 2014, the resulting increases were 4.1% and 2.2% for residential and commercial sales revenue, respectively.2014.
Fuel and other cost recovery revenues increased in the thirdsecond quarter and year-to-date 20142015 when compared to the corresponding periodsperiod in 20132014 primarily due to an increase in fuel costs associated with an increasepurchased power partially offset by a decrease in the average cost of fuel. Fuel and other cost recovery revenues decreased year-to-date 2015 when compared to the corresponding period in 2014 primarily due to a decrease in KWH generation and a decrease in the average cost of natural gas. fuel.
Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the Natural Disaster Reserve.natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income.
Wholesale Revenues Non-Affiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$6 9.1 $36 19.4
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(8) (12.3) $(27) (18.0)
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of available wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by

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system's 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.
In the thirdsecond quarter 2014,2015, wholesale revenues from sales to non-affiliates were $72$57 million compared to $66$65 million for the corresponding period in 2013.2014. The increasedecrease was primarily due to an 11.2% increasea 12.0% decrease in KWH sales primarily due to the availability of Alabama Power's lower cost generation partially offset by a 2.3% decrease in the price of energy primarily due to the lower cost of coal.
sales. For year-to-date 2014,2015, wholesale revenues from sales to non-affiliates were $222$123 million compared to $186$150 million for the corresponding period in 2013.2014. The increasedecrease was primarily due to a 16.4% increase10.3% decrease in KWH sales primarily due to the availability of Alabama Power's lower cost generation and an increase of 2.2%8.7% decrease in the price of energy primarilyenergy.
In 2014, Alabama Power's fuel diversity led to increased sales to non-affiliates due to higher natural gas prices. In 2015, lower natural gas prices during the winter monthsand decreased availability of 2014.hydro generation, due to less rainfall, resulted in lower sales of Alabama Power's generation to non-affiliates.
Wholesale Revenues Affiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$(16) (34.0) $5 3.1
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(48) (70.6) $(102) (74.5)
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. 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 this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.
In the thirdsecond quarter 2014,2015, wholesale revenues from sales to affiliates were $31$20 million compared to $47$68 million for the corresponding period in 2013.2014. The decrease was primarily due to a 38.8%57.4% decrease in KWH sales and a 31.1% decrease in the price of energy. For year-to-date 2015, wholesale revenues from sales to affiliates were $35 million compared to $137 million for the corresponding period in 2014. The decrease was primarily due to a 63.0% decrease in KWH sales and a 31.4% decrease in the price of energy.
In 2014, Alabama Power's fuel diversity led to increased sales to affiliates due to higher natural gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation, due to less rainfall, resulted in the third quarter 2014 as comparedlower sales of Alabama Power's generation to the corresponding period in 2013 as well as the addition of new generation in the Southern Company system. This decrease was partially offset by a 4.1% increase in the price of energy primarily due to higher natural gas prices.
Other Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1 1.9 $11 7.1
For year-to-date 2014, other revenues were $166 million compared to $155 million for the corresponding period in 2013. The increase was primarily due to increases in co-generation steam revenues, open access transmission tariff revenues, and transmission service agreement revenues.affiliates.
Fuel and Purchased Power Expenses
 
 Third Quarter 2014
vs.
Third Quarter 2013
  Year-to-Date 2014
vs.
Year-to-Date 2013
 
 Second Quarter 2015
vs.
Second Quarter 2014
  Year-to-Date 2015
vs.
Year-to-Date 2014
 (change in millions)
(% change) (change in millions) (% change) (change in millions)
(% change) (change in millions) (% change)
Fuel $(25) (5.4) $48
 3.9 $(71) (17.1) $(193) (22.8)
Purchased power – non-affiliates 21
 58.3 69
 82.1 6
 15.4 (10) (10.4)
Purchased power – affiliates 24
 80.0 38
 37.3 12
 32.4 17
 19.8
Total fuel and purchased power expenses $20
 $155
  $(53) $(186)  
In the thirdsecond quarter 2014,2015, total fuel and purchased power expenses were $553$437 million compared to $533$490 million for the corresponding period in 2013.2014. The increasedecrease was primarily due to a $42$52 million decrease in the average cost of fuel, an $18 million decrease related to the volume of KWHs generated, and a $7 million decrease in the average cost of purchased power, partially offset by a $24 million increase in the volume of KWHs purchased.
For year-to-date 2015, fuel and purchased power expenses were $842 million compared to $1.03 billion for the corresponding period in 2014. The decrease was primarily due to a $120 million decrease in the average cost of fuel, a $72 million decrease related to the volume of KWHs generated, and a $44 million decrease in the average cost of purchased power, partially offset by a $50 million increase in the volume of KWHs purchased.

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purchased, a $6 million increase related to the volume of KWHs generated, and a $3 million increase in the average cost of purchased power, partially offset by a $31 million decrease in the average cost of fuel.
For year-to-date 2014, total fuel and purchased power expenses were $1.58 billion compared to $1.43 billion for the corresponding period in 2013. The increase was primarily due to a $65 million increase related to the volume of KWHs purchased, a $48 million increase in the volume of KWHs generated, and a $42 million increase in the average cost of purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billingsbilling rates are required. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Energy Cost Recovery"Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 78 of the Form 10-K for additional information.
Details of Alabama Power's generation and purchased power were as follows:
 
Third Quarter
2014
 Third Quarter
2013
 Year-to-Date 2014
Year-to-Date 2013 
Second Quarter
2015
 Second Quarter
2014
 Year-to-Date 2015
Year-to-Date 2014
Total generation (billions of KWHs)
 17 18 50 49 15 16 29 33
Total purchased power (billions of KWHs)
 2 1 5 3 2 1 4 3
Sources of generation (percent)
  
Coal 59 57 55 53 59 53 53 53
Nuclear 23 21 23 22 20 24 23 23
Gas 16 16 16 16 15 16 17 16
Hydro 2 6 6 9 6 7 7 8
Cost of fuel, generated (cents per net KWH)
  
Coal 3.04 3.41 3.24 3.37 2.89 3.30 2.89 3.35
Nuclear 0.81 0.84 0.84 0.83 0.82 0.85 0.81 0.86
Gas 3.54 3.27 3.83 3.38 3.10 3.80 3.06 3.99
Average cost of fuel, generated (cents per net KWH)(a)
 2.61 2.80 2.75 2.76 2.50 2.76 2.41 2.83
Average cost of purchased power (cents per net KWH)(b)
 6.56 6.44 6.32 5.44 5.48 5.88 5.00 6.18
(a)
KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)
Average cost of purchased power includes fuel purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the thirdsecond quarter 2014,2015, fuel expense was $442$343 million compared to $467$414 million for the corresponding period in 2013.2014. The decrease was primarily due to a 10.8%an 18.4% decrease in the average cost of coal generation. This was partially offset by a 66.7% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall and an 8.3% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.
For year-to-date 2014, fuel expense was $1.29 billion compared to $1.24 billion for the corresponding period in 2013. The increase was primarily due to a 32.9% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall, a 13.3% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 6.9% increase in KWHs generated by nuclear fuel due to an outage in the second quarter 2013, and a 5.3% increase14.6% decrease in the volume of KWHs generated by natural gas, and a 12.3% decrease in the average cost of coal per KWH generated. The decrease was partially offset by a 21.4% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall.
For year-to-date 2015, fuel expense was $653 million compared to $846 million for the corresponding period in 2014. The decrease was primarily due to a 23.3% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 13.7% decrease in the average cost of coal per KWH generated, and a 9.6% decrease in the volume of KWHs generated by coal. The decrease was partially offset by a 22.1% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall.
Purchased Power – Non-Affiliates
In the second quarter 2015, purchased power expense from non-affiliates was $45 million compared to $39 million for the corresponding period in 2014. The increase was related to a 20.7% increase in the amount of energy purchased due to the availability of lower cost generation resulting from lower natural gas prices, decreased availability of hydro generation as a result of less rainfall, and increased customer demand due to warmer weather in the second quarter 2015 as compared to the corresponding period during 2014. The increase was partially offset by a 5.7% decrease in the average cost per KWH purchased as a result of lower natural gas prices.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Purchased Power – Non-Affiliates
In the third quarter 2014,For year-to-date 2015, purchased power expense from non-affiliates was $57$86 million compared to $36$96 million for the corresponding period in 2013.2014. The increasedecrease was related to a 48.3% increase21.9% decrease in the average cost per KWH purchased andas a 3.4%result of lower natural gas prices partially offset by a 13.6% increase in the amount of energy purchased due to the additionavailability of lower cost generation as a new PPA in 2014.
For year-to-date 2014, purchased power expense from non-affiliates was $153 million compared to $84 million for the corresponding period in 2013. The increase was related to a 65.9% increase in the average cost per KWH purchased primarily due to demand during peak periods and the additionresult of a new PPA in 2014 and a 7.2% increase in the volume of KWHs purchased to meet the demand created by colder weather in the first quarter 2014 compared to the corresponding period in 2013.lower natural gas prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the thirdsecond quarter 2014,2015, purchased power expense from affiliates was $54$49 million compared to $30$37 million for the corresponding period in 2013.2014. The increase was related to a 130.0%45.2% increase in the amount of energy purchased primarily due to the availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation due toas a result of less rainfall during the third quarter 2014 compared to the corresponding period in 2013 as well as the addition of new capacity in the Southern Company system during the third quarter 2014. Thisrainfall. The increase was partially offset by a 23.6%7.0% decrease in the average cost per KWH purchased due to availability of lower cost Southern Company system generation at the time of purchase.natural gas prices.
For year-to-date 2014,2015, purchased power expense from affiliates was $140$103 million compared to $102$86 million for the corresponding period in 2013.2014. The increase was related to a 63.1%39.5% increase in the volumeamount of KWHsenergy purchased to meet the demand created by colder weather in the first quarter 2014 comparedprimarily due to the corresponding period in 2013availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation as a result of less rainfall. The increase was partially offset by a 16.5%14.2% decrease in the average cost per KWH purchased due to the availability of lower cost Southern Company system generation at the time of purchase.natural gas prices.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$18 5.7 $24 2.5
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$40 12.1 $113 17.3
In the thirdsecond quarter 2014,2015, other operations and maintenance expenses were $334$370 million compared to $316$330 million for the corresponding period in 2013. For year-to-date 2014, other operations and maintenance expenses were $989 million compared to $965 million for the corresponding period in 2013.2014. The increases wereincrease was primarily due to increases in labor and contract labor costs. These increases were partially offset by the implementation of an accounting order in 2014 allowing the deferral of non-nuclear outage costs. Alabama Power deferred approximately $16 million of non-nuclear outage expenditures in the second quarter 2014. In addition, employee benefits including pension costs increased $11 million and $57steam generation costs increased $5 million primarily due to non-outage and maintenance costs.
For year-to-date 2015, other operations and maintenance expenses were $768 million compared to $655 million for the corresponding period in 2014. Alabama Power deferred approximately $41 million of non-nuclear outage expenditures in the third quarterfirst half of 2014. In addition, steam generation costs increased $28 million primarily due to scheduled outage costs and year-to-date 2014, respectively. employee benefits including pension costs increased $21 million.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Non-Nuclear Outage Accounting Order"Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Cost of Removal Accounting Order" in Item 78 of the Form 10-K for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Depreciation and Amortization
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$4 2.4 $34 7.0
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(12) (7.0) $(29) (8.4)
For year-to-date 2014,In the second quarter 2015, depreciation and amortization was $521$160 million compared to $487$172 million for the corresponding period in 2013. The increase2014. For year-to-date 2015, depreciation and amortization was $318 million compared to $347 million for the corresponding period in 2014. These decreases were primarily due to an increasea decrease in depreciation rates related to environmental, steam generation, transmission, and distribution assets andeffective January 1, 2015, as authorized by the deferral in 2013 of certain costs under an accounting order. Depreciation related to environmental assets isFERC, partially offset by revenues associated with Rate CNP Environmental. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate CNP" of Alabama Powerincreases in Item 7 of the Form 10-K for additional information regarding Alabama Power's revision to Rate CNP Environmental. See also MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Compliance and Pension Cost Accounting Order" of Alabama Powerplant in Item 7 of the Form 10-K for additional information regarding Alabama Power's deferral of costs under this accounting order.service.
Allowance for Equity Funds Used During Construction
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$8 114.3 $13 56.5
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$3 27.3 $8 38.1
In the thirdsecond quarter 2014,2015, AFUDC equity was $15$14 million compared to $7$11 million for the corresponding period in 2013.2014. For year-to-date 2014,2015, AFUDC equity was $36$29 million compared to $23$21 million for the corresponding period in 2013. The2014. These increases were primarily due to additional capital expenditures for steam power environmental and steam generation. Also contributing to the third quarter increase was an increase in capital expenditures for nuclear fuel.projects.
Income Taxes
Interest Expense, Net of Amounts Capitalized
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$9 5.2 $39 10.0
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$6 9.5 $9 7.2
In the thirdsecond quarter 2014, income taxes were $1832015, interest expense, net of amounts capitalized was $69 million compared to $174$63 million for the corresponding period in 2013.2014. For year-to-date 2014, income taxes were $4292015, interest expense, net of amounts capitalized was $134 million compared to $390$125 million for the corresponding period in 2013. The2014. These increases were primarily due to new debt issuances, which include issuances to redeem long-term debt, preferred stock, and preference stock.
Other Income (Expense), Net
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(11) N/M $(10) (125.0)
N/M - Not meaningful
In the second quarter 2015, other income (expense), net was $(14) million compared to $(3) million for the corresponding period in 2014. For year-to-date 2015, other income (expense), net was $(18) million compared to $(8) million for the corresponding period in 2014. The changes were primarily due to increases in donations.
Income Taxes
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$3 2.5 $(11) (4.5)
In the second quarter 2015, income taxes were $122 million compared to $119 million for the corresponding period in 2014. The increase was primarily due to higher pre-tax earnings.earnings, partially offset by state income tax credits.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS



For year-to-date 2015, income taxes were $235 million compared to $246 million for the corresponding period in 2014. The decrease was primarily due to state income tax credits in the second quarter 2015.
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 and growing sales which isare subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Changes in regional and global economic conditions may impact sales for Alabama Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See Note 3 to the financial statements of Alabama Power under "Environmental Matters New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations" and "PSC"Retail Regulatory Matters Environmental Accounting Order" of Alabama Power in Item 7 of the Form 10-K and "PSC"Retail Regulatory Matters Environmental Accounting Order" herein for additional information regarding Alabama Power's plan for compliance with environmental statutes and regulations.

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Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR) and.
On June 12, 2015, the EPA's proposed rulesEPA published a final rule requiring affected states (including Alabama) to revise or remove state implementation plan (SIP) provisions regarding the regulation of excess emissions that occur during periods of startup, shutdown, or malfunction (SSM).SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On AprilJune 29, 2014,2015, the U.S. Supreme Court overturnedissued a decision finding that the U.S. Court of Appeals for the District of Columbia Circuit's August 2012EPA had failed to properly consider costs in its decision to vacate CSAPRregulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014,The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.
On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subjectrespond to the rule, including Alabama, to revise their SSM provisions within 18 months after issuance of the final rule.decision. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges andthis decision cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate outcomeimpact of these mattersthis decision will depend on additional rulemaking and cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On April 21, 2014,June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a proposedfinal rule to reviserevising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs,CWA programs. The final rule significantly expandingexpands the scope of federal jurisdiction under the CWA. If finalized as proposed,CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition,The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as proposed could have significant impacts on economic development projects which could affect customer demand growth.the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Alabama Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Alabama Power recorded incremental asset retirement obligations (ARO) of approximately $401 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Alabama Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's AROs.

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impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.
On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.CO2 from fossil-fuel-fired electric generating units.
On June 18, 2014,August 3, 2015, the EPA publishedreleased pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the proposed Clean Power Plan, setting forthfinal rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to address CO2 emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and finalmeet EPA-mandated CO2 emission rate goalsrates for existing units. The EPA's final guidelines require state plans to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposedmeet interim CO2 performance standards for modifiedrates between 2022 and reconstructed fossil fuel-fired electric generating units. The2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, thatwhich could impactaffect future unit retirement and replacement decisions. Also, additional compliance costs could affectAlabama Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, any resulting higher costs that are recoveredrates or through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system.market-based contracts. However, the ultimate financial and operational impact of the Cleanfinal rules on Alabama Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upondepend on numerous factors. These factors include:including the structure, timing, and contentSouthern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-relatedemissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
FERC Matters
Alabama Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Alabama Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On June 23, 2014,April 27, 2015, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit andFERC issued an order finding that the EPA didtraditional operating companies' (including Alabama Power's) and Southern Power's existing tailored mitigation may not haveeffectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Alabama Power) and Southern Power to tailorshow why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including Alabama Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the statutory permitting thresholds.FERC. The ultimate impactoutcome of the U.S. Supreme Court's decisionthis matter cannot be determined at this time.
See REGULATION – "Federal Power Act" of Alabama Power in Item 1 of the Form 10-K for additional information regarding Alabama Power's Warrior River Project license.
On January 30, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an order denying Smith Lake Improvement and Stakeholders Association's (SLISA) petition for en banc review of the court's dismissal of SLISA's appeal of the new Warrior River Project license. SLISA did not appeal this decision; therefore, this matter is now concluded and the FERC license is authorized as issued.
Retail Regulatory Matters
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business

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FERC Matters
primarily through its Rate RSE, Rate CNP, rate energy cost recovery, and natural disaster reserve rate. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters"Note 1 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and Note 3 under "Retail Regulatory Matters" in Item 7 of the Form 10-K for additional information on Alabama Power's relicensing applications for the hydroelectric developments on the Coosa River and the Warrior River. On September 26, 2014, the U.S. Court of Appeals for the District of Columbia Circuit dismissed the appeal of the Smith Lake Improvement and Stakeholders' Association from the FERC's orders related to the Warrior River relicensing proceedings for lack of jurisdiction. The ultimate outcome of this matter cannot be determined at this time.
PSC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters" of Alabama Power in Item 78 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clausesrate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Environmental Accounting OrderRate CNP
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and – "PSC Matters – Environmental Accounting Order"Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 78 of the Form 10-K for additional information regarding Alabama Power's plandevelopment of a revised cost recovery mechanism and the normal purchases and normal sales (NPNS) exception for wind PPAs.
On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with environmental statutesthe revised rate now defined as Rate CNP Compliance. Alabama Power incurred $30 million of non-environmental compliance costs during the first six months of 2015 and regulations.will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under recovered position for Rate CNP Compliance during 2015.
AsIn April 2015, the Financial Accounting Standards Board (FASB) proposed new accounting guidance to allow the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power currently accounts for its two wind PPAs. On July 9, 2015, the FASB ratified the consensus reached by the Emerging Issues Task Force to allow the exception in such cases and voted to issue a final accounting standard.
Environmental Accounting Order
In April 2015, as part of its environmental compliance strategy, Alabama Power plans to retireretired Plant Gorgas Units 6 and 7. These units representrepresented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power also plans to ceaseceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally,No later than April 2016, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expectedSubject to be effective no later than April 2016.the final approval of the New Source Review stipulation, Alabama Power will also retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See Note (B) to the Condensed Financial Statements herein for additional information regarding the New Source Review actions.
In accordance with an accounting order from the Alabama PSC, Alabama Power will transfertransferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Alabama Power's financial statements.
Nuclear Waste Fund Accounting OrderRenewable Energy
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" ofOn June 25, 2015, Alabama Power in Item 7 of the Form 10-K and "Other Matters" herein for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero.
On August 5, 2014,filed a petition with the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014,a Renewable Generation Certificate (RGC). The RGC would develop a process that allows Alabama Power to build its own renewable projects each less than 80 MWs or purchase power from other renewable-generated sources up to 500 MWs. The Alabama PSC is authorizedexpected to recover from customers an amount equal to the prior fee and to record the amountsrule on this matter in a regulatory liability account (approximately $14 million annually). Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customers subject to the approval of the Alabama PSC.August 2015. The ultimate outcome of this matter cannot be determined at this time.
Cost of Removal Accounting Order
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters" of Alabama Power in Item 7 of the Form 10-K regarding the previously approved compliance and pension costs accounting order and non-nuclear outage accounting order.

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On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, projected to be $120 million at December 31, 2014. This amortization expense will be offset by the amortization of up to $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances to be fully amortized as of December 31, 2014 represent costs deferred under the compliance and pension cost accounting order as well as the non-nuclear outage accounting order, which were approved by the Alabama PSC in November 2012 and August 2013, respectively. This accounting order also requires Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order and the non-nuclear outage accounting order. Consequently, Alabama Power will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders.
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 air quality and water standards, has increased generallyoccurred throughout the U.S. In particular, personal injury, property damage, and otherThis litigation has included claims for damages alleged to have been caused by CO2 and other emissions, coal combustion residuals,CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.matters.
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 in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Alabama Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See the NotesNote (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011.
Additionally, there are 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. The ultimate outcome of these events cannot be determined at this time.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. See "PSC Matters – Nuclear Waste Fund Accounting Order" herein for information regarding an accounting order issued by the Alabama PSC which provides for continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley.The ultimate outcome of this matter cannot be determined at this time.

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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, and Pension and Other Postretirement Benefits.
Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of Alabama Power's nuclear facility, Plant Farley, and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Alabama Power has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. Alabama Power also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and

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the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Alabama Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Alabama Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Recently Issued Accounting Standards
On May 28, 2014, the Financial Accounting Standards Board issuedThe FASB's ASC 606, Revenue from Contracts with Customers. ASC 606, revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016.2017. Alabama Power is currently evaluatingcontinues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Alabama Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Alabama Power.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at SeptemberJune 30, 2014.2015. 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.4 billion$597 million for the first ninesix months of 2014,2015, a decrease of $71$77 million as compared to the first ninesix months of 2013.2014. The decrease in net cash provided from operating activities was primarily due to an increase in income tax payments and changes in the timing of fossil fuel stock purchases as compared toand payments of accounts payable, partially offset by the first nine monthstiming of 2013.income tax payments and refunds associated with bonus depreciation. Net cash used for investing activities totaled $1.0 billion$626 million for the first ninesix months of 20142015 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash used for financing activities totaled $28$49 million for the first ninesix months of 20142015 primarily due to the paymentredemptions and repurchases of commonlong-term debt and preferred and preference stock and payments of common stock dividends, partially offset by the issuanceissuances of long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20142015 include an increaseincreases of $519$690 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, and steam generation $367and $423 million in cash and cash equivalents, $344AROs associated with the CCR Rule. See Note (A) to the Condensed Financial Statements herein for additional information related to AROs. Other significant changes include decreases of $404 million in long-term debt primarilyredeemable preferred and preference stock due to redemptions in the issuance of additional senior notes, and $135 million in accrued income taxes.second quarter 2015.
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

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description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, 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. Approximately $54$600 million will be required through SeptemberJune 30, 20152016 to fund maturities of long-term debt.

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See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
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; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in the expected environmental compliance program; 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 used in the past. Alabama Power has primarily utilized funds from operating cash flows, short-term debt, security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of Alabama Power's debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.
At SeptemberJune 30, 2014,2015, Alabama Power had approximately $662$195 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20142015 were as follows:
Expires(a)
Expires(a)
     
Executable Term
Loans
 
Due Within One
Year
Expires(a)
     
Executable Term
Loans
 
Due Within One
Year
2014 2015 2016 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
20152015 2016 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions)(in millions) (in millions) (in millions) (in millions)(in millions) (in millions) (in millions) (in millions)
$70
 $158
 $50
 $1,030
 $1,308
 $1,308
 $58
 $
 $58
 $170
154
 $124
 $1,030
 $1,308
 $1,307
 $58
 $
 $58
 $170
(a)No credit arrangements expire in 2017.
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.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $810 million. In addition, at June 30, 2015, Alabama Power had $200 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross default provisions to other

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness or guarantee obligations over a specified threshold. Alabama Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
In addition, Alabama Power has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's variable rate pollution control revenue bonds and commercial paper borrowings. As of September 30, 2014, Alabama Power had $784 million of outstanding variable rate pollution control revenue bonds requiring liquidity support. In addition, at September 30, 2014, Alabama Power

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



had $280 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.
Alabama Power may meet short-term cash needs through its commercial paper program. 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 the other traditional operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
  
Short-term Debt at
September 30, 2014
 
Short-term Debt During the Period(a)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Commercial Paper $
 —% $27
 0.1% $300
  
Short-term Debt at
June 30, 2015
 Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Commercial Paper $
 —% $17
 0.2% $100
(a)(*)Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2014.2015.
ManagementAlabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, short-term bank notes, and cash.operating cash flows.
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.Baa3 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At SeptemberJune 30, 2014, the maximum2015, potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 were immaterial. The maximum collateral requirements at a rating below BBB- and/or Baa3 were approximately $343$367 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system 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
Subsequent to access capital markets, particularly the short-term debt marketJune 30, 2015, S&P placed its ratings of Southern Company and the variable rate pollution control revenue bond market.traditional operating companies (including Alabama Power) on CreditWatch with negative implications.
Financing Activities
In August 2014,March 2015, Alabama Power issued $400$550 million aggregate principal amount of Series 2014A 4.150%2015A 3.750% Senior Notes due AugustMarch 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, 2044. The2035 and for general corporate purposes, including Alabama Power's continuous construction program.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In April 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power reoffered these bonds to the public in May 2015.
Also in April 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used to redeem in May 2015 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for general corporate purposes, including Alabama Power's continuous construction program.program.
Subsequent to September 30, 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notionalIn June 2015, $18.7 million aggregate principal amount of the swaps totaled $100 million.Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1994, $6.15 million aggregate principal amount of the Industrial Development Board of the City of Gadsden, Pollution Control Revenue Bonds (Alabama Power Company Project), Series 1994, and $28.85 million aggregate principal amount of the Industrial Development Board of the Town of Parrish, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1994A were repaid at maturity.
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

5659

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GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
2014 2013 2014 20132015 2014 2015 2014
(in millions) (in millions)(in millions) (in millions)
Operating Revenues:              
Retail revenues$2,452
 $2,314
 $6,502
 $5,922
$1,872
 $2,000
 $3,686
 $4,050
Wholesale revenues, non-affiliates80
 77
 269
 212
50
 80
 118
 189
Wholesale revenues, affiliates7
 3
 38
 14
4
 10
 12
 31
Other revenues92
 90
 277
 260
90
 96
 178
 185
Total operating revenues2,631
 2,484
 7,086
 6,408
2,016
 2,186
 3,994
 4,455
Operating Expenses:              
Fuel684
 691
 2,055
 1,767
503
 619
 1,029
 1,371
Purchased power, non-affiliates77
 64
 219
 175
78
 63
 138
 142
Purchased power, affiliates172
 152
 522
 503
115
 166
 263
 350
Other operations and maintenance456
 402
 1,334
 1,230
467
 451
 943
 878
Depreciation and amortization211
 201
 628
 605
202
 209
 418
 417
Taxes other than income taxes111
 102
 320
 292
97
 106
 195
 209
Total operating expenses1,711
 1,612
 5,078
 4,572
1,462
 1,614
 2,986
 3,367
Operating Income920
 872
 2,008
 1,836
554
 572
 1,008
 1,088
Other Income and (Expense):              
Allowance for equity funds used during construction13
 11
 29
 24
Interest expense, net of amounts capitalized(88) (92) (262) (279)(93) (90) (182) (174)
Other income (expense), net1
 (1) 
 (2)1
 11
 16
 15
Total other income and (expense)(74) (82) (233) (257)(92) (79) (166) (159)
Earnings Before Income Taxes846
 790
 1,775
 1,579
462
 493
 842
 929
Income taxes317
 299
 660
 600
180
 177
 320
 343
Net Income529
 491
 1,115
 979
282
 316
 522
 586
Dividends on Preferred and Preference Stock4
 4
 13
 13
5
 5
 9
 9
Net Income After Dividends on Preferred and Preference Stock$525
 $487
 $1,102
 $966
$277
 $311
 $513
 $577
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
 2014 2013 2014 2013
 (in millions) (in millions)
Net Income$529
 $491
 $1,115
 $979
Other comprehensive income (loss):       
Qualifying hedges:       
Reclassification adjustment for amounts included in
net income, net of tax of $1, $-, $1 and $1, respectively

 1
 1
 2
Total other comprehensive income (loss)
 1
 1
 2
Comprehensive Income$529
 $492
 $1,116
 $981
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2014 2013
 (in millions)
Operating Activities:   
Net income$1,115
 $979
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total757
 734
Deferred income taxes121
 354
Allowance for equity funds used during construction(29) (24)
Retail fuel cost over recovery — long-term(44) (123)
Deferred expenses(35) (34)
Pension, postretirement, and other employee benefits28
 58
Other, net23
 28
Changes in certain current assets and liabilities —   
-Receivables(377) (191)
-Fossil fuel stock337
 213
-Prepaid income taxes19
 11
-Other current assets(24) 38
-Accrued taxes148
 131
-Other current liabilities29
 (46)
Net cash provided from operating activities2,068
 2,128
Investing Activities:   
Property additions(1,364) (1,165)
Investment of restricted cash
 (89)
Distribution of restricted cash
 89
Nuclear decommissioning trust fund purchases(457) (582)
Nuclear decommissioning trust fund sales455
 580
Cost of removal, net of salvage(39) (42)
Change in construction payables, net of joint owner portion16
 (28)
Prepaid long-term service agreements(66) (14)
Other investing activities(3) 
Net cash used for investing activities(1,458) (1,251)
Financing Activities:   
Increase (decrease) in notes payable, net(836) 211
Proceeds —   
Capital contributions from parent company39
 30
Pollution control revenue bonds issuances40
 89
Senior notes issuances
 850
FFB loan1,000
 
Redemptions —   
Pollution control revenue bonds(37) (89)
Senior notes
 (1,250)
Payment of preferred and preference stock dividends(13) (13)
Payment of common stock dividends(715) (680)
FFB loan issuance costs(49) (2)
Other financing activities(6) (15)
Net cash used for financing activities(577) (869)
Net Change in Cash and Cash Equivalents33
 8
Cash and Cash Equivalents at Beginning of Period30
 45
Cash and Cash Equivalents at End of Period$63
 $53
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $13 and $10 capitalized for 2014 and 2013, respectively)$235
 $247
Income taxes, net309
 109
Noncash transactions — accrued property additions at end of period220
 230

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)
Assets At September 30,
2014
 At December 31,
2013
  (in millions)
Current Assets:    
Cash and cash equivalents $63
 $30
Receivables —    
Customer accounts receivable 738
 512
Unbilled revenues 241
 209
Joint owner accounts receivable 75
 67
Other accounts and notes receivable 54
 117
Affiliated companies 21
 21
Accumulated provision for uncollectible accounts (8) (5)
Fossil fuel stock, at average cost 405
 742
Materials and supplies, at average cost 431
 409
Vacation pay 88
 88
Prepaid income taxes 57
 97
Other regulatory assets, current 62
 66
Other current assets 118
 54
Total current assets 2,345
 2,407
Property, Plant, and Equipment:    
In service 30,818
 30,132
Less accumulated provision for depreciation 11,192
 10,970
Plant in service, net of depreciation 19,626
 19,162
Other utility plant, net 218
 240
Nuclear fuel, at amortized cost 516
 523
Construction work in progress 3,884
 3,500
Total property, plant, and equipment 24,244
 23,425
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 58
 46
Nuclear decommissioning trusts, at fair value 772
 751
Miscellaneous property and investments 37
 44
Total other property and investments 867
 841
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 701
 718
Prepaid pension costs 133
 118
Deferred under recovered regulatory clause revenues 175
 
Other regulatory assets, deferred 1,156
 1,152
Other deferred charges and assets 294
 246
Total deferred charges and other assets 2,459
 2,234
Total Assets $29,915
 $28,907
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)
Liabilities and Stockholder's Equity At September 30,
2014
 At December 31,
2013
  (in millions)
Current Liabilities:    
Securities due within one year $503
 $5
Notes payable 211
 1,047
Accounts payable —    
Affiliated 503
 417
Other 476
 472
Customer deposits 250
 246
Accrued taxes —    
Accrued income taxes 155
 
Other accrued taxes 313
 321
Accrued interest 99
 91
Accrued vacation pay 60
 61
Accrued compensation 111
 80
Other current liabilities 177
 166
Total current liabilities 2,858
 2,906
Long-term Debt 9,135
 8,633
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 5,295
 5,200
Deferred credits related to income taxes 107
 112
Accumulated deferred investment tax credits 196
 203
Employee benefit obligations 580
 542
Asset retirement obligations 1,215
 1,210
Other cost of removal obligations 58
 43
Other deferred credits and liabilities 178
 201
Total deferred credits and other liabilities 7,629
 7,511
Total Liabilities 19,622
 19,050
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 5,683
 5,633
Retained earnings 3,950
 3,565
Accumulated other comprehensive loss (4) (5)
Total common stockholder's equity 10,027
 9,591
Total Liabilities and Stockholder's Equity $29,915
 $28,907
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Net Income$282
 $316
 $522
 $586
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of $9, $-, $-, and $-, respectively14
 
 
 
Reclassification adjustment for amounts included in
   net income, net of tax of $-, $-, $1, and $-, respectively
1
 1
 1
 1
Total other comprehensive income (loss)15
 1
 1
 1
Comprehensive Income$297
 $317
 $523
 $587
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Six Months
Ended June 30,
 2015 2014
 (in millions)
Operating Activities:   
Net income$522
 $586
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total512
 503
Deferred income taxes(6) 121
Allowance for equity funds used during construction(10) (16)
Retail fuel cost over recovery — long-term
 (44)
Deferred expenses28
 31
Contract amendment(118) 
Other, net
 (12)
Changes in certain current assets and liabilities —   
-Receivables(21) (353)
-Fossil fuel stock101
 255
-Prepaid income taxes86
 (7)
-Other current assets(38) (14)
-Accounts payable(110) (140)
-Accrued taxes(125) (65)
-Accrued compensation(61) (15)
-Retail fuel cost over recovery — short-term
 (14)
-Other current liabilities14
 27
Net cash provided from operating activities774
 843
Investing Activities:   
Property additions(853) (906)
Nuclear decommissioning trust fund purchases(655) (324)
Nuclear decommissioning trust fund sales649
 322
Change in construction payables, net of joint owner portion26
 52
Prepaid long-term service agreements(40) (47)
Other investing activities(18) (14)
Net cash used for investing activities(891) (917)
Financing Activities:   
Increase (decrease) in notes payable, net44
 (359)
Proceeds —   
Capital contributions from parent company23
 24
Pollution control revenue bonds170
 
FFB loan600
 1,000
Short-term borrowings250
 
Redemptions and repurchases —   
Pollution control revenue bonds(65) (37)
Senior notes(125) 
Short-term borrowings(250) 
Payment of preferred and preference stock dividends(9) (9)
Payment of common stock dividends(517) (477)
FFB loan issuance costs
 (49)
Other financing activities(4) (3)
Net cash provided from financing activities117
 90
Net Change in Cash and Cash Equivalents
 16
Cash and Cash Equivalents at Beginning of Period24
 30
Cash and Cash Equivalents at End of Period$24
 $46
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $5 and $8 capitalized for 2015 and 2014, respectively)$170
 $157
Income taxes, net240
 145
Noncash transactions — Accrued property additions at end of period171
 267

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)
Assets At June 30,
2015
 At December 31,
2014
  (in millions)
Current Assets:    
Cash and cash equivalents $24
 $24
Receivables —    
Customer accounts receivable 778
 553
Unbilled revenues 294
 201
Joint owner accounts receivable 44
 121
Other accounts and notes receivable 46
 61
Affiliated companies 20
 18
Accumulated provision for uncollectible accounts (6) (6)
Fossil fuel stock, at average cost 338
 439
Materials and supplies, at average cost 425
 438
Vacation pay 91
 91
Prepaid income taxes 225
 278
Other regulatory assets, current 147
 136
Other current assets 86
 74
Total current assets 2,512
 2,428
Property, Plant, and Equipment:    
In service 31,363
 31,083
Less accumulated provision for depreciation 10,961
 11,222
Plant in service, net of depreciation 20,402
 19,861
Other utility plant, net 10
 211
Nuclear fuel, at amortized cost 551
 563
Construction work in progress 4,171
 4,031
Total property, plant, and equipment 25,134
 24,666
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 61
 58
Nuclear decommissioning trusts, at fair value 814
 789
Miscellaneous property and investments 37
 38
Total other property and investments 912
 885
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 681
 698
Deferred under recovered regulatory clause revenues 
 197
Other regulatory assets, deferred 2,063
 1,753
Other deferred charges and assets 446
 403
Total deferred charges and other assets 3,190
 3,051
Total Assets $31,748
 $31,030
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)
Liabilities and Stockholder's Equity At June 30,
2015
 At December 31,
2014
  (in millions)
Current Liabilities:    
Securities due within one year $1,660
 $1,154
Notes payable 200
 156
Accounts payable —    
Affiliated 392
 451
Other 574
 555
Customer deposits 259
 253
Other accrued taxes 207
 332
Accrued interest 96
 96
Accrued vacation pay 62
 63
Accrued compensation 81
 153
Other current liabilities 309
 257
Total current liabilities 3,840
 3,470
Long-term Debt 8,914
 8,683
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 5,524
 5,507
Deferred credits related to income taxes 103
 106
Accumulated deferred investment tax credits 191
 196
Employee benefit obligations 870
 903
Asset retirement obligations 1,301
 1,223
Other deferred credits and liabilities 286
 255
Total deferred credits and other liabilities 8,275
 8,190
Total Liabilities 21,029
 20,343
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 6,232
 6,196
Retained earnings 3,830
 3,835
Accumulated other comprehensive loss (7) (8)
Total common stockholder's equity 10,453
 10,421
Total Liabilities and Stockholder's Equity $31,748
 $31,030
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


THIRDSECOND QUARTER 20142015 vs. THIRDSECOND QUARTER 20132014
AND
YEAR-TO-DATE 20142015 vs. YEAR-TO-DATE 20132014


OVERVIEW
Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service areaterritory 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 costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, and fuel. In addition, Georgia Power is currently constructingconstruction continues on Plant Vogtle Units 3 and 4 in which Georgia Power will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
Georgia Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Georgia Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$38 7.8 $136 14.1
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(34) (10.9) $(64) (11.1)
Georgia Power's net income after dividends on preferred and preference stock for the thirdsecond quarter 20142015 was $525$277 million compared to $487$311 million for the corresponding period in 2013. The increase was primarily due to an increase in retail base revenues effective January 1, 2014 as authorized under the 2013 ARP and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013, partially offset by higher non-fuel operations and maintenance expenses.
Georgia Power's2014. For year-to-date 2015, net income after dividends on preferred and preference stock for year-to-date 2014 was $1.10 billion$513 million compared to $966$577 million for the corresponding period in 2013.2014. The increase wasdecreases were primarily due to colder weather inhigher non-fuel operations and maintenance expenses and the first quarter 2014correction of an error affecting billings to a small number of large commercial and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and an increaseindustrial customers, partially offset by increases in retail base revenues effective January 1, 20142015 as authorized underby the 2013 ARP, partially offset by higher non-fuel operations and maintenance expenses.Georgia PSC. Additionally, warmer weather in the second quarter 2015 compared to the corresponding period in 2014 contributed to increases in retail base revenues.
See Note (A) to Condensed Financial Statements herein for additional information.
Retail Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions)
(% change)
$138 6.0 $580 9.8
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions)
(% change)
$(128) (6.4) $(364) (9.0)
In the thirdsecond quarter 2014,2015, retail revenues were $2.45$1.87 billion compared to $2.31$2.00 billion for the corresponding period in 2013.2014. For year-to-date 2014,2015, retail revenues were $6.50$3.69 billion compared to $5.92$4.05 billion for the corresponding period in 2013.2014.

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Details of the changes in retail revenues were as follows:
 Third Quarter
2014
 
Year-to-Date
 2014
 Second Quarter
2015
 
Year-to-Date
 2015
 (in millions)
(% change) (in millions) (% change) (in millions)
(% change) (in millions) (% change)
Retail – prior year $2,314
   $5,922
   $2,000
   $4,050
  
Estimated change resulting from –                
Rates and pricing 67
 2.9
 147
 2.5
 (27) (1.3) 3
 0.1
Sales growth 1
 0.1
 23
 0.4
 21
 1.0
 37
 0.9
Weather 51
 2.2
 131
 2.2
 22
 1.1
 6
 0.1
Fuel cost recovery 19
 0.8
 279
 4.7
 (144) (7.2) (410) (10.1)
Retail – current year $2,452
 6.0% $6,502
 9.8% $1,872
 (6.4)% $3,686
 (9.0)%
Revenues associated with changes in rates and pricing increaseddecreased in the thirdsecond quarter and year-to-date 20142015 when compared to the corresponding periodsperiod in 20132014 primarily due to the correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing, partially offset by base tariff increases effective January 1, 2014, as approved by the Georgia PSC inunder the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, as well as higher contributions from market-drivenwhich were both effective January 1, 2015. Revenues associated with changes in rates from commercial and industrial customers.pricing increased slightly year-to-date 2015 when compared to the corresponding period in 2014 primarily due to the base tariff increases and increases in collections for financing costs described above, partially offset by the error correction. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales increased in the thirdsecond quarter andyear-to-date 20142015 when compared to the corresponding periods in 2013.2014. Weather-adjusted residential KWH sales decreased 0.1%increased 2.6%, weather-adjusted commercial KWH sales decreasedincreased 1.1%, and weather-adjusted industrial KWH sales increased 2.4%remained flat in the thirdsecond quarter 20142015 when compared to the corresponding period in 2013.2014. For year-to-date 2014,2015, weather-adjusted residential KWH sales increased 0.8%1.8%, weather-adjusted commercial KWH sales decreased 0.2%increased 1.0%, and weather-adjusted industrial KWH sales increased 1.7%2.0% when compared to the corresponding period in 2013.2014. An increase of approximately 28,000 residential customers since June 30, 2014 contributed to the increase in weather-adjusted residential KWH sales. Increased customer usage and an increase of approximately 3,000 commercial customers since June 30, 2014 contributed to the increase in weather-adjusted commercial sales. Increased demand in the primary metals, non-manufacturing, paper, stone, clay, and glass, food processing, transportation, rubber, and pipeline sectors was the main contributor to the increase in weather-adjusted industrial sales. Decreased customer usage contributed to the decrease in weather-adjusted commercial sales. An increase of approximately 20,000 residential customers since September 30, 2013 contributed to the year-to-date 2014 increase in weather-adjusted residential KWH sales, partially offset by decreased customer usage. Household income, one ofa decrease in the primary drivers of residential customer usage, has been flat in 2014.chemicals sector.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $19decreased $144 million and $279$410 million in the thirdsecond quarter and year-to-date 2014,2015, respectively, when compared to the corresponding periods in 20132014 primarily due to higherlower natural gas, costscoal, and higher energy sales resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013.nuclear fuel costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "PSC"Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.
Wholesale RevenuesNon-Affiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$3 3.9 $57 26.9
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(30) (37.5) $(71) (37.6)
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. CapacityWholesale capacity revenues reflectfrom PPAs are

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recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's

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generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's 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 Georgia Power's variable cost of energy.
For year-to-date 2014,In the second quarter 2015, wholesale revenues from sales to non-affiliates were $269$50 million compared to $212$80 million for the corresponding period in 20132014 related to a $15 million decrease in energy revenues and a $15 million decrease in capacity revenues. For year-to-date 2015, wholesale revenues from sales to non-affiliates were $118 million compared to $189 million for the corresponding period in 2014 related to a $48 million decrease in energy revenues and a $23 million decrease in capacity revenues. The decreases in energy revenues were primarily due to increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and the lower cost of Georgia Power-owned generation compared tonatural gas and coal. The decreases in capacity revenues reflect the market costexpiration of available energy.wholesale contracts in December 2014 and the retirements of Plant Branch Units 1, 3, and 4, Plant Yates Units 1 through 5, and Plant McManus Units 1 and 2.
Wholesale RevenuesAffiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$4 N/M $24 171.4
N/M – Not meaningful
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(6) (60.0) $(19) (61.3)
Wholesale revenues from 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. 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.
For year-to-date 2014,In the second quarter 2015, wholesale revenues from sales to affiliates were $38$4 million compared to $14$10 million for the corresponding period in 2013. The increase was due to higher demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and the lower cost of Georgia Power-owned generation.
Other Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$2 2.2 $17 6.5
2014. For year-to-date 2014, other operating2015, wholesale revenues from sales to affiliates were $277$12 million compared to $260$31 million infor the corresponding period in 2013.2014. The increase was primarilydecreases were due to an increase of $13 million in open access transmission tariff revenueslower natural gas and $6 million of solar application fee revenue for year-to-date 2014 as compared to the corresponding period in 2013.coal prices.
Fuel and Purchased Power Expenses
  Third Quarter 2014
vs.
Third Quarter 2013
  Year-to-Date 2014
vs.
Year-to-Date 2013
  Second Quarter 2015
vs.
Second Quarter 2014
  Year-to-Date 2015
vs.
Year-to-Date 2014
 (change in millions)
(% change) (change in millions) (% change) (change in millions)
(% change) (change in millions) (% change)
Fuel $(7) (1.0) $288
 16.3 $(116) (18.7) $(342) (24.9)
Purchased power – non-affiliates 13
 20.3
 44
 25.1 15
 23.8
 (4) (2.8)
Purchased power – affiliates 20
 13.2
 19
 3.8 (51) (30.7) (87) (24.9)
Total fuel and purchased power expenses $26
   $351
  $(152)   $(433)  
In the thirdsecond quarter 2014,2015, total fuel and purchased power expenses were $933$696 million compared to $907$848 million in the corresponding period in 2013.2014. The increasedecrease in the thirdsecond quarter 20142015 was primarily due to an $82a $154 million decrease in the average cost of fuel related to lower natural gas, coal, and nuclear fuel prices and a decrease in the average cost of purchased power due to lower natural gas prices and a $21 million decrease in the volume of KWHs generated due to less available generating capacity as a result of plant retirements in April 2015, partially offset by a $23 million increase in the volume of KWHs generated and purchased as a result of warmer weather in the third quarter 2014 asdue to lower natural gas prices.

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For year-to-date 2015, total fuel and purchased power expenses were $1.43 billion compared to $1.86 billion in the corresponding period in 2013 driving higher customer demand, partially offset by2014. The decrease in year-to-date 2015 was primarily due to a $56$396 million decrease in the average cost of fuel primarily duerelated to lower natural gas, coal, prices.
For year-to-date 2014, totaland nuclear fuel prices and purchased power expenses were $2.80 billion compared to $2.45 billion in the corresponding period in 2013. The increase in year-to-date 2014 was primarily due to a $66 million increasedecrease in the average cost of fuel and purchased power primarily due to higherlower natural gas prices and a $285$99 million decrease in the volume of KWHs generated due to less available generating capacity as a result of plant retirements in April 2015, partially offset by a $62 million increase in the volume of KWHs generated primarily as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as comparedpurchased due to the corresponding periods in 2013 driving higher customer demand.lower natural gas prices.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL – "PSC"Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.
Details of Georgia Power's generation and purchased power were as follows:
 Third Quarter
2014
 Third Quarter
2013
 Year-to-Date 2014
Year-to-Date 2013 Second Quarter
2015
 Second Quarter
2014
 Year-to-Date 2015
Year-to-Date 2014
Total generation (billions of KWHs)
 19 19 55 50 17 18 34 36
Total purchased power (billions of KWHs)
 6 5 16 17 6 5 11 10
Sources of generation (percent)
  
Coal 45 42 45 35 40 42 37 45
Nuclear 20 22 21 23 24 22 23 21
Gas 34 34 32 39 34 34 38 31
Hydro 1 2 2 3 2 2 2 3
Cost of fuel, generated (cents per net KWH)
  
Coal 4.19 4.89 4.49 4.99 3.75 4.20 4.18 4.65
Nuclear 0.86 0.91 0.90 0.91 0.85 0.93 0.71 0.92
Gas 3.41 3.34 3.84 3.34 2.67 3.81 2.65 4.09
Average cost of fuel, generated (cents per net KWH)
 3.25 3.47 3.51 3.37 2.66 3.32 2.76 3.66
Average cost of purchased power (cents per net KWH)(a)
 5.03 5.00 5.42 4.80
Average cost of purchased power (cents per net KWH)(*)
 4.56 5.55 4.47 5.66
(a)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
(*) Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the thirdsecond quarter 2014,2015, fuel expense was $684$503 million compared to $691$619 million in the corresponding period in 2013.2014. The decrease was primarily due to a 14.3%19.9% decrease in the average cost of coal per KWH generated, partially offset by a 1.5% increase in the volume of KWHs generated as a result of warmer weather in the third quarter 2014 as compared to the corresponding period in 2013 driving higher customer demand.
For year-to-date 2014, fuel expense was $2.06 billion compared to $1.77 billion in the corresponding period in 2013. The increase was primarily due to a 10.7% increase in the volume of KWHs generated as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 driving higher customer demand and a 4.2% increase in the average cost of fuel per KWH generated and a 6.7% decrease in the volume of KWHs generated by coal.
For year-to-date 2015, fuel expense was $1.03 billion compared to $1.37 billion in the corresponding period in 2014. The decrease was primarily due to highera 24.6% decrease in the average cost of fuel per KWH generated and a 22.2% decrease in the volume of KWHs generated by coal, partially offset by a 13.9% increase in the volume of KWHs generated by natural gas prices.gas.
Purchased Power – Non-Affiliates
In the thirdsecond quarter 2014,2015, purchased power expense from non-affiliates was $77$78 million compared to $64$63 million in the corresponding period in 2013.2014. The increase was primarily due to a 4.1%94.1% increase in the average cost per KWHvolume of KWHs purchased to meet higher customer demand resulting from warmer weather in the second quarter 2015 compared to the corresponding period in 2014 and to replace the energy previously generated by the plants retired in April 2015,

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partially offset by a 36.0% decrease in the average cost per KWH purchased, primarily resulting from higherlower natural gas prices.
For year-to-date 2015, purchased power expense from non-affiliates was $138 million compared to $142 million in the corresponding period in 2014. The decrease was primarily due to a 32.9% decrease in the average cost per KWH purchased primarily from lower natural gas prices, andpartially offset by a 19.0%48.5% increase in the volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the thirdsecond quarter 2014 as2015 compared to the corresponding period in 2013.
For year-to-date 2014, purchased power expense from non-affiliates was $219 million compared to $175 million in the corresponding period in 2013. The increase was due to an increase of 17.5% in the average cost per KWH purchased primarily resulting from higher natural gas prices and a 7.3% increase in the volume of KWHs purchased to meet higher customer demand resulting from colder weather in the first quarter 2014 and warmer weatherto replace the energy previously generated by the plants retired in the second and third quarters 2014 as compared to the corresponding periods in 2013.April 2015.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the thirdsecond quarter 2014,2015, purchased power expense from affiliates was $172$115 million compared to $152$166 million in the corresponding period in 2013. The increase was due to a 23.1% increase in the volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.
2014. For year-to-date 2014,2015, purchased powerpower expense from affiliates was $522$263 million compared to $503$350 million in the corresponding period in 2013.2014. The increase was primarilydecreases were due to a 10.1% increase17.7% decrease in the second quarter 2015 and a 20.7% decrease for year-to-date 2015 in the average cost perof KWH purchased, reflecting higherprimarily resulting from lower natural gas prices, partially offset by a 2.1% decrease in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources.prices.
Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$54 13.4 $104 8.5
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$16 3.5 $65 7.4
In the thirdsecond quarter 2014,2015, other operations and maintenance expenses were $456$467 million compared to $402$451 million in the corresponding period in 2013.2014. The increase was primarily due to increases of $21$10 million in generation expensesemployee compensation and benefits including pension costs, $8 million in scheduled outage-related costs, and $3 million primarily related to meet higher demandcustomer incentive and for scheduled outage maintenance and $22demand-side management costs, partially offset by a decrease of $7 million in transmission and distribution overhead line maintenance. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
For year-to-date 2014,2015, other operations and maintenance expensesexpenses were $1.33 billion compared$943 million compared to $1.23 billion$878 million in the corresponding periodperiod in 2013.2014. The increase was primarily due to increases of $44$31 million in generation expenses to meet higher demand, $37employee compensation and benefits including pension costs, $15 million in transmissionscheduled outage-related costs, and distribution overhead line maintenance, and $16$13 million in customer assistance expensesprimarily related to customer incentive and demand-side management programs.costs.
Depreciation and Amortization
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$10 5.0 $23 3.8
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(7) (3.3) $1 0.2
In the thirdsecond quarter 2014,2015, depreciation and amortization was $211$202 million compared to $201$209 million in the corresponding period in 2013.2014. The increasedecrease was primarily due to decreases in other cost of removal of $9 million and $4depreciation of $2 million as authorized by the Georgia PSC under the 2013 ARP, partially offset by an increase in amortization of $4 million.

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regulatory liabilities related to state income tax credits that was completed in December 2013 and other cost of removal obligations as authorized in the 2013 ARP, respectively, partially offset by a decrease of $6 million inFor year-to-date 2015, depreciation and amortization also as authorized in the 2013 ARP.
For year-to-date 2014, depreciation and amortizationwas $628$418 million compared to $605$417 million in the corresponding period in 2013.2014. The increase was due to decreases of $27 millionan increase in depreciation and $12 million in amortization of regulatory liabilities related to state income tax credits that was completed in December 2013 and other cost of removal obligations$10 million as authorized inby the Georgia PSC under the 2013 ARP, respectively, partially offset by a decrease in other cost of $14 million in depreciation and amortization also as authorized in the 2013 ARP.removal of $9 million.
Taxes Other Than Income Taxes
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$9 8.8 $28 9.6
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(9) (8.5) $(14) (6.7)
In the thirdsecond quarter 2014,2015, taxes other than income taxes were $111$97 million compared to $102$106 million in the corresponding period in 2013. 2014. For the year-to-date 2014,2015, taxes other than income taxes were $320$195 million comparedcompared to $292$209 million in the corresponding period in 2013.2014. The increasesdecreases were primarily due to increasesdecreases of $5$6 million and $21$11 million in municipal franchise fees related to higherlower retail revenues in the second quarter 2015 and $3 million and $6year-to-date 2015, respectively, as well as decreases of $2 million in payrollproperty taxes in the third quarter 2014 and year-to-date 2014, respectively.for each period.
Interest Expense, Net of Amounts CapitalizedOther Income (Expense), net
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(4) (4.3) $(17) (6.1)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(10) (90.9) $1 6.6
In the thirdsecond quarter 2014, interest expense,2015, other income (expense), net of amounts capitalized was $88$1 million compared to $92$11 million in the corresponding period in 2013. The decrease was due to a $13 million decrease in interest on long-term debt resulting from the refinancing of long-term debt at lower rates, partially offset by a $9 million increase in interest on outstanding long-term debt borrowings from the FFB.
2014. For year-to-date 2014, interest expense,2015, other income (expense), net of amounts capitalized was $262$16 million compared to $279$15 million in the corresponding period in 2013.2014. The decrease was duechanges primarily relate to a $36 million decrease in interest on long-term debt resulting from the refinancing of long-term debt at lower rates and redemptions, partially offset by a $22 million increase in interest on outstanding long-term debt borrowings from the FFB.
See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.AFUDC equity.
Income Taxes
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$18 6.0 $60 10.0
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$3 1.7 $(23) (6.7)
In the third quarter 2014,For year-to-date 2015, income taxes were $317$320 million compared to $299 million for the corresponding period in 2013. For year-to-date 2014, income taxes were $660 million compared to $600$343 million in the corresponding period in 2013.2014. The increases in income taxes weredecrease was primarily due to higherlower pre-tax earnings.

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FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and the completion and subsequent operation of ongoing construction projects, primarily Plant Vogtle Units 3 and 4. Future earnings in the near term will depend, in part, upon maintaining and growing sales which isare subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Changes in regional and global economic conditions may impact sales for Georgia Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

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Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "PSC"Retail Regulatory Matters Integrated Resource Plans" of Georgia Power in Item 7 of the Form 10-K and "PSC"Retail Regulatory Matters Integrated Resource Plan" herein for additional information regardingon planned unit retirements and fuel conversions at Georgia Power's plans for compliance with environmental statutes and regulations.Power.
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015, the EPA published a final rule requiring affected states (including Georgia, Alabama, and the EPA's proposed rulesFlorida) to revise or remove state implementation plan (SIP) provisions regarding the regulation of excess emissions that occur during periods of startup, shutdown, or malfunction (SSM).SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On AprilJune 29, 2014,2015, the U.S. Supreme Court overturnedissued a decision finding that the U.S. Court of Appeals for the District of Columbia Circuit's August 2012EPA had failed to properly consider costs in its decision to vacate CSAPRregulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014,The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit grantedand the EPA's motionEPA respond to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR.decision. The ultimate financial and unit operational impact of the rulethis decision cannot be determined at this timetime.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Georgia, Alabama, and is dependentFlorida. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of

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the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.
On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Georgia, Alabama, and Florida) to revise their SSM provisions within 18 months after issuance of the final rule. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.
The ultimate outcome of these matters cannot be determined at this time.
Water Quality
On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed,CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, theThe rule as proposed could have significant impacts on economic development projects which could affect customer demand growth.becomes effective August 28, 2015. The ultimate impact of the proposedfinal rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations – Water Quality" Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.regulation of CCR.
On August 15, 2014,April 17, 2015, the EPA published athe Disposal of Coal Combustion Residuals from Electric Utilities final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became(CCR Rule) in the Federal Register, setting October 19, 2015 as the effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementationdate of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units.CCR Rule. The ultimate impact of this rule will depend on the outcome of any legal challenges andCCR Rule cannot be determined at this time.timeand will depend on Georgia Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Georgia Power recorded incremental asset retirement obligations (ARO) of approximately $82 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Georgia Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's AROs.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.CO2 from fossil-fuel-fired electric generating units.
On June 18, 2014,August 3, 2015, the EPA publishedreleased pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the proposed Clean Power Plan, setting forthfinal rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to address CO2 emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and finalmeet EPA-mandated CO2 emission rate goalsrates for existing units. The EPA's final guidelines require state plans to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposedmeet interim CO2 performance standards for modifiedrates between 2022 and reconstructed fossil fuel-fired electric generating units. The2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, thatwhich could impactaffect future unit retirement and replacement decisions. Also, additional compliance costs could affectGeorgia Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, any resulting higher costs that are recoveredrates or through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include

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a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system.market-based contracts. However, the ultimate financial and operational impact of the Cleanfinal rules on Georgia Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upondepend on numerous factors. These factors include:including the structure, timing, and contentSouthern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-relatedemissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of the U.S. Supreme Court's decision cannot be determined at this time.
PSCFERC Matters
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate Plans" of Georgia Power in Item 7 and Note 3has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the financial statementsrequirements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 ofan energy auction, which the Form 10-K for additional information on Georgia Power's 2013 ARP.
FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with the terms of the 2013 ARP, on October 3, 2014, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2015 pending its approval:
Increase the traditional base tariffs by approximately $107 million to cover additional capacity costs;
Increase the environmental compliance cost recovery tariff by approximately $32 million;
Increase the demand-side management tariffs by approximately $3 million; and
Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.
The ultimate outcome of this matter cannot be determined at this time.
Renewables Development
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Renewables Development" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Renewables Development" in Item 8 of the Form 10-K for additional information.
On May 20, 2014, the Georgia PSC approved Georgia Power's application for the certification of two PPAs executed in April 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.
As a result of biomass PPA amendments executed during 2014, total estimated purchased power contractual obligations decreased $392 million from December 31, 2013. Estimated purchased power contractual obligations have been updated to $641million for 2015 and 2016, $679 million for 2017 and 2018, and $3.8 billion after 2018. Estimated purchased power contractual obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations – Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for additional information.

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FERC regulations governing such authority, the traditional operating companies (including Georgia Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On October 8, 2014,April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Georgia Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Georgia Power) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including Georgia Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power executed PPAscurrently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, ECCR tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to purchase energy from 515 MWsthe construction of solar capacity asPlant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Renewables Development
As part of the Georgia Power Advanced Solar Initiative program.program, Georgia Power executed ten PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. These PPAs are expected to commence in December 2015 and 2016 and have terms ranging from 20 to 30 years,years. As a result of certain acquisitions by Southern Power, Georgia Power expects that 249 MWs of the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.
On June 15, 2015, Georgia Power executed a PPA to purchase a total of 58 MWs of biomass capacity and are subject toenergy from a 79-MW facility in Georgia that will begin in 2017 and end in 2047. This PPA was approved by the Georgia PSC approval.on April 15, 2015. Georgia Power also entered into an energy-only PPA for the remaining 21 MWs from the same facility.
On October 23, 2014,July 21, 2015, the Georgia PSC approved Georgia Power's request to build, own, and operate three 30-MWa 46-MW solar generation facilitiesfacility at threea U.S. Army basesMarine Corps base in Albany, Georgia by the end of 2016. In addition, Georgia Power has entered into a memorandum of understanding with the U.S. Navy to pursue a similar solar project pending Georgia PSC review.
The ultimate outcome of these matters cannot be determined at this time.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Integrated Resource Plans" of Georgia Power in Item 7 and Note 3 toTo comply with the financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8April 16, 2015 effective date of the Form 10-K for additional information.
Georgia Power filed a request with the Georgia PSCMATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on January 10, 2014 to cancel the proposed biomass fuel conversion ofApril 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) because it would notand its decertification will be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3requested in connection with the triennial Integrated Resource Plan in 2016. Georgia Power plansThe switch to continuenatural gas as the primary fuel is complete at Plant Yates Units 7 and 6 and the units were returned to operate the unit as needed until the Mercuryservice on May 4, 2015 and Air Toxics Standards rule becomes effective in April 2015.June 27, 2015, respectively.
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 tohas established fuel cost recovery rates approved by the financial statements ofGeorgia PSC. Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
As of September 30, 2014, Georgia Power's under recovered fuel balance totaled $175 million and is included in deferred charges and other assets on Georgia Power's Condensed Balance Sheet herein. As of December 31, 2013, Georgia Power's over recovered fuel balance totaled $58 million and is included in current liabilities and other deferred credits and liabilities on Georgia Power's Condensed Balance Sheet herein. Georgia Power'sexpects to file its next fuel case is expected toin September 2015. The ultimate outcome of this matter cannot be filed with the Georgia PSC by February 27, 2015.determined at this time.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Georgia Power's revenues or net income, but will affect cash flow. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information.
Storm Damage Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Storm Damage Recovery" of Georgia Power in Item 7 and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.
Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $105 million and $37 million, respectively. The increase was primarily the result of an ice storm in February 2014. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Georgia Power's financial statements.

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Nuclear Construction
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC"Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, and pending litigation.
In 2009,2008, Georgia Power, acting for itself and as agent for the Georgia PSC approved inclusion ofVogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 related CWIP accounts in rate base,Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the State of Georgia enactedContractor's failure to fulfill the Georgia Nuclear Energy Financing Act, which allowsschedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to recover financing coststhe Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.
Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for nuclear construction projects certifiedtheir convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Georgia PSC. Financing costs are recoveredVogtle Owners, Vogtle Owner insolvency, and certain other events.
In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On October 31, 2014, Georgia Power filed to increase the NCCR tariff by approximately $27 million effective January 1, 2015 pending Georgia PSC approval. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2014, approximately $23 million of these 2009 and 2010 costs remained unamortized in CWIP.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from4. The NRC certified the Georgia PSC. Accordingly, Georgia Power's eighth VCM report filedWestinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in February 2013 requested an amendmentlate 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the certificate to increase the estimated in-service capital costconstruction and licensing of Plant Vogtle Units 3 and 4, from $4.4 billion to $4.8 billionat the federal and to extend the estimated in-service dates to the fourth quarter 2017state level, and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during theadditional challenges are expected as construction period are estimated to total approximately $2.0 billion.proceeds.
In September 2013, the Georgia PSC approved a stipulation entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. On August 19, 2014, the Georgia PSC approved a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), including construction capital costs incurred, which through December 31, 2013 totaled $2.6 billion. Georgia Power resumed filing semi-annual reports with the eleventh VCM report filed on August 28, 2014, which requests approval of an additional $0.2 billion in costs incurred from January 1, 2014 through June 30, 2014.
In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the Westinghouse Design Control Document, as amended (DCD),DCD and the delays in the timing of approval of the DCD and issuance of the combined construction and operating licenses (COLs),COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the agreement entered into by Georgia Power, acting for itself and as agent for the Vogtle Owners, and the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement).Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling

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that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision toOn March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit in September 2013.affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (inin 2008 dollars (approximately $591 million in 2015 dollars).The Contractor also asserted it is entitled to further schedule extensions. Onextensions of the guaranteed substantial completion dates of

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April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 22, 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations, butallegations; however, the Contractor subsequently asserted estimated minimum damages related to the amended counterclaim (based on Georgia Power's ownership interest) of approximately $113 million in 2014 dollars (approximately $118 million in 2015 dollars). In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power doeshas not agree with eitheragreed to the proposed cost or schedule adjustmentsto any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during whichschedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Georgia Power's eighth VCM report filed in 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.
On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).
Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.
On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month

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Contractor delay, and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion.
Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.
Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in theits fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. While Georgia Power expectsIn addition, the ContractorIRS allocated production tax credits to employ mitigation effortseach of Plant Vogtle Units 3 and 4, which require the applicable unit to maintain the current project schedule and believes the Contractor is responsible for any related costs, Contractor performance and progressbe placed in recent months on the assembly and installation of the shield building and structural modules have resulted in additional schedule pressure.service before 2021.
Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.
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.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has increased generallyoccurred throughout the U.S. In particular, personal injury, property damage, and otherThis litigation has included claims for damages alleged to have been caused by CO2 and other emissions, coal combustion residuals,CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.matters.

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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 in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not

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anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See the NotesNote (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Other Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011.
Additionally, there are 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.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On June 17, 2014, the Georgia PSC approved Georgia Power's request to credit customers the portion of fuel cost related to the nuclear waste fund fee. The nuclear waste fund rider became effective July 1, 2014. The ultimate outcome of this matter cannot be determined at this time.
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, and Pension and Other Postretirement Benefits.
Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of Georgia Power's nuclear facilities, which include Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Georgia Power has retirement obligations related to various landfill sites, underground storage tanks, and asbestos removal. Georgia Power also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with Georgia Power's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Georgia Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Georgia Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Georgia Power under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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Recently Issued Accounting Standards
On May 28, 2014, theThe Financial Accounting Standards Board issuedBoard's (FASB) ASC 606, Revenue from Contracts with Customers. ASC 606, revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016.2017. Georgia Power is currently evaluatingcontinues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Georgia Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Georgia Power.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at SeptemberJune 30, 2014.2015. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangementsagreements to meet future capital and liquidity needs.

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See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.07 billion$774 million for the first ninesix months of 20142015 compared to $2.13 billion$843 million for the corresponding period in 2013.2014. The decrease was primarily due to fuel cost recovery and storm restoration costs,lower operating revenues, partially offset by higher retail operating revenues and lowerincreased fuel inventory additions.cost recovery. Net cash used for investing activities totaled $1.46 billion$891 million for the first ninesix months of 20142015 compared to $1.25 billion$917 million for the corresponding period in 2013 due to gross property additions2014 primarily related to installation of equipment to comply with environmental standards;standards and construction of transmission and distribution facilities; and purchase of nuclear fuel.facilities. Net cash used forprovided from financing activities totaled $577$117 million for the first ninesix months of 20142015 compared to $869$90 million used for financing activities in the corresponding period in 2013.2014. The decreaseincrease in cash used forprovided from financing activities is primarily due to borrowings from the FFB for the construction of Plant Vogtle Units 3 and 4, partially offset by FFB loan issuance costs and a reductionan increase in short-term debt.debt borrowings. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20142015 include increases of $819$468 million in property, plant, and equipment $502to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases of $550 million in long-term debt primarily due to borrowings from the FFB, and $175 million in deferred under recovered regulatory clause revenues and decreases of $836$231 million in short-term debt and $337 million in fossil fuel stock.long-term debt, respectively, to fund the continuous construction program and for general corporate purposes.
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, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $503 million$1.7 billion will be required through SeptemberJune 30, 20152016 to fund maturities and announced redemptions of long-term debt, including $98 milliondebt. See "Sources of certain pollution control revenue bonds reclassified to securities due within one year in anticipation of redemption in connection with unit retirement decisions. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information regarding unit retirement decisions. Also see FUTURE EARNINGS POTENTIAL – "PSC Matters – Renewables Development"Capital" herein for additional information regarding estimated purchased power contractual obligations.information.
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; the outcome of any legal challenges to the

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environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; 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. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.
Sources of Capital
Except as described below with respect to the DOE loan guarantees, Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory

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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.
On February 20, 2014,In addition, Georgia Power and the DOE entered intomay make borrowings through a loan guarantee agreement (Loan Guarantee Agreement), pursuant between Georgia Power and the DOE, the proceeds of which may be used to whichreimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Georgia Power is obligatedEligible Project Costs incurred through June 30, 2015 would allow for borrowings of up to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and also are secured by a first priority lien on (i) Georgia Power's 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit Facility, Georgia Power may make term loan borrowings through the FFB. Proceeds of borrowings made$2.2 billion under the FFB Credit Facility, will be used to reimburseof which Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46has borrowed $1.8 billion. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Eligible Project Costs incurred through SeptemberAs of June 30, 2014 would allow for borrowings of up to $2.0 billion under the FFB Credit Facility. Through September 30, 2014, Georgia Power has borrowed $1.0 billion under the FFB Credit Facility, leaving $1.0 billion of available borrowing ability.
2015, Georgia Power's current liabilities frequently exceedexceeded current assets because of the continued use of short-term debt as a funding sourceby $1.3 billion primarily due to meet scheduled maturitiesapproximately $1.9 billion of long-term debt due within one year and notes payable. For the remainder of 2015, Georgia Power expects to utilize borrowings through the FFB as the primary source of long-term borrowed funds. Georgia Power also intends to utilize operating cash flows, as well as cash needs, which can fluctuate significantly duecommercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, and equity contributions from Southern Company to the seasonality of the business.fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At SeptemberJune 30, 2014,2015, Georgia Power had approximately $63$24 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20142015 were as follows:
Expires(a)
Expires(a)
  
Expires(a)
   Due Within One Year
2016 2018 Total Unused
20162016 2018 Total Unused Term Out 
No Term
Out
(in millions)(in millions) (in millions)(in millions) (in millions) (in millions)
$150
 $1,600
 $1,750
 $1,736
$150
 $1,600
 $1,750
 $1,737
 $
 $150
(a)No credit arrangements expire in 2014, 2015, or 2017.
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.

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A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's variable rate pollution control revenue bonds and commercial paper borrowings.program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20142015 was approximately $865$970 million. In addition, at SeptemberJune 30, 2014,2015, Georgia Power had $65$122 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketedreoffered within the next 12 months.
Georgia Power'sMost of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Georgia Power. Such cross default provisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness or guarantee obligations over a specified threshold. Georgia Power is currently in compliance with all such covenants. None of the

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bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Georgia Power expects to renew or replace its credit arrangements, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
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 the other traditional operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
  
Short-term Debt at
September 30, 2014
 
Short-term Debt During the Period(a)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Commercial paper $211
 0.2% $278
 0.2% $644
  
Short-term Debt at
June 30, 2015
 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Commercial paper $200
 0.3% $370
 0.3% $598
Short-term bank debt 
 % 247
 0.8% 250
Total $200
 0.3% $617
 0.5%  
(a)(*)Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2014.2015.
ManagementGeorgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program,programs, lines of credit, short-term bank notes, and cash.operating cash flows.
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.

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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, interest rate derivatives, and construction of new generation.
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20142015 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB- and/or Baa3$86
$102
Below BBB- and/or Baa31,297
1,341
Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system 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, anya credit rating downgrade could impact Georgia Power's abilityaccess to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.
Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Georgia Power) on CreditWatch with negative implications.
Financing Activities
In February 2014,March 2015, Georgia Power entered into a $250 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes and the loan was repaid at maturity.
In April 2015, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power reoffered these bonds to the public in May 2015.
In April 2015, Georgia Power redeemed $125 million aggregate principal amount of its Series Y 5.80% Senior Notes due April 15, 2035.
In May 2015, Georgia Power reoffered to the public $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013, which had been previously purchased and held by Georgia Power since 2013.
In June 2015, Georgia Power made initialadditional borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion.$600 million. The interest rate applicable to $500the $600 million of the initial advance under the FFB Credit Facilityprincipal amount is 3.860%3.283% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029 and is expected to be reset from time to time thereafter through 2044. The final maturity date for all advances under the FFB Credit Facility isof February 20, 2044. The proceeds of the initial borrowings under the FFB Credit Facility were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. In connection with its entry into the

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agreements with the DOE and the FFB, Georgia Power incurred issuance costssettled $350 million of interest rate swaps related to this borrowing for approximately $66$6 million, which will be amortized to interest expense over the life of the borrowings under the FFB Credit Facility.10 years.
Under the Loan Guarantee Agreement, Georgia Power is subjectSubsequent to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of Georgia Power or Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. See Note 6 to the financial statements of Georgia Power in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.
In February 2014, Georgia Power repaid three four-month floating rate bank loans in an aggregate principal amount of $400 million.
In June 2014, Georgia Power redeemed $1730, 2015, $97.925 million aggregate principal amount of the Development Authority of BartowPutnam County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), Second Series 1998 and $19.5 million aggregate principal amount of Development Authority of Appling County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Hatch Project), Second Series 2001.
In July 2014, Georgia Power reoffered to the public $40 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant SchererBranch Project), First Series 2009, which had been previously purchased1996, First Series 1997, Second Series 1997, and held by Georgia Power since 2010.
Subsequent to September 30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amount of the swaps totaled $900 million.First Series 1998 were redeemed.
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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CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
2014
2013 2014 20132015
2014 2015 2014
(in thousands) (in thousands)(in millions) (in millions)
Operating Revenues:              
Retail revenues$365,971
 $335,916
 $979,435
 $901,343
$327
 $310
 $620
 $613
Wholesale revenues, non-affiliates33,689
 29,431
 103,616
 82,533
27
 34
 52
 70
Wholesale revenues, affiliates20,591
 16,701
 96,996
 65,206
13
 24
 35
 76
Other revenues18,083
 17,313
 48,950
 47,726
17
 16
 34
 32
Total operating revenues438,334
 399,361
 1,228,997
 1,096,808
384
 384
 741
 791
Operating Expenses:              
Fuel164,497
 136,216
 478,163
 397,409
122
 145
 232
 314
Purchased power, non-affiliates26,813
 17,180
 56,605
 41,369
25
 14
 50
 30
Purchased power, affiliates3,611
 15,829
 19,299
 30,075
9
 9
 17
 16
Other operations and maintenance85,097
 76,964
 250,425
 232,472
91
 82
 185
 164
Depreciation and amortization38,487
 37,345
 109,354
 111,479
40
 39
 60
 71
Taxes other than income taxes31,229
 28,051
 83,786
 75,437
28
 26
 56
 53
Total operating expenses349,734
 311,585
 997,632
 888,241
315
 315
 600
 648
Operating Income88,600
 87,776
 231,365
 208,567
69
 69
 141
 143
Other Income and (Expense):              
Allowance for equity funds used during construction3,195
 1,663
 8,276
 4,318
3
 3
 8
 5
Interest expense, net of amounts capitalized(12,859) (13,988) (39,417) (42,650)(12) (13) (26) (27)
Other income (expense), net(627) (337) (1,857) (2,704)(1) (1) (2) (1)
Total other income and (expense)(10,291) (12,662) (32,998) (41,036)(10) (11) (20) (23)
Earnings Before Income Taxes78,309
 75,114
 198,367
 167,531
59
 58
 121
 120
Income taxes29,511
 28,109
 74,228
 62,950
21
 22
 44
 45
Net Income48,798
 47,005
 124,139
 104,581
38
 36
 77
 75
Dividends on Preference Stock2,251
 2,251
 6,752
 5,453
3
 2
 5
 4
Net Income After Dividends on Preference Stock$46,547
 $44,754
 $117,387
 $99,128
$35
 $34
 $72
 $71
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
 2014 2013 2014 2013
 (in thousands) (in thousands)
Net Income$48,798
 $47,005
 $124,139
 $104,581
Other comprehensive income (loss):       
Qualifying hedges:       
Reclassification adjustment for amounts included in net income,
net of tax of $58, $58, $175 and $238 respectively
93
 93
 279
 379
Total other comprehensive income (loss)93
 93
 279
 379
Comprehensive Income$48,891
 $47,098
 $124,418
 $104,960
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2014 2013
 (in thousands)
Operating Activities:   
Net income$124,139
 $104,581
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total115,093
 116,626
Deferred income taxes29,359
 55,911
Allowance for equity funds used during construction(8,276) (4,318)
Pension, postretirement, and other employee benefits5,693
 9,279
Stock based compensation expense1,520
 1,389
Other, net(2,667) 2,509
Changes in certain current assets and liabilities —   
-Receivables(45,777) (49,690)
-Prepayments2,894
 2,568
-Fossil fuel stock44,300
 24,475
-Materials and supplies1,007
 (2,683)
-Prepaid income taxes8,627
 23,515
-Other current assets(1,022) 
-Accounts payable10,097
 (9,132)
-Accrued taxes21,858
 20,648
-Accrued compensation5,131
 (5,974)
-Over recovered regulatory clause revenues6,834
 (17,092)
-Other current liabilities4,939
 5,258
Net cash provided from operating activities323,749
 277,870
Investing Activities:   
Property additions(254,256) (205,161)
Cost of removal, net of salvage(9,309) (12,563)
Change in construction payables1,688
 6,752
Payments pursuant to long-term service agreements(6,097) (3,843)
Other investing activities89
 306
Net cash used for investing activities(267,885) (214,509)
Financing Activities:   
Decrease in notes payable, net(44,395) (65,077)
Proceeds —   
Common stock issued to parent50,000
 40,000
Capital contributions from parent company2,873
 1,936
Preference stock
 50,000
Pollution control revenue bonds42,075
 63,000
Senior notes200,000
 90,000
Redemptions —   
Pollution control revenue bonds(29,075) (63,000)
Senior notes
 (90,000)
Payment of preference stock dividends(6,752) (4,753)
Payment of common stock dividends(92,400) (86,550)
Other financing activities(2,951) (3,209)
Net cash provided from (used for) financing activities119,375
 (67,653)
Net Change in Cash and Cash Equivalents175,239
 (4,292)
Cash and Cash Equivalents at Beginning of Period21,753
 32,167
Cash and Cash Equivalents at End of Period$196,992
 $27,875
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $3,699 and $2,291 capitalized for 2014 and 2013, respectively)$28,574
 $33,433
Income taxes, net35,940
 (17,064)
Noncash transactions — accrued property additions at end of period34,876
 30,846
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)
Assets At September 30,
2014
 At December 31,
2013
  (in thousands)
Current Assets:    
Cash and cash equivalents $196,992
 $21,753
Receivables —    
Customer accounts receivable 98,357
 64,884
Unbilled revenues 63,950
 57,282
Under recovered regulatory clause revenues 52,531
 48,282
Other accounts and notes receivable 10,131
 8,620
Affiliated companies 7,405
 8,259
Accumulated provision for uncollectible accounts (1,695) (1,131)
Fossil fuel stock, at average cost 90,750
 135,050
Materials and supplies, at average cost 53,928
 54,935
Other regulatory assets, current 42,683
 18,536
Prepaid expenses 8,374
 33,186
Other current assets 3,805
 6,120
Total current assets 627,211
 455,776
Property, Plant, and Equipment:    
In service 4,444,015
 4,363,664
Less accumulated provision for depreciation 1,277,290
 1,211,336
Plant in service, net of depreciation 3,166,725
 3,152,328
Construction work in progress 433,299
 280,626
Total property, plant, and equipment 3,600,024
 3,432,954
Other Property and Investments 15,212
 15,314
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 54,856
 50,597
Prepaid pension costs 11,639
 11,533
Other regulatory assets, deferred 322,370
 340,415
Other deferred charges and assets 38,394
 30,982
Total deferred charges and other assets 427,259
 433,527
Total Assets $4,669,706
 $4,337,571
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)
Liabilities and Stockholder's Equity At September 30,
2014
 At December 31,
2013
  (in thousands)
Current Liabilities:    
Securities due within one year $75,000
 $75,000
Notes payable 91,483
 135,878
Accounts payable —    
Affiliated 82,258
 76,897
Other 55,713
 47,038
Customer deposits 35,188
 34,433
Accrued taxes —    
Accrued income taxes 16,124
 45
Other accrued taxes 29,777
 7,486
Accrued interest 17,808
 10,272
Accrued compensation 16,839
 11,657
Other regulatory liabilities, current 9,136
 13,408
Liabilities from risk management activities 7,337
 6,470
Other current liabilities 41,716
 22,972
Total current liabilities 478,379
 441,556
Long-term Debt 1,369,447
 1,158,163
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 746,866
 734,355
Accumulated deferred investment tax credits 3,101
 4,055
Employee benefit obligations 78,004
 76,338
Other cost of removal obligations 233,926
 228,148
Other regulatory liabilities, deferred 50,859
 56,051
Deferred capacity expense 168,574
 180,149
Other deferred credits and liabilities 78,671
 77,126
Total deferred credits and other liabilities 1,360,001
 1,356,222
Total Liabilities 3,207,827
 2,955,941
Preference Stock 146,504
 146,504
Common Stockholder's Equity:    
Common stock, without par value —    
Authorized — 20,000,000 shares    
Outstanding — September 30, 2014: 5,442,717 shares    
                — December 31, 2013: 4,942,717 shares 483,060
 433,060
Paid-in capital 557,664
 552,681
Retained earnings 275,481
 250,494
Accumulated other comprehensive loss (830) (1,109)
Total common stockholder's equity 1,315,375
 1,235,126
Total Liabilities and Stockholder's Equity $4,669,706
 $4,337,571
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Net Income$38
 $36
 $77
 $75
Other comprehensive income (loss)
 
 
 
Comprehensive Income$38
 $36
 $77
 $75
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Six Months
Ended June 30,
 2015 2014
 (in millions)
Operating Activities:   
Net income$77
 $75
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total64
 75
Deferred income taxes40
 20
Allowance for equity funds used during construction(8) (5)
Other, net11
 1
Changes in certain current assets and liabilities —   
-Receivables(15) (57)
-Fossil fuel stock6
 39
-Prepaid income taxes12
 9
-Other current assets1
 2
-Accounts payable(9) 1
-Accrued taxes15
 12
-Accrued compensation(10) 
-Over recovered regulatory clause revenues
 9
-Other current liabilities(1) (4)
Net cash provided from operating activities183
 177
Investing Activities:   
Property additions(148) (159)
Cost of removal, net of salvage(7) (6)
Other investing activities(19) (5)
Net cash used for investing activities(174) (170)
Financing Activities:   
Increase in notes payable, net4
 3
Proceeds —   
Common stock issued to parent20
 50
Pollution control revenue bonds
 42
Short-term borrowings40
 
Redemptions — Pollution control revenue bonds
 (29)
Payment of preference stock dividends(5) (5)
Payment of common stock dividends(65) (62)
Other financing activities2
 2
Net cash provided from (used for) financing activities(4) 1
Net Change in Cash and Cash Equivalents5
 8
Cash and Cash Equivalents at Beginning of Period39
 22
Cash and Cash Equivalents at End of Period$44
 $30
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $3 and $2 capitalized for 2015 and 2014, respectively)$26
 $26
Income taxes, net(9) 17
Noncash transactions — Accrued property additions at end of period28
 31
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)
Assets At June 30,
2015
 At December 31,
2014
  (in millions)
Current Assets:    
Cash and cash equivalents $44
 $39
Receivables —    
Customer accounts receivable 93
 73
Unbilled revenues 77
 58
Under recovered regulatory clause revenues 38
 57
Other accounts and notes receivable 9
 8
Affiliated companies 4
 10
Accumulated provision for uncollectible accounts (2) (2)
Fossil fuel stock, at average cost 95
 101
Materials and supplies, at average cost 55
 56
Other regulatory assets, current 72
 74
Prepaid expenses 35
 40
Other current assets 3
 2
Total current assets 523
 516
Property, Plant, and Equipment:    
In service 4,600
 4,495
Less accumulated provision for depreciation 1,234
 1,296
Plant in service, net of depreciation 3,366
 3,199
Other utility plant, net 77
 
Construction work in progress 387
 465
Total property, plant, and equipment 3,830
 3,664
Other Property and Investments 15
 15
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 59
 56
Other regulatory assets, deferred 406
 416
Other deferred charges and assets 41
 41
Total deferred charges and other assets 506
 513
Total Assets $4,874
 $4,708
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)
Liabilities and Stockholder's Equity At June 30,
2015
 At December 31,
2014
  (in millions)
Current Liabilities:    
Notes payable $154
 $110
Accounts payable —    
Affiliated 72
 87
Other 52
 56
Customer deposits 36
 35
Other accrued taxes 24
 9
Accrued interest 10
 11
Accrued compensation 13
 23
Deferred capacity expense, current 22
 22
Liabilities from risk management activities 32
 37
Other current liabilities 21
 23
Total current liabilities 436
 413
Long-term Debt 1,370
 1,370
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 852
 800
Employee benefit obligations 119
 121
Other cost of removal obligations 222
 235
Other regulatory liabilities, deferred 49
 49
Deferred capacity expense 152
 163
Other deferred credits and liabilities 187
 101
Total deferred credits and other liabilities 1,581
 1,469
Total Liabilities 3,387
 3,252
Preference Stock 147
 147
Common Stockholder's Equity:    
Common stock, without par value —    
Authorized — 20,000,000 shares    
Outstanding — June 30, 2015: 5,642,717 shares    
                — December 31, 2014: 5,442,717 shares 503
 483
Paid-in capital 564
 560
Retained earnings 274
 267
Accumulated other comprehensive loss (1) (1)
Total common stockholder's equity 1,340
 1,309
Total Liabilities and Stockholder's Equity $4,874
 $4,708
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

THIRDSECOND QUARTER 20142015 vs. THIRDSECOND QUARTER 20132014
AND
YEAR-TO-DATE 20142015 vs. YEAR-TO-DATE 20132014


OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service areaterritory 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 costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, restoration following major storms, and fuel. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future. Capacity revenues represent the majority of Gulf Power's wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's co-ownership of Plant Scherer Unit 3 (205 MWs) through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively evaluating strategic alternatives related to this asset, including replacement wholesale contracts, but the expiration of current contracts could have a material negative impact on Gulf Power's earnings.
Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS OVERVIEW "Key Performance Indicators" of Gulf Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1.8 4.0 $18.3 18.4
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$1 2.9 $1 1.4
Gulf Power's net income after dividends on preference stock for the thirdsecond quarter 20142015 was $46.5$35 million compared to $44.7$34 million for the corresponding period in 2013.2014. The increase was primarily due to higher retail revenues related to a base rate increase, partially offset by higher non-fuel operations and maintenance expenses.
Gulf Power's net income after dividends on preference stock for year-to-date 20142015 was $117.4$72 million compared to $99.1$71 million for the corresponding period in 2013.2014. The increase was primarily due to a reduction in depreciation, as authorized by the Florida PSC, and higher retail revenues related to a base rate increase, and colder weather in the first quarter 2014, partially offset by higher non-fuel operations and maintenance expenses.
Retail Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$30.1 8.9 $78.1 8.7
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$17 5.5 $7 1.1
In the thirdsecond quarter 2014,2015, retail revenues were $366.0$327 million compared to $335.9$310 million for the corresponding period in 2013.2014. For year-to-date 2014,2015, retail revenues were $979.4$620 million comparedcompared to $901.3$613 million for the corresponding period in 2013.2014.

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GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:
 Third Quarter
2014
 
Year-to-Date
 2014
 Second Quarter
2015
 
Year-to-Date
 2015
 (in millions) (% change) (in millions) (% change) (in millions) (% change) (in millions) (% change)
Retail – prior year $335.9
   $901.3
   $310
   $613
  
Estimated change resulting from –                
Rates and pricing 11.0
 3.3
 33.6
 3.7
 7
 2.3
 10
 1.7
Sales growth 6.1
 1.8
 7.7
 0.9
 2
 0.6
 
 
Weather (0.9) (0.3) 10.0
 1.1
 4
 1.3
 4
 0.6
Fuel and other cost recovery 13.9
 4.1
 26.8
 3.0
 4
 1.3
 (7) (1.2)
Retail – current year $366.0
 8.9 % $979.4
 8.7% $327
 5.5% $620
 1.1 %
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC"Retail Regulatory Matters" 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" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing increased in the thirdsecond quarter and year-to-date 20142015 when compared to the corresponding periods in 20132014 primarily due to an increase in retail base revenues resulting from the retailrates effective in January 2015, as authorized in a settlement agreement for Gulf Power's 2013 base rate increase effective January 2014case, and higher revenues associated with an increase in the environmental and energy conservation cost recovery clause raterates effective in January 2014.2015.
Revenues attributable to changes in sales increased in the thirdsecond quarter 20142015 when compared to the corresponding period in 2013.2014. Weather-adjusted KWH energy sales to residential and commercial customers increased 5.8%3.0% and 2.6%1.6%, respectively, due to customer growth and higher weather-adjusted use per customer usage. KWH energy sales to industrial customers decreased 2.8% primarily due to increased customer co-generation.
Revenues attributable to changes in sales remained essentially flat year-to-date 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH energy sales to residential and commercial customers decreased 0.9% and 0.1%, respectively, due to lower customer usage, partially offset by customer growth. KWH energy sales to industrial customers increased 6.4%decreased 2.7% primarily due to decreasedincreased customer co-generation and changes in customers' operations.
Revenues attributable to changes in sales increased year-to-date 2014 when compared to the corresponding period in 2013. Weather-adjusted KWH energy sales to residential customers increased 1.8% due to higher weather-adjusted use per customer and customer growth. Weather-adjusted KWH energy sales to commercial customers increased 0.3% due to customer growth, partially offset by a decline in weather-adjusted use per customer. KWH energy sales to industrial customers increased 11.0% due to decreased customer co-generation and changes in customers' operations.co-generation.
Fuel and other cost recovery revenues increased in the thirdsecond quarter 2014 and year-to-date 20142015 when compared to the corresponding periodsperiod in 20132014 primarily due to higher revenues associated with recoverable fuel costs for increased generation andrecoverable purchased power capacity costs, partially offset by lower revenues associated with fuel costs as the result of decreased generation and lower recoverable costs under Gulf Power'spurchased power energy conservationcosts. For year-to-date 2015, fuel and environmentalother cost recovery clauses. Recoverablerevenues decreased when compared to the corresponding period in 2014 primarily due to lower revenues associated with fuel costs include the effectas a result of a 2013 payment received pursuant to the resolution of a contract dispute.decreased generation and lower purchased power energy costs, partially offset by higher revenues associated with purchased power capacity costs.
Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See FUTURE EARNINGS POTENTIAL – "PSCNote 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" of Gulf Power in Item 78 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
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$4.3 14.5 $21.1 25.5
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(7) (20.6) $(18) (25.7)
Wholesale revenues from sales to non-affiliates consist of long-term sales agreements to other utilities in Florida and Georgia and short-term opportunity sales. Capacity revenues from long-term sales agreements represent the greatest contribution to net income. The energywholesale earnings. Energy is generally sold at variable cost.cost and does not have a significant impact on wholesale earnings. Short-term opportunity sales are made at market-based rates that generally provide a margin above Gulf Power's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
In the thirdsecond quarter 2014,2015, wholesale revenues from sales to non-affiliates were $33.7$27 million compared to $29.4$34 million for the corresponding period in 2013.2014. The increasedecrease was primarily due to a 25.4% increase43.5% decrease in KWH sales primarily to wholesale customersresulting from lower sales under the Plant Scherer Unit 3 long-term sales agreements.agreements due to a planned outage and lower natural gas prices that led to increased customer-owned generation.
For year-to-date 2014,year-to-date 2015, wholesale revenues from sales to non-affiliates were $103.6$52 million compared to $82.5$70 million for the corresponding period in 2013.2014. The increasedecrease was primarily due to a 59.9% increase52.1% decrease in KWH sales due to lower-priced supply alternativesresulting from lower sales under the Southern Company system's resources compared to wholesale market prices and a planned outage at Plant Scherer Unit 3 in 2013.long-term sales agreements due to a planned outage and lower natural gas prices that led to increased customer-owned generation.
Wholesale Revenues – Affiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$3.9 23.3 $31.8 48.8
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$(11) (45.8) $(41) (53.9)
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. 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 revenue related to these energy sales generally offsets the cost of energy sold.
In the thirdsecond quarter 2014,2015, wholesale revenues from sales to affiliates were $20.6$13 million compared to $16.7$24 million for the corresponding period in 2013.2014. The increasedecrease was primarily due to an 11.7% increasea 29.9% decrease in KWH sales that resulted from planned outages for Gulf Power generation resources and a 20.6% decrease in the price of energy sold to affiliates due to higher marginal generation costs andlower power pool interchange rates resulting from lower natural gas prices.
For year-to-date 2015, wholesale revenues from sales to affiliates were $35 million compared to $76 million for the corresponding period in 2014. The decrease was primarily due to a 10.3% increase37.2% decrease in KWH sales that resulted from moreplanned outages for Gulf Power generation dispatched to serve affiliated companies' higher weather-related energy demand.
For year-to-date 2014, wholesale revenues from sales to affiliates were $97.0 million compared to $65.2 million for the corresponding period in 2013. The increase was primarily due toresources and a 29.6% increase26.1% decrease in the price of energy sold to affiliates due to higher marginal generation costs and a 14.8% increase in KWH sales that resultedlower power pool interchange rates resulting from more Gulf Power generation dispatched to serve affiliated companies' higher weather-related energy demand in 2014.lower natural gas prices.

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GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses
  Third Quarter 2014
vs.
Third Quarter 2013
  Year-to-Date 2014
vs.
Year-to-Date 2013
  Second Quarter 2015
vs.
Second Quarter 2014
  Year-to-Date 2015
vs.
Year-to-Date 2014
 (change in millions) (% change) (change in millions) (% change) (change in millions) (% change) (change in millions) (% change)
Fuel $28.3
 20.8
 $80.8
 20.3
 $(23) (15.9) $(82) (26.1)
Purchased power – non-affiliates 9.6
 56.1
 15.2
 36.8
 11
 78.6
 20
 66.7
Purchased power – affiliates (12.2) (77.2) (10.8) (35.8) 
 
 1
 6.3
Total fuel and purchased power expenses $25.7
   $85.2
   $(12)   $(61)  
In the thirdsecond quarter 2014,2015, total fuel and purchased power expenses were $194.9$156 million compared to $169.2$168 million for the corresponding period in 2013. Total fuel and purchased power expenses for2014. The decrease was primarily the third quarter 2013 included the effectresult of a 2013 payment received pursuant to$9 million decrease in the resolution of a contract dispute. Excluding that effect, higher volume of KWHs generated and purchased increased expenses $12.5 million in the third quarter 2014 due to moreplanned outages for Gulf PowerPower's generation dispatched to serve affiliated companies' higher weather-related demand. This increase was offset byand a $7.3resource contracted under a PPA and a $3 million net decrease due to athe lower average cost of fuel and purchased power.
For year-to-date 2014,2015, total fuel and purchased power expenses were $554.1$299 million compared to $468.9$360 million for the corresponding period in 2013. Total fuel and purchased power expenses for2014. The decrease was primarily the first nine months of 2013 included the effectresult of a 2013 payment received pursuant to$50 million decrease in the resolution of a contract dispute. Excluding that effect, higher volume of KWHs generated and purchased increased expenses $62.3 million year-to-date 2014 primarily due to moreplanned outages for Gulf PowerPower's generation dispatched to serve affiliated companies' higher demand asand a result of colder weather in the first quarter 2014resource contracted under a PPA and warmer weather in the third quarter 2014 comparedan $11 million net decrease due to the corresponding periods in 2013. The increased expenses also included a $2.4 million increase due to a higherlower average cost of fuel and purchased power.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel cost and purchased power capacity recovery clauses. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" of Gulf Power in Item 8 of the Form 10-K for additional information.
Details of Gulf Power's generation and purchased power were as follows:
 Third Quarter
2014
 Third Quarter
2013
 
Year-to-Date
2014
 Year-to-Date 2013 Second Quarter
2015
 Second Quarter
2014
 Year-to-Date 2015 Year-to-Date 2014
Total generation (millions of KWHs)
 3,085 2,692 8,717 6,978 2,360 2,670 4,596 5,632
Total purchased power (millions of KWHs)
 1,479 1,593 4,190 4,602 1,336 1,281 2,594 2,711
Sources of generation (percent) –
  
Coal 66 64 69 62 61 69 60 70
Gas 34 36 31 38 39 31 40 30
Cost of fuel, generated (cents per net KWH) –
  
Coal(a)
 3.83 3.33 4.08 4.09 4.05 4.09 4.02 4.21
Gas 4.16 4.17 3.95 4.05 4.38 3.99 4.17 3.82
Average cost of fuel, generated (cents per net KWH)(a)
 3.94 3.64 4.04 4.07 4.18 4.06 4.08 4.09
Average cost of purchased power (cents per net KWH)(b)
 4.96 4.48 4.83 4.01
Average cost of purchased power (cents per net KWH)(*)
 4.25 4.71 4.31 4.75
(a)2013 cost of coal includes the effect of a payment received in 2013 pursuant to the resolution of a coal contract dispute.
(b)(*)Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.
Fuel
In the second quarter 2015, fuel expense was $122 million compared to $145 million for the corresponding period in 2014. The decrease was primarily due to an 11.6% decrease in the volume of KWHs generated due to planned outages for Gulf Power's generation and a resource contracted under a PPA. This was partially offset by a 3.0% increase in the average cost of fuel due to higher natural gas prices per KWH generated, which includes firm gas transportation and storage.

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Fuel
In the third quarter 2014,For year-to-date 2015, fuel expense was $164.5$232 million compared to $136.2$314 million for the corresponding period in 2013.2014. The decrease was primarily due to an 18.4% decrease in the volume of KWHs generated due to planned outages for Gulf Power's generation and a resource contracted under a PPA.
Purchased Power – Non-Affiliates
In the second quarter 2015, purchased power expense from non-affiliates was $25 million compared to $14 million for the corresponding period in 2014. The increase was primarily due to a 14.6% higher volume of KWHs generated due to more Gulf Power generation dispatched to serve affiliated companies' higher demand resulting from warmer weather in the third quarter 2014. The fuel expense for the third quarter 2013 included the effect of a 2013 payment received pursuant to the resolution of a coal contract dispute. Excluding this effect, the average cost of fuel decreased 10.5% primarily due to lower-priced coal supply.
For year-to-date 2014, fuel expense was $478.2 million compared to $397.4 million for the corresponding period in 2013. The increase was primarily due to a 24.9% higher volume of KWHs generated primarily due to more Gulf Power generation dispatched to serve affiliated companies' higher demand resulting from colder weather in the first quarter 2014 and warmer weather in the third quarter 2014 compared to the corresponding periods in 2013. The fuel expense for year-to-date 2013 included the effect of a 2013 payment received pursuant to the resolution of a coal contract dispute. Excluding this effect, the average cost of fuel decreased 7.6% primarily due to lower-priced coal supply.
Purchased Power – Non-Affiliates
In the third quarter 2014, purchased power expense from non-affiliates was $26.8 million compared to $17.2 million for the corresponding period in 2013. The increase was primarily due to a 30.4% increase in the average cost per KWH purchased, which included a $9.7$10 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA.PPA in mid-2014. The increase was partially offset by a 3.3%7.9% decrease in the volume of KWHs purchased due to the expiration of a Gulf Powerplanned outage for a resource contracted under a PPA.
For year-to-date 2014,2015, purchased power expense from non-affiliates was $56.6$50 million compared to $41.4$30 million for the corresponding period in 2013.2014. The increase was primarily due to a 34.9% increase in the average cost per KWH purchased, which included a $12.8$26 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA. ThisPPA in mid-2014. The increase was partially offset by an 11.7%a 17.4% decrease in the volume of KWHs purchased due to colder regional weather conditions in the first quarter 2014 which limited the availability of market resources.a planned outage for a resource contracted under a PPA.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the thirdsecond quarter 2015 and the corresponding period in 2014, purchased power expense from affiliates was $3.6 million compared to $15.8 million for the corresponding period in 2013.$9 million. The decrease was primarilyvolume of KWHs purchased increased 55.4% due to planned outages for Gulf Power's generation and a 67.0%resource contracted under a PPA. The increase was offset by a 39.1% decrease in the average cost per KWH purchased which included a $9.2 million reduction in capacity costs primarily associated with the expiration of an existing PPA, and a 31.8% decrease in the volume of KWHs purchased due to increased generation from Gulf Power's owned units in 2014.lower power pool interchange rates.
For year-to-date 2014,2015, purchased power expense from affiliates was $19.3$17 million compared to $30.1$16 million for the corresponding period in 2013.2014. The decreaseincrease was primarily due to a 44.8% decrease in the average cost per KWH purchased, which included a $12.8 million reduction in capacity costs primarily associated with the expiration of an existing PPA, partially offset by a 14.5%68.5% increase in the volume of KWHs purchased due to colder weather driving higher demandplanned outages for Gulf Power's generation and a resource contracted under a PPA, largely offset by a 36.0% decrease in the first quarter 2014 comparedaverage cost per KWH purchased due to the corresponding period in 2013.lower power pool interchange rates.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$9 11.0 $21 12.8
In the second quarter 2015, other operations and maintenance expenses were $91 million compared to $82 million for the corresponding period in 2014. The increase was primarily due to increases of $6 million in routine and planned maintenance expenses at generation and distribution facilities, $1 million in energy services expenses, $1 million in customer service expenses, and $1 million in employee benefits including pension costs.
For year-to-date 2015, other operations and maintenance expenses were $185 million compared to $164 million for the corresponding period in 2014. The increase was primarily due to increases of $11 million in routine and planned maintenance expenses at generation facilities, $2 million in energy services expenses, $2 million in customer service expenses, and $2 million in employee benefits including pension costs.

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Other Operations and Maintenance Expenses
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$8.2 10.6 $17.9 7.7
In the third quarter 2014, other operations and maintenance expenses were $85.1 million compared to $76.9 million for the corresponding period in 2013. The increase was primarily due to increases of $7.0 million in routine and planned maintenance expense at generation facilities, partially offset by a decrease of $1.8 million in marketing programs.
For year-to-date 2014, other operations and maintenance expenses were $250.4 million compared to $232.5 million for the corresponding period in 2013. The increase was primarily due to a $20.0 million increase in routine and planned maintenance expenses at generation, transmission, and distribution facilities, a $2.3 million net increase in employee compensation and benefits including pension costs, a $2.1 million increase in customer uncollectibles and collection expenses, and a $2.0 million increase in transmission service related to a third party PPA. These increases were partially offset by a $5.3 million decrease in marketing programs and a $2.9 million decrease in other energy services expenses.
The year-to-date 2014 increased expense from routine and planned maintenance at distribution facilities included $3.7 million in environmental projects that did not have a significant impact on net income since the expense was offset by environmental revenues through Gulf Power's environmental cost recovery clause. The increased expense from transmission service did not have a significant impact on net income since the expense was offset by purchased power capacity revenues through Gulf Power's purchased power capacity recovery clause. The decreased expense from marketing programs did not have a significant impact on net income since the expense was offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause. The decreased expense from other energy services did not have a significant impact on net incomeearnings since the expense wasthey were generally offset by associated revenues. See Note 3(F) to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Purchased Power Capacity Recovery," "– Environmental Cost Recovery," and "– Energy Conservation Cost Recovery" in Item 8 of the Form 10-KCondensed Financial Statements herein for additional information.information related to pension costs.
Depreciation and Amortization
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1.2 3.1 $(2.1) (1.9)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$1 2.6 $(11) (15.5)
In the thirdsecond quarter 2014,2015, depreciation and amortization was $38.5$40 million compared to $37.3$39 million for the corresponding period in 2013.2014. The increase in depreciation and amortization was primarily attributable to property additions at generation, transmission, and distribution facilities.
For year-to-date 2014,2015, depreciation and amortization was $109.4$60 million compared to $111.5$71 million for the corresponding period in 2013.2014. As authorized by the Florida PSC in a 2013 rate order,settlement agreement, Gulf Power recorded a $5.4$19.6 million reduction in depreciation expensein the first half of 2015 as compared to $5.4 million in the corresponding period in 2014. ThisThe decrease was partially offset by increases of $3.3$3 million in depreciation and amortization primarily attributable to property additions at generation, transmission, and distribution facilities.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC"Retail Regulatory Matters – Retail Base Rate Case" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" herein for additional information.

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Taxes Other Than Income Taxes
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$3.2 11.3 $8.4 11.1
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$2 7.7 $3 5.7
In the thirdsecond quarter 2014,2015, taxes other than income taxes were $31.2$28 million compared to $28.0$26 million for the corresponding period in 2013.2014. For year-to-date 2014,2015, taxes other than income taxes were $83.8$56 million compared to $75.4$53 million for the corresponding period in 2013.2014. The increases were primarily due to increases in property taxes, franchise fees, and gross receipts taxes as a result of higher retail revenues.taxes. Franchise fees and gross receipts taxes have no impact on net income.
Allowance for Equity Funds Used During Construction
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1.5 92.1 $4.0 91.7
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$—  $3 60.0
In the third quarter 2014,For year-to-date 2015, AFUDC equity was $3.2$8 million compared to $1.7$5 million for the corresponding period in 2013. For year-to-date 2014, AFUDC equity2014. The increase was $8.3 million compared to $4.3 million for the corresponding period in 2013. These increases were primarily due to increased construction related to environmental control projects at generation facilities.
Income Taxes
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1.4 5.0 $11.2 17.9
In the third quarter 2014, income taxes were $29.5 million compared to $28.1 million for the corresponding period in 2013. For year-to-date 2014, income taxes were $74.2 million compared to $63.0 million for the corresponding period in 2013. These increases were primarily due to higher pre-tax earnings.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of selling electricity. These factors include Gulf Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining and

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growing sales which isare subject to a number of factors. These factors include weather, competition, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, the rate of economic growth or decline in Gulf Power's service territory, and the successful remarketing of wholesale capacity as current contracts expire. Changes in regional and global economic conditions may impact sales for Gulf Power as 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.
Gulf Power's wholesale business consists of two types of agreements. The first type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's co-ownership of a unit with Georgia Power at Plant Scherer Unit 3 (205 MWs) and consist of both capacity and energy sales. Capacity revenues represent the majority of Gulf Power's

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wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's ownershipco-ownership of that unit through 2015 and 57%41% through 2018. The second type, referred to as requirements service, provides that2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power servesis actively evaluating strategic alternatives related to this asset, including replacement wholesale contracts, but the customer's capacity and energy requirements from otherexpiration of current contracts could have a material negative impact on Gulf Power resources.Power's earnings. In the event some portion of Gulf Power's ownership in Plant Scherer is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis.basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with 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. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" and "PSC"Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" 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.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR) and the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM).
On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.
On September 17, 2014,June 12, 2015, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreementfinal rule requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would requireaffected states subject to the rule (including Florida, Georgia, and Mississippi) to revise theiror remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSM provisions within 18 months after issuance of the final rule.by no later than November 22, 2016. The ultimate impact of the proposed SSMfinal rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.
The ultimate outcome of these matters cannot be determined at this time.
Water Quality
On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the

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outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On June 29, 2015, the U.S. Supreme Court issued a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate impact of this decision cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Florida and Georgia. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of federal jurisdiction under the CWA. If finalized as proposed,CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, theThe rule as proposed could have significant impacts on economic development projects which could affect customer demand growth.becomes effective August 28, 2015. The ultimate impact of the proposedfinal rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations – Water Quality" Coal Combustion Residuals" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.regulation of CCR.
On August 15, 2014,April 17, 2015, the EPA published athe Disposal of Coal Combustion Residuals from Electric Utilities final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became(CCR Rule) in the Federal Register, setting October 19, 2015 as the effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementationdate of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units.CCR Rule. The ultimate impact of this rule will depend on the outcome of any legal challenges andCCR Rule cannot be determined at this time.timeand will depend on Gulf Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Gulf Power recorded incremental asset retirement obligations (ARO) of approximately $75 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Gulf Power expects to periodically update these estimates.
In connection with a proposed settlement related to the closure of Plant Scholz, Gulf Power may incur additional AROs associated with CCR of approximately $15 million to $35 million.
See Note (A) to the Condensed Financial Statements herein for additional information regarding Gulf Power's AROs.

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Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.CO2 from fossil-fuel-fired electric generating units.
On June 18, 2014,August 3, 2015, the EPA publishedreleased pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the proposed Clean Power Plan, setting forthfinal rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to address CO2 emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and finalmeet EPA-mandated CO2 emission rate goalsrates for existing units. The EPA's final guidelines require state plans to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposedmeet interim CO2 performance standards for modifiedrates between 2022 and reconstructed fossil fuel-fired electric generating units. The2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, thatwhich could impactaffect future unit retirement and replacement decisions. Also, additional compliance costs could affectGulf Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, any resulting higher costs that are recoveredrates or through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system.market-based contracts. However, the ultimate financial and operational impact of the Cleanfinal rules on Gulf Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upondepend on numerous factors. These factors include:including the structure, timing, and contentSouthern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-relatedemissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
FERC Matters
Gulf Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Gulf Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Gulf Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Gulf Power) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including Gulf Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 23, 2014,26, 2015 filed their response with the U.S. Supreme Court struck down a portionFERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the EPA's programFlorida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for GHG permittingspecific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority toForm 10-K for additional information.

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tailor the statutory permitting thresholds. The ultimate impact of the U.S. Supreme Court's decision cannot be determined at this time.
PSC Matters
Retail Base Rate Case
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.
In December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $5.4$19.6 million reduction in depreciation expense in the first ninesix months of 2014.2015.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC"Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The recovery balance of each regulatory clause for Gulf Power is reported inSee Note (B) to the Condensed Financial Statements herein.herein for additional information.
Renewables
On October 22, 2014,April 16, 2015, the Florida PSC approved Gulf Power's annual rate clause requestthree energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. On May 5, 2015, the Florida PSC approved an energy purchase agreement for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2015. The net effectup to 178 MWs of the approved changes is a $41.2 million increasewind generation in annual revenue for 2015. The increased revenues will not have a significant impact on net income since most of the revenuescentral Oklahoma. Purchases under these agreements will be offset by expenses.
Retail Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery" offor energy only and will be recovered through Gulf Power in Item 7 and Note 1 and Note 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Cost Recovery Clauses – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
Gulf Power has establishedPower's fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first half of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested for 2014. Under recovered fuel costs at September 30, 2014 totaled $41.3 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.mechanism.
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 air quality and water standards, has increased generally

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occurred throughout the U.S. In particular, personal injury, property damage, and otherThis litigation included claims for damages alleged to have been caused by CO2 and other emissions, coal combustion residuals,CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.matters.
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 in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See the NotesNote (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with 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, and Pension and Other Postretirement Benefits.

95

GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to Gulf Power's combustion turbines at its Pea Ridge facility and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Gulf Power has retirement obligations related to various landfill sites, a barge unloading dock, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. Gulf Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Gulf Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Gulf Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Gulf Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Gulf Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Recently Issued Accounting Standards
On May 28, 2014, theThe Financial Accounting Standards Board issuedBoard's (FASB) ASC 606, Revenue from Contracts with Customers. ASC 606, revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016.2017. Gulf Power is currently evaluatingcontinues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Gulf Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Gulf Power.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at SeptemberJune 30, 2014.2015. Gulf Power intends to continue to monitor its access to short-term and long-term

96

GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

capital markets as well as its bank credit arrangementsagreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $323.7$183 million for the first ninesix months of 20142015 compared to $277.9$177 million for the corresponding period in 2013.2014. The $45.8$6 million increase in net cash was primarily due to changesincreases in cash flows related to clausecost recovery a decrease in fossil fuel stock,clauses and an increase in accounts payable,deferred income taxes related to bonus depreciation, partially offset by a decreasedecreases in deferred income taxes.the timing of fossil fuel stock purchases, accrued compensation, and accounts payable. Net cash used for investing activities totaled $267.9$174 million in the first ninesix months of 20142015 primarily due to property additions to utility plant. Net cash provided fromused for financing activities totaled $119.4$4 million for the first ninesix months of 20142015 primarily due to the issuance of long-term debt and common stock, partially offset by the payment of common stock dividends, partially offset by an increase in notes payable and the redemptionissuance of long-term debt.common stock to Southern Company. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20142015 include increases of $211.3 million in long-term debt, $175.2 million in cash and cash equivalents, $167.1$166 million in net property, plant, and equipment, and $50.0

93

GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$86 million in common stock dueother deferred credits and other liabilities primarily related to AROs associated with the issuance of common stockCCR Rule, $52 million in accumulated deferred income tax liabilities primarily related to Southern Company. Decreases included $44.4bonus depreciation, and $44 million in notes payable and $44.3 million in fossil fuel stock resulting from an increase in KWH generation.payable.
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, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $75$60 million waswill be required through SeptemberJune 30, 20152016 to fund maturitiesannounced redemptions of long-term debt. Subsequent to September 30, 2014, Gulf Power repaid at maturity the $75 million of securities due within one year.See "Financing Activities" herein for additional information.
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; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in the expected environmental compliance programs; 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, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of 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. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs.needs, including its commercial paper program which is supported by bank credit facilities.

97

GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At SeptemberJune 30, 2014,2015, Gulf Power had approximately $197.0$44 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20142015 were as follows:
Expires(a)
Expires(a)
     
Executable Term
Loans
 
Due Within One
Year
Expires(a)
     
Executable Term
Loans
 
Due Within One
Year
2014 2015 2016 2017 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
20152015 2016 2017 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions)(in millions) (in millions) (in millions) (in millions)(in millions) (in millions) (in millions) (in millions)
$20
 $60
 $165
 $30
 $275
 $275
 $50
 $
 $50
 $30
20
 $225
 $30
 $275
 $275
 $50
 $
 $50
 $195
(a)No credit arrangements expire in 2018.
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.
Most of the unused credit arrangements with banks is allocated to provide liquidity support to Gulf Power's variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $69 million. In addition, at June 30, 2015, Gulf Power had approximately $46 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross default provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness

94

GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

or guarantee obligations over a specified threshold. Gulf Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration.
A portion of the unused credit arrangements with banks provide liquidity support to Gulf Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2014 was approximately $69 million. In addition, at September 30, 2014,connection therewith, Gulf Power had $78 million of fixed rate pollution control revenue bonds that are required to be remarketed withinmay extend the next 12 months.maturity dates and/or increase or decrease the lending commitments thereunder.
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 the other traditional operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
  Short-term Debt at
September 30, 2014
 
Short-term Debt During the Period(a)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Commercial paper $92
 0.2% $106
 0.2% $139
  
Short-term Debt at
June 30, 2015
 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Commercial paper $114
 0.3% $133
 0.3% $175
Short-term bank debt 40
 1.3% 10
 1.3% 40
Total $154
 0.6% $143
 0.4%  
(a)(*)Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2014.2015.
ManagementGulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and cash.operating cash flows.

98

GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk
Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at SeptemberJune 30, 20142015 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB- and/or Baa3$74
$91
Below BBB- and/or Baa3425
481
Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system 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 and the variable rate pollution control revenue bond market.
Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Gulf Power) on CreditWatch with negative implications.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the thirdsecond quarter 2014and year-to-date 2015 has not changed materially compared to the December 31, 20132014 reporting period. Gulf Power's exposure to market volatility in

95

GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreements shift substantially all fuel cost responsibility to the purchaser. However, Gulf Power could become exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and 57%41% through 2018.2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively pursuing replacement wholesale contracts but the expiration of current contracts could have a material negative impact on Gulf Power's earnings. In the event some portion of Gulf Power's ownership in Plant Scherer is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market. For an in-depth discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.
Financing Activities
In January 2014,2015, Gulf Power issued 500,000200,000 shares of common stock to Southern Company and realized proceeds of $50$20 million. The proceeds were used to repay a portion of Gulf Power's short-term debt and for other general corporate purposes, including Gulf Power's continuous construction program.
In April 2014,June 2015, Gulf Power executedentered into a three-month floating rate bank loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075bearing interest based on one-month LIBOR. This short-term loan was for $40 million aggregate principal amount of Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 forand the benefit of Gulf Power. The proceeds were used for credit support, working capital, and other general corporate purposes.
Subsequent to redeem $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).
In June 2014,30, 2015, Gulf Power reoffered to the publicpurchased and held $13 million aggregate principal amount of MBFCMississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Refunding Bonds Series 2012 (Gulf Power Company Project), which had been previously purchased and held bySeries 2012. Gulf Power since December 2013.reoffered these bonds on July 16, 2015.

99

In September 2014,GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to June 30, 2015, Gulf Power issued $200announced the redemption in September 2015 of $60 million aggregate principal amount of its Series 2014A 4.55%L 5.65% Senior Notes due OctoberSeptember 1, 2044. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power's continuous construction program, and subsequent to September 30, 2014, for repayment at maturity $75 million aggregate principal amount of Gulf Power's Series K 4.90% Senior Notes due October 1, 2014.2035.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm-recovery,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.

96100



MISSISSIPPI POWER COMPANY

97101



MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)
 
For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
2014 2013 2014 20132015 2014 2015 2014
(in thousands) (in thousands)(in millions) (in millions)
Operating Revenues:              
Retail revenues$228,331
 $230,710
 $646,695
 $613,274
$189
 $211
 $357
 $418
Wholesale revenues, non-affiliates82,952
 82,937
 254,642
 219,984
63
 75
 141
 172
Wholesale revenues, affiliates38,639
 6,999
 81,593
 31,242
18
 20
 45
 43
Other revenues4,701
 4,560
 13,829
 13,075
5
 5
 9
 9
Total operating revenues354,623
 325,206
 996,759
 877,575
275
 311
 552
 642
Operating Expenses:              
Fuel168,708
 138,148
 458,976
 384,905
115
 143
 229
 290
Purchased power, non-affiliates3,475
 2,077
 16,163
 5,222
2
 1
 3
 13
Purchased power, affiliates1,966
 14,691
 16,630
 28,302
2
 6
 4
 15
Other operations and maintenance65,758
 56,907
 191,923
 166,175
68
 61
 144
 125
Depreciation and amortization23,382
 22,202
 70,318
 67,644
30
 24
 57
 47
Taxes other than income taxes22,344
 21,071
 63,198
 60,760
23
 20
 48
 41
Estimated loss on Kemper IGCC418,000
 150,000
 798,000
 1,062,000
23
 
 32
 380
Total operating expenses703,633
 405,096
 1,615,208
 1,775,008
263
 255
 517
 911
Operating Income (Loss)(349,010) (79,890) (618,449) (897,433)12
 56
 35
 (269)
Other Income and (Expense):              
Allowance for equity funds used during construction32,223
 32,624
 107,685
 87,740
25
 37
 53
 75
Interest expense, net of amounts capitalized(9,416) (8,728) (34,071) (29,526)30
 (13) 19
 (25)
Other income (expense), net(7,764) (375) (11,496) (4,184)(1) (1) (2) (4)
Total other income and (expense)15,043
 23,521
 62,118
 54,030
54
 23
 70
 46
Earnings (Loss) Before Income Taxes(333,967) (56,369) (556,331) (843,403)66
 79
 105
 (223)
Income taxes (benefit)(139,330) (32,687) (253,007) (355,156)16
 16
 20
 (114)
Net Income (Loss)(194,637) (23,682) (303,324) (488,247)50
 63
 85
 (109)
Dividends on Preferred Stock433
 433
 1,299
 1,299
1
 1
 1
 1
Net Income (Loss) After Dividends on Preferred Stock$(195,070) $(24,115) $(304,623) $(489,546)$49
 $62
 $84
 $(110)
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
 2014 2013 2014 2013
 (in thousands) (in thousands)
Net Income (Loss)$(194,637) $(23,682) $(303,324) $(488,247)
Other comprehensive income (loss):       
Qualifying hedges:       
Reclassification adjustment for amounts included in net income,
net of tax of $131, $131, $394 and $394, respectively
212
 212
 637
 637
Total other comprehensive income (loss)212
 212
 637
 637
Comprehensive Income (Loss)$(194,425) $(23,470) $(302,687) $(487,610)
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Net Income (Loss)$50
 $63
 $85
 $(109)
Other comprehensive income (loss)
 
 
 
Comprehensive Income (Loss)$50
 $63
 $85
 $(109)
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

98102



MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Nine Months
Ended September 30,
 2014 2013
 (in thousands)
Operating Activities:   
Net income (loss)$(303,324) $(488,247)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —   
Depreciation and amortization, total77,774
 68,436
Deferred income taxes158,552
 (391,143)
Investment tax credits(108,171) 45,228
Allowance for equity funds used during construction(107,685) (87,740)
Regulatory assets associated with Kemper IGCC(51,875) (23,545)
Estimated loss on Kemper IGCC798,000
 1,062,000
Kemper regulatory deferral111,828
 61,997
Other, net12,105
 23,697
Changes in certain current assets and liabilities —   
-Receivables(30,452) (40,003)
-Under recovered regulatory clause revenues(17,845) 
-Fossil fuel stock35,917
 59,608
-Materials and supplies(9,080) (8,029)
-Prepaid income taxes(90,401) 33,793
-Other current assets5,173
 (1,710)
-Accounts payable27,511
 17,397
-Accrued taxes(17,032) (2,334)
-Accrued interest23,939
 15,153
-Accrued compensation7,993
 (8,543)
-Over recovered regulatory clause revenues(18,358) (49,247)
-Other current liabilities154
 
Net cash provided from operating activities504,723
 286,768
Investing Activities:   
Property additions(986,019) (1,221,519)
Cost of removal, net of salvage(7,431) (5,769)
Construction payables(40,301) (6,200)
Capital grant proceeds
 4,500
Investment in restricted cash(10,548) 
Distribution of restricted cash9,104
 
Proceeds from asset sales
 79,020
Other investing activities(14,804) (3,659)
Net cash used for investing activities(1,049,999) (1,153,627)
Financing Activities:   
Proceeds —   
Capital contributions from parent company310,860
 601,197
Bonds — Other22,866
 31,092
Interest-bearing refundable deposit75,000
 
Long-term debt issuance to parent company220,000
 
Other long-term debt issuances250,000
 475,000
Redemptions —   
Bonds — Other
 (82,563)
Capital leases(1,893) (82)
Long-term debt to parent company(220,000) 
Other long-term debt
 (125,000)
Payment of preferred stock dividends(1,299) (1,299)
Payment of common stock dividends
 (71,956)
Return of capital(164,790) (60,614)
Other financing activities(687) (1,845)
Net cash provided from financing activities490,057
 763,930
Net Change in Cash and Cash Equivalents(55,219) (102,929)
Cash and Cash Equivalents at Beginning of Period145,165
 145,008
Cash and Cash Equivalents at End of Period$89,946
 $42,079
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (paid $55,376 and $53,450, net of $50,446 and $37,882
capitalized for 2014 and 2013, respectively)
$4,930
 $15,568
Income taxes, net(210,465) (48,307)
Noncash transactions — accrued property additions at end of period123,894
 208,663
Noncash transactions — capital lease obligation
 82,915
 For the Six Months
Ended June 30,
 2015 2014
 (in millions)
Operating Activities:   
Net income (loss)$85
 $(109)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —   
Depreciation and amortization, total55
 50
Deferred income taxes694
 (108)
Investment tax credits32
 28
Allowance for equity funds used during construction(53) (75)
Regulatory assets associated with Kemper IGCC(50) (26)
Estimated loss on Kemper IGCC32
 380
Income taxes receivable, non-current(544) 
Other, net8
 7
Changes in certain current assets and liabilities —   
-Receivables6
 (32)
-Fossil fuel stock5
 32
-Prepaid income taxes24
 (12)
-Other current assets(7) (5)
-Accounts payable(25) 4
-Accrued taxes(51) (23)
-Accrued interest(7) 13
-Accrued compensation(12) 4
-Over recovered regulatory clause revenues32
 (18)
-Mirror CWIP82
 67
-Other current liabilities3
 1
Net cash provided from operating activities309
 178
Investing Activities:   
Property additions(428) (692)
Construction payables(15) (28)
Other investing activities(17) (13)
Net cash used for investing activities(460) (733)
Financing Activities:   
Increase in notes payable, net475
 
Proceeds —   
Capital contributions from parent company77
 211
Bonds — Other
 12
Interest-bearing refundable deposit
 75
Long-term debt issuance to parent company
 220
Other long-term debt issuances
 250
Short-term borrowings30
 
Redemptions — Other long-term debt(350) 
Payment of preferred stock dividends(1) (1)
Return of capital
 (110)
Other financing activities(1) (1)
Net cash provided from financing activities230
 656
Net Change in Cash and Cash Equivalents79
 101
Cash and Cash Equivalents at Beginning of Period133
 145
Cash and Cash Equivalents at End of Period$212
 $246
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (paid $39 and $37, net of $37 and $29 capitalized for 2015 and 2014, respectively)$2
 $8
Income taxes, net(181) (34)
Noncash transactions —   
Accrued property additions at end of period99
 136
Issuance of promissory note to parent related to repayment of
    interest-bearing refundable deposits and accrued interest
301
 

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At September 30,
2014
 At December 31,
2013
 At June 30,
2015
 At December 31,
2014
 (in thousands) (in millions)
Current Assets:        
Cash and cash equivalents $89,946
 $145,165
 $212
 $133
Receivables —        
Customer accounts receivable 53,593
 40,978
 44
 43
Unbilled revenues 38,575
 38,895
 37
 35
Under recovered regulatory clause revenues 17,845
 
Other accounts and notes receivable 3,995
 4,600
 11
 11
Affiliated companies 53,682
 34,920
 43
 51
Accumulated provision for uncollectible accounts (1,980) (3,018) (1) (1)
Fossil fuel stock, at average cost 77,368
 113,285
 95
 100
Materials and supplies, at average cost 55,166
 45,347
 69
 62
Other regulatory assets, current 53,854
 52,496
 69
 73
Prepaid income taxes 162,790
 34,751
 193
 191
Other current assets 4,676
 9,357
 7
 6
Total current assets 609,510
 516,776
 779
 704
Property, Plant, and Equipment:        
In service 4,323,501
 3,458,770
 4,456
 4,378
Less accumulated provision for depreciation 1,149,432
 1,095,352
 1,194
 1,173
Plant in service, net of depreciation 3,174,069
 2,363,418
 3,262
 3,205
Construction work in progress 1,987,789
 2,586,031
 2,543
 2,161
Total property, plant, and equipment 5,161,858
 4,949,449
 5,805
 5,366
Other Property and Investments 6,863
 4,857
 6
 5
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 197,278
 139,834
 260
 226
Other regulatory assets, deferred 255,430
 200,620
 482
 385
Accumulated deferred income taxes 25,255
 
Income taxes receivable, non-current 544
 
Other deferred charges and assets 54,929
 36,673
 71
 71
Total deferred charges and other assets 532,892
 377,127
 1,357
 682
Total Assets $6,311,123
 $5,848,209
 $7,947
 $6,757
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.


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MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity At September 30,
2014
 At December 31,
2013
 At June 30,
2015
 At December 31,
2014
 (in thousands) (in millions)
Current Liabilities:        
Securities due within one year $811,751
 $13,789
 $429
 $778
Interest-bearing refundable deposit 225,000
 150,000
Notes payable 505
 
Interest-bearing refundable deposits 
 275
Accounts payable —        
Affiliated 90,488
 70,299
 88
 86
Other 177,212
 210,191
 136
 178
Customer deposits 14,946
 14,379
Accrued taxes —        
Accrued income taxes 92,018
 5,590
 
 142
Other accrued taxes 65,375
 77,958
 47
 84
Accrued interest 70,956
 47,144
 13
 76
Accrued compensation 17,317
 9,324
 14
 26
Other regulatory liabilities, current 10,138
 24,981
Over recovered regulatory clause liabilities 
 18,358
 33
 1
Mirror CWIP 353
 271
Other current liabilities 21,634
 21,413
 59
 61
Total current liabilities 1,596,835
 663,426
 1,677
 1,978
Long-term Debt 1,633,394
 2,167,067
Long-term Debt:    
Long-term debt, affiliated 301
 
Long-term debt, non-affiliated 1,623
 1,630
Total Long-term Debt 1,924
 1,630
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 159,061
 72,808
 844
 285
Deferred credits related to income taxes 6,639
 9,145
Accumulated deferred investment tax credits 283,382
 284,248
 282
 283
Employee benefit obligations 94,539
 94,430
 146
 148
Asset retirement obligations 42,624
 41,197
 148
 48
Other cost of removal obligations 162,274
 151,340
 170
 166
Other regulatory liabilities, deferred 263,531
 140,880
 65
 64
Other deferred credits and liabilities 15,037
 14,337
 410
 38
Total deferred credits and other liabilities 1,027,087
 808,385
 2,065
 1,032
Total Liabilities 4,257,316
 3,638,878
 5,666
 4,640
Redeemable Preferred Stock 32,780
 32,780
 33
 33
Common Stockholder's Equity:        
Common stock, without par value —        
Authorized — 1,130,000 shares        
Outstanding — 1,121,000 shares 37,691
 37,691
 38
 38
Paid-in capital 2,525,056
 2,376,595
 2,692
 2,612
Accumulated deficit (534,493) (229,871) (475) (559)
Accumulated other comprehensive loss (7,227) (7,864) (7) (7)
Total common stockholder's equity 2,021,027
 2,176,551
 2,248
 2,084
Total Liabilities and Stockholder's Equity $6,311,123
 $5,848,209
 $7,947
 $6,757
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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THIRDSECOND QUARTER 20142015 vs. THIRDSECOND QUARTER 20132014
AND
YEAR-TO-DATE 20142015 vs. YEAR-TO-DATE 20132014


OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory 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 Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment to maintain and grow energy sales given economic conditions, and to effectively manage and securethat provides timely recovery of prudently-incurred costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, restoration following major storms, and the completion and operation of ongoingmajor construction projects, primarily the Kemper IGCC.IGCC and the Plant Daniel scrubber project, projected long-term demand growth, reliability, fuel, and increasingly stringent environmental standards, as well as ongoing capital expenditures required for maintenance. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
On October 27, 2014,In 2010, the Mississippi Power further revised itsPSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate forof the Kemper IGCC to approximately $4.86established by the Mississippi PSC was $2.4 billion with a construction cost cap of $2.88 billion, net of $245.3$245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The revised
Mississippi Power's current cost estimate primarily reflects costs related to the extension of the project schedule for the Kemper IGCC as a resultin total is approximately $6.23 billion, which includes approximately $4.96 billion of matters relatedcosts subject to the time expected to be required for start-up activities and operational readiness, including enhancing the scope of specialized operator training.
construction cost cap. Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction and start-up of the Kemper IGCCcosts that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. As a result of the revised cost estimate, Mississippi Power recorded pre-tax charges to income for revisions to the estimated probable losses on the Kemper IGCCcost estimate of $418.0$23 million ($258.114 million after tax) in the thirdsecond quarter 2014 resulting in an estimated probable loss of $798.02015 and $9 million ($492.86 million after tax) forin the first nine months of 2014. Inquarter 2015. Since 2012, in the aggregate, Mississippi Power has incurred charges of $1.98$2.08 billion ($1.221.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through SeptemberJune 30, 2014.2015.
Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC project in service onin August 9, 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016. The revisedcurrent cost estimate above includes costs through March 31, 2016. As a result of the additional factors that have the potential to impact start-up and operational readiness activities for this first-of-a-kind technology as described herein, the risk of further schedule extensions and/or cost increases, which could be material, remains.
For additional information on the Kemper IGCC, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" 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 and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
On February 12, 2015, the Mississippi Supreme Court (Court) issued its decision in a legal challenge with respect to the Mississippi PSC's March 2013 order that authorized the collection of $156 million annually (2013 MPSC Rate Order) to be recorded as Mirror CWIP. The Court reversed the 2013 MPSC Rate Order, deemed the 2013

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Settlement Agreement (defined below) between Mississippi Power and the Mississippi PSC unenforceable due to a lack of public notice for the related proceedings, and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts collected pursuant to the 2013 MPSC Rate Order. As of June 30, 2015, $331 million had been collected by Mississippi Power. On March 12, 2015, Mississippi Power and the Mississippi PSC filed motions for rehearing, and, on June 11, 2015, the Court issued its final decision, rejecting both Mississippi Power's and the Mississippi PSC's motions for rehearing and requiring that a rate refund be made and that the Mirror CWIP rate be terminated. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information.
Prior to the Court's final decision on June 11, 2015, Mississippi Power sought alternate rate recovery and filed a rate case on May 15, 2015 (2015 Rate Case). Mississippi Power's 2015 Rate Case presented the Mississippi PSC with three alternative rate proposals: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). RMP 2019 contemplated the total Mirror CWIP funds collected would be used to offset the retail revenue requirements over the life of the plan. However, in light of the Court's mandate and the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
On May 20, 2015, SMEPA notified Mississippi Power of its termination of the asset purchase agreement (APA) between Mississippi Power and SMEPA whereby SMEPA previously agreed to purchase a 15% undivided interest in the Kemper IGCC. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
The return of approximately $301 million to SMEPA in June 2015 in connection with the termination of the APA, the required refund of the approximately $353 million of Mirror CWIP rate collections, including associated carrying costs, and the termination of the Mirror CWIP rates have adversely impacted Mississippi Power's ability to obtain financing needed for its business operations.
As a result, on July 10, 2015, Mississippi Power submitted a supplemental filing with the Mississippi PSC that includes a request for interim rates (Supplemental Notice) until such time as the Mississippi PSC renders a final decision on an additional alternative rate proposal (In-Service Asset Proposal). The Supplemental Notice was filed in response to the Mississippi PSC's July 7, 2015 order and presents the In-Service Asset Proposal for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016 and is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.
As of June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $1 billion at September$898 million primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying

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costs through June 30, 2014, primarily because2015. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of securities due within a year. ManagementKemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information. In addition, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company that matures on December 2, 2016 in conjunction with the repayment of SMEPA's deposits with interest, following the termination of SMEPA's planned purchase of 15% of the Kemper IGCC project. Furthermore, Mississippi Power expects to fund the cash component of the Mirror CWIP refund with an intercompany loan from Southern Company. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions and/or loans from Southern Company and cash, as well as commercial paper, lines of credit, and bank notes, as market conditions permit, to fund Mississippi Power's short-term capital needs.
Mississippi Power continues to focus on several key performance indicators, including the construction, start-up, and rate recovery of the Kemper IGCC. 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. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding revisions to the cost estimate for the Kemper IGCC and the Court's decision that have negatively impacted Mississippi Power's actual performance on net income after dividends on preferred stock, one of its key performance indicators, for 2014,2015, as compared to the target.
RESULTS OF OPERATIONS
Net Income (Loss)
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(171.0) N/M $184.9 37.8
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(13) (21.0) $194 N/M
N/M – NotM-Not meaningful
Mississippi Power's net lossincome after dividends on preferred stock for the thirdsecond quarter 20142015 was $195.1$49 million compared to $24.1$62 million for the corresponding period in 2013.2014. The changedecrease was primarily related to a $418.0$23 million in pre-tax chargecharges ($258.114 million after tax) in the thirdsecond quarter 2014 compared to a $150.0 million pre-tax charge ($92.6 million after tax) in the third quarter 20132015 for a revisionrevisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. The changedecrease in net income was also related to a decrease in AFUDC equity, increases in non-fuel operations and maintenance expenses, an increase in depreciation and amortization, and a decrease in retail revenues primarily resulting from the Court's decision, partially offset by an increasea decrease in revenues primarily due to retail and wholesale base rate increases and the recognition as revenue of a portion of the retail rate increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013.interest expense.
For year-to-date 2014, the2015, net lossincome after dividends on preferred stock was $304.6$84 million compared to $489.5a net loss of $110 million for the corresponding period in 2013.2014. The changeincrease was primarily related to a $798.0$32 million in pre-tax chargecharges ($492.820 million after tax) in 20142015 compared to $1.06 billion$380 million in pre-tax charges ($655.8235 million after tax) in 20132014 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. The changeincrease in net income was also related to an increasea decrease in interest expense, partially offset by a decrease in AFUDC equity, primarily related to the construction of the Kemper IGCC and an increase in revenues primarily due to retail and wholesale base rate increases and the recognition as revenue of a portion of the retail rate increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013. The change was partially offset by increases in non-fuel operations and maintenance expenses.expenses, an increase in depreciation and amortization, and a decrease in retail revenues primarily resulting from the Court's decision.
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" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

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Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information. Also see "Interest Expense, Net of Amounts Capitalized" herein for additional information.
Retail Revenues
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(2.4) (1.0) $33.4 5.4
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(22) (10.4) $(61) (14.6)
In the thirdsecond quarter 2014,2015, retail revenues were $228.3$189 million compared to $230.7$211 million for the corresponding period in 2013.2014. For year-to-date 2014,2015, retail revenues were $646.7$357 million compared to $613.3$418 million for the corresponding period in 2013.2014.
Details of the changes in retail revenues were as follows:
 Third Quarter
2014
 
Year-to-Date
 2014
 Second Quarter
2015
 
Year-to-Date
 2015
 (in millions)
(% change) (in millions) (% change) (in millions)
(% change) (in millions) (% change)
Retail – prior year $230.7
   $613.3
   $211
   $418
  
Estimated change resulting from –                
Rates and pricing 2.8
 1.2
 16.4
 2.7
 (6) (2.7) (9) (2.2)
Sales decline (3.3) (1.4) (3.6) (0.6) (1) (0.6) (5) (1.2)
Weather 4.8
 2.1
 6.3
 1.0
 2
 0.9
 1
 0.2
Fuel and other cost recovery (6.7) (2.9) 14.3
 2.3
 (17) (8.0) (48) (11.4)
Retail – current year $228.3
 (1.0)% $646.7
 5.4 % $189
 (10.4)% $357
 (14.6)%
Revenues associated with changes in rates and pricing increaseddecreased in the thirdsecond quarter 2014and year-to-date 2015 when compared to the corresponding periodperiods in 20132014 primarily due to $7 million and $11 million, respectively, of revenues associated with the collection of Kemper IGCC cost recovery revenues,recognized in 2014, which ceased in 2015 as a result of the majority of which were deferred to a regulatory liability. The collected revenue for thirdCourt's decision, partially offset by $1 million in the second quarter 2014 was $47.62015 and $2 million compared to $37.0 millionyear-to-date 2015 in net revenues for the corresponding period in 2013, with deferrals of $41.8 million in 2014 and $34.0 million in 2013.
Revenues associated with changes in rates and pricing increased year-to-date 2014 when compared to the corresponding period in 2013 due to the collection of Kemper IGCCnew energy efficiency cost recovery revenues,rate, which began in the majority of which were deferred to a regulatory liability, and a $2.8 million PEP base rate increase, which both became effective March 2013. The collected Kemper IGCC cost recovery revenue for year-to-date 2014 was $121.9 million compared to $68.1 million for the corresponding period in 2013, with deferrals of $105.1 million in 2014 and $60.1 million in 2013. Also contributing to the increase was a $4.7 million refund in 2013 related to the annual PEP lookback filing.fourth quarter 2014.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Revenues attributable to changes in sales decreased in the thirdsecond quarter and year-to-date 20142015 when compared to the corresponding periodsperiod in 2013.2014. Weather-adjusted KWH sales to residential customers decreased 0.5% in the second quarter 2015 due to lower customer usage, slightly offset by an increase in customers. Weather-adjusted KWH sales to commercial customers increased 2.6% in the second quarter 2015 due to higher customer usage and an increase in customers. KWH sales to industrial customers decreased 0.9% in the second quarter 2015 due to decreased usage by larger customers related to planned maintenance outages.
Revenues attributable to changes in sales decreased year-to-date 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH energy sales to residential customers decreased 5.5% in the third quarter and 2.7% for year-to-date 2014 when compared to the corresponding periods in 20131.2% due to lower average usage per customer. Household income, one of the primary drivers of residential customer usage, has been flatslightly offset by an increase in 2014.customers. Weather-adjusted KWH energy sales to commercial customers decreased 1.8% in the third quarter and 0.5% for year-to-date 2014 when compared to the corresponding periods in 20130.2% due to decreased commercial economic activity.lower customer usage slightly offset by an increase in customers. KWH energy sales to industrial customers increased 2.5% in the third quarter and 3.2% for year-to-date 2014 when compared to the corresponding periods in 20131.2% primarily due to increased usage by larger customers.
In the first quarter 2015, Mississippi Power updated its methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled second quarter

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and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without these adjustments, second quarter 2015 weather-adjusted residential KWH sales increased 4.0%, weather-adjusted commercial KWH sales decreased 1.5%, and industrial KWH sales decreased 2.1% as compared to the corresponding period in 2014. Also, without these adjustments, year-to-date 2015 weather-adjusted residential KWH sales decreased 3.3%, weather-adjusted commercial KWH sales decreased 5.1%, and industrial KWH sales remained flat as compared to the corresponding period in 2014.
Fuel and other cost recovery revenues decreased in the thirdsecond quarter 2014and year-to-date 2015 when compared to the corresponding periodperiods in 2013,2014, primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased year-to-date 2014 when compared to the corresponding period in 2013 primarily as a result of higher recoverable fuel costs resulting from an increase in Mississippi Power's generation and higher natural gas costs. See "Fuel and Purchased Power Expenses" herein for additional information. 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 energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$0.1  $34.6 15.8
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(12) (16.0) $(31) (18.0)
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's 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. Mississippi Power serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under long-term contracts with cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.
In the thirdsecond quarter 2014,2015, wholesale revenues from sales to non-affiliates were $83.0$63 million compared to $82.9$75 million for the corresponding period in 2013. The increase was due to a $2.0 million increase in base revenues primarily resulting from a wholesale base rate increase effective beginning May 1, 2014, partially offset by a $1.9 million decrease in energy revenues.
2014. For year-to-date 2014,2015, wholesale revenues from sales to non-affiliates were $254.6$141 million compared to $220.0$172 million for the corresponding period in 2013.2014. The increase wasdecreases were primarily due to a $17.2 million increase in base revenues primarily resulting from wholesale base rate increases effective April 1, 2013 and May 1, 2014 and a $17.4 million increasedecrease in energy revenues of which $5.1 million was primarily associated with higher fuelresulting from lower market prices and $12.3 million was associated with an increase in KWH sales primarily due to the higher demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013.fuel cost.
Wholesale Revenues – Affiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$31.6 N/M $50.4 N/M
N/M – Not meaningful
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(2) (10.0) $2 4.7
Wholesale revenues from sales to affiliatesaffiliated companies will vary depending on demand and the availability and cost of generating resources at each company. 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 thethis energy is generally sold at marginal cost.
In the thirdsecond quarter 2014,2015, wholesale revenues from sales to affiliates were $38.6$18 million compared to $7.0$20 million for the corresponding period in 2013.2014. The decrease was due to a $6 million decrease associated with lower natural gas prices, partially offset by a $4 million increase in KWH sales due to higher gas generation partially as a result of the Kemper IGCC combined cycle being in service since August 2014.
For year-to-date 2015, wholesale revenues from sales to affiliates were $45 million compared to $43 million for the corresponding period in 2014. The increase was due to a $33.7an $18 million increase in energy revenuesKWH sales due to higher gas

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primarily due to placinggeneration partially as a result of the Kemper IGCC combined cycle being in service. These increased revenues are offset by fuel expense. Of the $33.7 million increase in energy revenues, $31.6 million was associated with an increase in KWH sales due to higher gas and coal generation and $2.1 million was associated with higher prices,service since August 2014, partially offset by a $2.1$16 million decrease in capacity revenues.
For year-to-date 2014, wholesale revenues from sales to affiliates were $81.6 million compared to $31.2 million for the corresponding period in 2013. The increased revenues were driven by $48.0 million associated with an increase in KWH sales primarily due to higherlower natural gas prices resulting in higher coal-fired generation at lower coal prices and $4.6 million associated with higher prices, partially offset by a $2.2 million decrease in capacity revenues.prices.
Fuel and Purchased Power Expenses
  Third Quarter 2014
vs.
Third Quarter 2013
  Year-to-Date 2014
vs.
Year-to-Date 2013
  (change in millions)
(% change) (change in millions) (% change)
Fuel $30.5
 22.1 $74.1
 19.2
Purchased power – non-affiliates 1.4
 67.3 11.0
 N/M
Purchased power – affiliates (12.7) (86.6) (11.7) (41.2)
Total fuel and purchased power expenses $19.2
   $73.4
  
N/M – Not meaningful
  Second Quarter 2015
vs.
Second Quarter 2014
  Year-to-Date 2015
vs.
Year-to-Date 2014
  (change in millions)
(% change) (change in millions) (% change)
Fuel $(28) (19.6) $(61) (21.0)
Purchased power – non-affiliates 1
 100.0 (10) (76.9)
Purchased power – affiliates (4) (66.7) (11) (73.3)
Total fuel and purchased power expenses $(31)   $(82)  
In the thirdsecond quarter 2014,2015, total fuel and purchased power expenses were $174.1$119 million compared to $154.9$150 million for the corresponding period in 2013.2014. The increasedecrease was due to a $39.4 million increase in the total volume of KWHs generated, partially offset by a $20.2$28 million decrease in the average cost of fuel and purchased power.power and a $3 million decrease in the volume of KWHs purchased.
For year-to-date 2014,2015, total fuel and purchased power expenses were $491.8$236 million compared to $418.4$318 million for the corresponding period in 2013.2014. The increasedecrease was due to a $91.8 million increase in the total volume of KWHs generated, partially offset by an $18.5$72 million decrease in the average cost of fuel and purchased power.power and a $14 million decrease in the volume of KWHs purchased, partially offset by a $4 million increase in the volume of KWHs generated.
Fuel and purchased power energy 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 – "PSC Matters – Fuel Cost Recovery" herein for additional information.
Details of Mississippi Power's generation and purchased power were as follows:
 Third Quarter 2014 Third Quarter 2013 Year-to-Date 2014 Year-to-Date 2013 
Second Quarter
2015
 
Second Quarter
2014
 Year-to-Date 2015 Year-to-Date 2014
Total generation (millions of KWHs)(a)
 5,022 3,688 12,996 10,645
Total generation (millions of KWHs)(*)
 4,109 3,932 8,455 7,974
Total purchased power (millions of KWHs)
 125 469 591 1,070 114 208 227 466
Sources of generation (percent)(a)
   
Sources of generation (percent)(*)
   
Coal 43 43 45 38 18 47 20 46
Gas 57 57 55 62 82 53 80 54
Cost of fuel, generated (cents per net KWH)
  
Coal 3.97 5.12 4.12 5.01 4.14 4.18 3.64 4.21
Gas(a)
 3.20 3.08 3.45 3.14
Average cost of fuel, generated (cents per net KWH)(a)
 3.55 4.03 3.77 3.91
Average cost of purchased power (cents per net KWH)(a)
 4.36 3.58 5.55 3.13
Gas(*)
 2.71 3.62 2.69 3.61
Average cost of fuel, generated (cents per net KWH)(*)
 2.98 3.90 2.90 3.91
Average cost of purchased power (cents per net KWH)(*)
 3.19 3.33 3.37 5.87
(a)(*)Includes energy produced during the test period for the Kemper IGCC which is accounted for in accordance with FERC guidance.
Fuel
In the second quarter 2015, fuel expense was $115 million compared to $143 million for the corresponding period in 2014. The decrease was primarily due to a 23.6% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower natural gas prices, partially offset by a 4.9% increase in the volume of KWHs generated resulting from the availability of lower cost Mississippi Power units. The 4.9% increase in volume included an increase in gas-fired generation of 70.2%, partially offset by a decrease in coal-fired generation of 60.2%.

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Fuel
In the third quarter 2014,For year-to-date 2015, total fuel expense was $168.7$229 million compared to $138.2$290 million for the corresponding period in 2013.2014. The increasedecrease was primarily due to a 38.6% increase in the volume of KWHs generated to meet demand attributed to industrial consumption and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013, partially offset by an 11.9%25.8% decrease in the average cost of fuel per KWH generated primarily due to higher coal-firedgas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower coalnatural gas prices, partially offset by higher natural gas prices.
For year-to-date 2014, fuel expense was $459.0 million compared to $384.9 million for the corresponding period in 2013. The increase was primarily due to a 23.9%6.1% increase in the volume of KWHs generated to meet demand related to colder weatherresulting from the availability of lower cost Mississippi Power units. The 6.1% increase in the first quarter 2014 as compared to the corresponding periodvolume included an increase in 2013, partiallygas-fired generation of 65.2%, offset by a 3.6% decrease in the average cost of fuel per KWH generated, primarily due to higher natural gas prices resulting in higher coal-fired generation at lower coal prices.of 53.7%.
Purchased Power - Non-Affiliates
In the thirdsecond quarter 2014,2015, purchased power expense from non-affiliates was $3.5$2 million compared to $2.1$1 million for the corresponding period in 2013.2014. The increase was primarily the result of a 145.8%57.6% increase in the average cost per KWH, purchased, partially offset by a 32.0%2.8% decrease in the volume of KWHs purchased.purchased due to an increase in Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014.
For year-to-date 2014,2015, purchased power expense from non-affiliates was $16.2$3 million compared to $5.2$13 million for the corresponding period in 2013.2014. The increasedecrease was primarily the result of a 54.1% decrease in the volume of KWHs purchased due to an increase in Mississippi Power generation partially as a 283.8% increaseresult of the Kemper IGCC combined cycle being placed in service in August 2014 and a 42.3% decrease in the average cost per KWH purchased partially offset byas a 19.4% decrease in the volumeresult of KWHs purchased.lower natural gas prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power - Affiliates
In the thirdsecond quarter 2014,2015, purchased power expense from affiliates was $2.0$2 million compared to $14.7$6 million for the corresponding period in 2013.2014. The decrease was primarily due to an 83.4%a 58.3% decrease in the volume of KWHs purchased due to increased Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014, and a 19.5%24.7% decrease in the average cost per KWH purchased.purchased as a result of lower natural gas prices.
For year-to-date 2014,2015, purchased power expense from affiliates was $16.6$4 million compared to $28.3$15 million for the corresponding period in 2013.2014. The decrease was primarily due to a 52.8%50.0% decrease in the volume of KWHs purchased due to increased Mississippi Power generation partially offset byas a 24.5% increaseresult of the Kemper IGCC combined cycle being placed in service in August 2014, and a 41.5% decrease in the average cost per KWH purchased.purchased as a result of lower natural gas prices.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC.
Other Operations and Maintenance Expenses
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$8.9 15.6 $25.7 15.5
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$7 11.5 $19 15.2
In the thirdsecond quarter 2014,2015, other operations and maintenance expenses were $65.8$68 million compared to $56.9$61 million for the corresponding period in 2013.2014. The increase was primarily due to a $4.0$7 million increase in employee compensation and benefits and labor, a $2.3 million increase in customer accounting services and sales expenses primarily due to uncollectible expenses and customer incentives, a $1.9 million increase in administrative and general expenses primarily due to an increase in charges from affiliates and a $1.5 million increase in transmission and distribution expenses mainly for overhead line maintenance and vegetation management. These increases were partially offset by a $0.7 million decrease in generation maintenance expenses primarily related to scheduled outages.
For year-to-date 2015, other operations and maintenance expenses were $144 million compared to $125 million for the corresponding period in 2014. The increase was primarily due to a $6 million increase in generation

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For year-to-date 2014, other operations and maintenance expenses were $191.9 million compared to $166.2 million for the corresponding period in 2013. The increase was primarily due to an $11.8including scheduled outages, a $5 million increase in employee compensation and benefits including pension, and labor, a $10.5$5 million increase in generation maintenance expenses primarily related to scheduled outages,uncollectible expenses and a $2.7 million increase in transmission and distribution maintenance expenses primarilycustomer incentives.
See Note (F) to the Condensed Financial Statements herein for overhead line maintenance, vegetation management and equipment maintenance.additional information related to pension costs.
Depreciation and Amortization
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$1.2 5.3 $2.7 4.0
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$6 25.0 $10 21.3
In the thirdsecond quarter 2014,2015, depreciation and amortization was $23.4$30 million compared to $22.2$24 million for the corresponding period in 2013.2014. The $1.2 million increase was primarily due to a $0.6$2 million increase in depreciation related to increases in generation and transmissiondistribution plant in service, a $2 million increase related to regulatory deferrals associated with Plant Daniel Units 3 and 4 and the Kemper IGCC, and a $0.3$1 million increase in amortization primarily resulting from the 2013 regulatory deferral associated with the capital lease related to the Kemper IGCC air separation unit.ECO Plan amortization.
For year-to-date 2014,2015, depreciation and amortization was $70.3$57 million compared to $67.6$47 million for the corresponding period in 2013.2014. The $2.7 million increase was primarily due to a $1.6$4 million increase in depreciation related to increases in generation, transmission and transmissiondistribution plant in service, and a $1.9$4 million increase in therelated to regulatory deferraldeferrals associated with the purchase of Plant Daniel Units 3 and 4. These increases were partially offset by a $0.6 million decrease in amortization resulting from regulatory deferrals associated with4 and the Kemper IGCC.IGCC, and a $2 million increase in ECO Plan amortization.
See Note 1 to the financial statements of Mississippi Power under "Purchase of the Plant Daniel Combined Cycle Generating Units" and "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. 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" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Taxes Other Than Income Taxes
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$1.2 6.0 $2.4 4.0
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$3 15.0 $7 17.1
In the thirdsecond quarter 2014,2015, taxes other than income taxes were $22.3$23 million compared to $21.1$20 million for the corresponding period in 2013.2014. The increase was primarily due to a $1.4$3 million increase in ad valorem taxes, and a $0.4 million increase in payroll taxes due to an increase in labor expenses, partially offset by a $0.5$1 million decrease primarily in corporate franchise taxes.tax.
For year-to-date 2014,2015, taxes other than income taxes were $63.2$48 million compared to $60.8$41 million for the corresponding period in 2013.2014. The increase was primarily due to a $1.4$9 million increase in ad valorem taxes, partially offset by a $2 million decrease in franchise taxes.
The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, a $1.0 million increase in payroll taxes due to an increase in labor expenses.therefore, does not affect net income.
Estimated Loss on Kemper IGCC
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$268.0 N/M $(264.0) (24.9)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$23 N/M $(348) (91.6)
N/M – NotM-Not meaningful

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In the thirdsecond quarter 20142015 an estimated probable loss on the Kemper IGCC of $23 million was recorded at Mississippi Power. For year-to-date 2015 and the third quarter 2013,year-to-date 2014, estimated probable losses on the Kemper IGCC of $418.0$32 million and $150.0$380 million, respectively, were recorded at Mississippi Power. For year-to-date 2014 and year-to-date 2013, estimated probable losses on the Kemper IGCC of $798.0 million and $1.06 billion, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions.
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" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(0.4) (1.2) $20.0 22.7
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(12) (32.4) $(22) (29.3)
For year-to-date 2014,In the second quarter 2015, AFUDC equity was $107.7$25 million compared to $87.7$37 million for the corresponding period in 2013.2014. For year-to-date 2015, AFUDC equity was $53 million compared to $75 million for the corresponding period in 2014. The increase was primarily due to $16.8 million related todecreases are driven by a reduction in the constructionAFUDC rate and by placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. 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 $3.2Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(43) N/M $(44) N/M
N/M-Not meaningful
In the second quarter 2015, interest expense, net of amounts capitalized was ($30) million compared to $13 million for the corresponding period in 2014. For year-to-date 2015, interest expense, net of amounts capitalized was ($19) million compared to $25 million for the corresponding period in 2014. The decreases were primarily due to a $41 million decrease related to the Plant Daniel scrubber project.termination of the APA between Mississippi Power and SMEPA which required the return of SMEPA's deposits at a lower rate of interest than accrued. Also contributing to the decrease was an increase in capitalized interest primarily resulting from carrying costs related to the Kemper IGCC. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.information.
Interest Expense, Net of Amounts CapitalizedIncome Taxes (Benefit)
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$0.7 7.9 $4.5 15.4
Second Quarter 2015 vs. Second Quarter 2014Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change)(change in millions)(% change)
$—$134N/M
N/M-Not meaningful
In the thirdsecond quarter 2015 and 2014, interest expense, net of amounts capitalized was $9.4income taxes were $16 million. For year-to-date 2015, income taxes (benefit) were $20 million compared to $8.7$(114) million for the corresponding period in 2013.2014. The increase waschange primarily due toreflects a $2.5 million increase resulting from the receipt of a $75.0 million interest-bearing refundable deposit from SMEPA in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC, a $1.9 million increase related to the regulatory liability for Kemper IGCC rate recovery, and a $1.5 million increase associated with issuances of new long-term debt. These increases were partially offset by a $4.0 million increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC and a $0.9 million decrease in interest expense associated with the redemption of long-term debt in 2013.
For year-to-date 2014, interest expense, net of amounts capitalized was $34.0 million compared to $29.5 million for the corresponding period in 2013. The increase was primarily due to a $7.3 million increase resulting from the receipt of a $75.0 million interest-bearing refundable deposit from SMEPA in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC, a $4.9 million increase related to the regulatory liability for Kemper IGCC rate recovery, and a $3.7 million increase associated with issuances of new long-term debt. These increases were partially offset by an $8.1 million increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC and a $2.8 million decrease in interest expense associated with the redemption of long-term debt in 2013.
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

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Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Other Income (Expense), Net
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(7.4) N/M $(7.3) N/M
N/M – Not meaningful
In the third quarter 2014, other income (expense), net was $(7.8) million compared to $(0.4) million for the corresponding periodreduction in 2013. For year-to-date 2014, other income (expense), net was $(11.5) million compared to $(4.2) million for the corresponding period in 2013. These changes in expense were primarily due to a settlement with the Sierra Club in 2014. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.
Income Taxes (Benefit)
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(106.6) N/M $102.2 28.8
N/M – Not meaningful
In the third quarter 2014, income tax benefits were $139.3 million compared to $32.7 million for the corresponding period in 2013. For year-to-date 2014, income tax benefits were $253.0 million compared to $355.2 million for the corresponding period in 2013. These changes were primarily related to the estimated probable losses recorded on the construction of the Kemper IGCC.IGCC recorded in 2014.
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 allows for the timely recovery ofrecover its prudently-incurred costs during a time of increasing costs, its ability to recover costs in a timely manner, and the completion and subsequent operation of ongoing construction projects, primarily the Kemper IGCC and the Plant Daniel scrubber project.project as well as other ongoing construction projects. Future earnings in the near term will depend, in part, upon maintaining and growing sales which isare subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Changes in regional and global economic conditions may impact sales for Mississippi Power as 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 federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis.basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could

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negatively affect 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.
On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million excluding the reserve for cost of removal. As of June 30, 2015, Mississippi Power reclassified the net carrying value of these assets from accumulated provision for depreciation to other regulatory assets, deferred, in accordance with an accounting order from the Mississippi PSC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Sierra Club Settlement Agreement" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.
Mississippi Power expects to recover through its rates the remaining book value of the retired assets and certain costs, including unusable inventory, associated with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.
New Source Review Actions
See Note 3 to the financial statements of Mississippi Power under "Environmental Matters New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case. If approved by the U.S. District Court for the Northern District of Alabama, Alabama

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Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
See Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.
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 the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama and the EPA's proposed rulesMississippi) to revise or remove state implementation plan (SIP) provisions regarding the regulation of excess emissions that occur during periods of startup, shutdown, or malfunction (SSM).SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On AprilJune 29, 2014,2015, the U.S. Supreme Court overturnedissued a decision finding that the U.S. Court of Appeals for the District of Columbia Circuit's August 2012EPA had failed to properly consider costs in its decision to vacate CSAPRregulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014,The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.
On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subjectrespond to the rule (including Alabama and Mississippi) to revise their SSM provisions within 18 months after issuance of the final rule.decision. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges andthis decision cannot be determined at this time.
See "PSC Matters Environmental Compliance Overview Plan"On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama. The court's decision leaves the emissions trading program in place and "Other Matters Sierra Club Settlement Agreement" and Note (B)remands the rule to the Condensed Financial Statements under "PSC Matters Environmental Compliance Overview Plan" and "Other Matters Sierra Club Settlement Agreement" hereinEPA for additional information regarding generating unit retirement, repowering, and/or conversion.
further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate outcomeimpact of these mattersthis decision will depend on additional rulemaking 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 Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On April 21, 2014,June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a proposedfinal rule to reviserevising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs,CWA programs. The final rule significantly expandingexpands the scope of federal jurisdiction under the CWA. If finalized as proposed,CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, theThe rule as proposed could have significant impacts on economic development projects which could affect customer demand growth.becomes effective August 28, 2015. The ultimate impact of the proposedfinal rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
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 the EPA's rulemaking for cooling water intake structures.

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Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Coal Combustion Residuals" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On August 15, 2014,April 17, 2015, the EPA published athe Disposal of Coal Combustion Residuals from Electric Utilities final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became(CCR Rule) in the Federal Register, setting October 19, 2015 as the effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementationdate of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units.CCR Rule. The ultimate impact of this rule will depend on the outcome of any legal challenges andCCR Rule cannot be determined at this time.timeand will depend on Mississippi Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Mississippi Power recorded incremental asset retirement obligations (ARO) of approximately $95 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Mississippi Power's AROs.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.CO2 from fossil-fuel-fired electric generating units.
On June 18, 2014,August 3, 2015, the EPA publishedreleased pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the proposed Clean Power Plan, setting forthfinal rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to address CO2 emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and finalmeet EPA-mandated CO2 emission rate goalsrates for existing units. The EPA's final guidelines require state plans to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposedmeet interim CO2 performance standards for modifiedrates between 2022 and reconstructed fossil fuel-fired electric generating units. The2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, thatwhich could impactaffect future unit retirement and replacement decisions. Also, additional compliance costs could affectMississippi Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. Further, any resulting higher costs that are recoveredrates or through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.
On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system.market-based contracts. However, the ultimate financial and operational impact of the Cleanfinal rules on Mississippi Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upondepend on numerous factors. These factors include:including the structure, timing, and contentSouthern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-relatedemissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant DeteriorationFERC Matters
Municipal and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of the U.S. Supreme Court's decision cannot be determined at this time.
FERC MattersRural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the authority to defer inestablishment of a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules.for Kemper IGCC-related costs. 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 Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
On March 31, 2015, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgo the Municipal and Rural Associations cost-based electric tariff increase reflected in

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On March 31, 2014, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increasefiling by, among other things, increasing the accrual of AFUDC in the Municipal and Rural Associations (MRA) cost-based electric tariff.lieu of including CWIP in rate base. The settlement agreement, approvedwhich was accepted by the FERC on May 20, 2014,13, 2015, provides that the additional accrual of AFUDC was effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $11 million annually, of which $8 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.
Market-Based Rate Authority
Mississippi Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Mississippi Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Mississippi Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Mississippi Power) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including Mississippi Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates underand several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as the MRA cost-based electric tariff will increase approximately $10.1 million annually,Kemper IGCC, fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with revised rates effective for services rendered beginning May 1, 2014.
PSC Matters
Energy Efficiency
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Energy Efficiency"environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through Mississippi Power in Item 7 andPower's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency"Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
On June 3, 2014,Renewables
In April and May 2015, Mississippi Power entered into separate PPAs for three solar facilities for a combined total of approximately 105 MWs. Mississippi Power would purchase all of the energy produced by the solar facilities for the 25-year term of the contracts. If approved by the Mississippi PSC, approvedthe projects are expected to be in service by the end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfoliofuel cost recovery mechanism. The ultimate outcome of energy efficiency programs. On October 17, 2014, Mississippi Power filed a revised compliance filing, which proposed an increase of $6.7 million in retail revenues for the period December 2014 through December 2015. The Mississippi PSC approved the revised filing on November 4, 2014.this matter cannot be determined at this time.
Performance Evaluation Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Performance Evaluation Plan" of Mississippi Power in Item 7 and 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.
On March 18, 2014,17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2013,2014, which indicated no surcharge or refund. On March 31, 2014,26, 2015, the Mississippi PSC suspended the filing to allow it more time for review.
On June 3, 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for Mississippi Power and other regulated electric utilities in Mississippi.
The ultimate outcome of these mattersthis matter cannot be determined at this time.
Environmental Compliance Overview Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Compliance Overview Plan" of Mississippi Power in Item 7 and 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 additional information regarding the CPCN to construct a scrubber on Plant Daniel Units 1 and 2.
On August 1, 2014, Mississippi Power entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On August 28, 2014, the Chancery Court dismissed the appeal.
In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from

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environmental regulations. As of September 30, 2014, $5.5 million of Plant Greene County CWIP had been reclassified as a regulatory asset. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Greene County and Watson. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.
The ultimate outcome of these matters 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 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Mississippi Power's fuel cost recovery.
At September 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $13.1 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.
Ad Valorem Tax Adjustment
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Ad Valorem Tax Adjustment" ofOn April 23, 2015, Mississippi Power in Item 7 of the Form 10-K for additional information.
On May 6, 2014, the Mississippi PSC approved Mississippi Power'sfiled its annual ad valorem tax adjustment factor filing for 2014,2015, which requested an annual rate increasedecrease of 0.38%0.35%, or $3.6$2 million in annual retail revenues, primarily due to an increasea decrease in property taxaverage millage rates. On May 26, 2015, the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.
Integrated Coal Gasification Combined Cycle
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Integrated Coal Gasification Combined Cycle" 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 Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Project ApprovalOverview
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC, which the Sierra Club appealed to the Chancery Court. Later in 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. In January 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.
On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN, which the Mississippi Supreme Court granted on September 11, 2014. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.
Kemper IGCC Schedule and Cost EstimateIGCC.
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245.3$245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2

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pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the Cost Cap Exceptions, as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.
The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service onusing natural gas onin August 9, 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. In accordance with a Mississippi PSC order, on August 18, 2014, Mississippi Power provided an analysisRecovery of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of (1) the continued collection of rates as prescribed by the 2013 MPSC Rate Order (defined below), with the current recognition as revenue of the related equity return on all assets placed in service, and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account, (2) the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC, and (3) the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurredand the Cost Cap Exceptions remains subject to support operationreview and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the combined cycle. All energy revenues associated withCourt decision), and actual costs incurred as of June 30, 2015, as adjusted for the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" herein for additional information.
The ultimate outcome of this matter cannot be determined at this time.Court's decision, are as follows:

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Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of September 30, 2014 for the Kemper IGCC are as follows:
Cost Category
2010 Project Estimate(f)
 Current Estimate Actual Costs at September 30, 2014
2010 Project Estimate(f)
 Current Estimate Actual Costs at June 30, 2015
(in billions)(in billions)
Plant Subject to Cost Cap(a)
$2.40
 $4.86
 $4.06
$2.40
 $4.96
 $4.51
Lignite Mine and Equipment0.21 0.23 0.230.21 0.23 0.23
CO2 Pipeline Facilities
0.14 0.11 0.100.14 0.11 0.11
AFUDC(b)(c)
0.17 0.62 0.410.17 0.62 0.52
Combined Cycle and Related Assets Placed in
Service – Incremental(d)

 
 

 0.02
 
General Exceptions0.05 0.10 0.070.05 0.10 0.08
Regulatory Asset(c)(e)

 0.18 0.10
Deferred Costs(c)(e)

 0.19 0.15
Total Kemper IGCC(a)(c)
$2.97
 $6.10
 $4.97
$2.97
 $6.23
 $5.60
(a)
The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap.cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.
(b)
Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.
(c)Amounts in the Current Estimate reflect estimated costs through March 31, 2016.
(d)Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service onin August 9, 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.
(e)
The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."
(f)
The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
Of the total costs, including post-in-service costs for the lignite mine, incurred as of SeptemberJune 30, 2014, $2.882015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $1.98$2.08 billion), $104.3$2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, and $3.9$16 million in other deferred charges and assets, and $24 million in Mississippi Power's Condensed Balance Sheet herein, and $1.1AROs in the balance sheet, with $1 million was previously expensed.
Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related coststo the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $418.0$23 million ($258.114 million after tax) in the thirdsecond quarter 20142015 and $380.0$9 million ($234.76 million after tax) in the first quarter 2014.2015. These amounts are in addition to charges totaling $1.18 billion$868 million ($728.7536 million after tax) recognized through December 31, 2013., $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. The first quarter 2014 revisedincreases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to decreases in construction labor productivity at the Kemper IGCC due in large part to adverse weather, unexpected excessive craft labor turn-over, and unanticipated installation inefficiencies, as well as additional risk related to the expected in-service date. The third quarter 2014 revised cost estimate primarily reflects costs related to the extension of the project schedule for the remainder of the Kemper IGCC (including the gasifierequipment rework, scope modifications, and the gas clean-up facilities) as a resultrelated additional labor costs in support of matters related to the time expected to be required for start-up activities and operational readiness including enhancing the scope of specialized operator training.activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $20$25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion

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cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.
Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and

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inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations.operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material.
Rate Recovery of Kemper IGCC Costs
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the Seven-Year2015 Rate Plan (described below)Case and otherany alternative proceedings related proceedings duringto the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements.
2013 Settlement Agreement
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, establishesestablished the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowsallowed Mississippi Power to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in February 2013. Mississippi Power intendsPower's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Seven-Year Rate Plan (described below) as approved by the Mississippi PSC. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective following completion of the Mississippi PSC's prudence review of the costs to be securitized. With the extension of the Kemper IGCC in-service date, under certain potential scenarios, the amount eligible to be securitized may exceed $1.0 billion. In that event, Mississippi Power would expect to pursue rate recovery of any additional eligible costs.
The 2013 Settlement Agreement provides that Mississippi Power may terminate the 2013 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 2013 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the 2013 Settlement

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Agreement.estimated in-service date until securitization is finalized and other costs not included in Mississippi Power continuesPower's 2013 revision to workthe proposed rate recovery plan filed with the Mississippi PSC andfor the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi Public Utilities Staff (MPUS)PSC. The Court's decision did not impact Mississippi Power's ability to implementutilize alternate financing through securitization, the requirements of2012 MPSC CPCN Order, or the February 2013 Settlement Agreement.legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.
2013 MPSC Rate Order
Consistent with the terms of the 2013 Settlement Agreement, in January 2013, Mississippi Power filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013.
In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively arewere designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order). For the first nine months of 2014, $121.9 million has been collected, with $16.8 million recognized in retail revenues in Mississippi Power's Condensed Statements of Operations herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Mississippi Power's Condensed Balance Sheet herein. Since March 2013, $220.0 million has been collected, with $27.1 million recognized in retail revenues in Mississippi Power's Condensed Statements of Operations herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Mississippi Power's Condensed Balance Sheet herein.
service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC and to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates through the in-service date unlessuntil directed to do otherwise by the Mississippi PSC.
In MarchAugust 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.
In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Mississippi Power.
2015 Mississippi Supreme Court Decision
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was filed by Thomas A. Blanton withnot provided for under the Baseload Act and (2) the Mississippi SupremePSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court which remains pending againstalso found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC. On April 22, 2014,PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi Supreme Court requested further briefingPSC to (1) fix by order the rates that were in this proceeding on a number of substantive issues relatingexistence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. An adverse outcome could affect the rates that went into effect on March 19, 2013 and January 1, 2014 and the related amounts deferred as a regulatory liability.
See "Regulatory Assets and Liabilities" herein for additional information.
Seven-Year Rate Plan
In March 2013,Through June 30, 2015, Mississippi Power in compliance withhad collected $331 million through rates under the 2013 MPSC Rate Order filed a revision to the proposed rate recovery plan withand had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC forordered that the Kemper IGCC for cost recovery through 2020 (Seven-Year Rate Plan), which is still under review by the Mississippi PSC. In the Seven-Year Rate Plan,Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equalsubmitted a refund plan to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC will reviewon July 21, 2015, which proposed two alternative refund plans for the amountMississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.
2015 Rate Case
As a result of the 2015 Mississippi Supreme Court decision and if approved, determine the appropriate method and period of disposition.Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "Regulatory Assets and Liabilities""2015 Mississippi Supreme Court Decision" herein for additional information.
The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act On

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of 2012 (ATRA), which currently requires that assets be placed in service in 2014. WhileMay 15, 2015, Mississippi Power placedfiled the 2015 Rate Case with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
On July 10, 2015, Mississippi Power filed a Supplemental Notice with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal, In-Service Asset Proposal, for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the associated common facilities portionIn-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.
The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC in service on August 9, 2014, extension of the in-service date for the remainder of the Kemper IGCC beyond 2014 results in the loss of tax benefits related to bonus depreciation under current law. The estimated value to retail customers of the bonus depreciation tax benefits not associated with the combined cycle and the associated common facilities portion of the Kemper IGCC is approximately $130 million to $160 million.
Mississippi Power plans to further revise the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to investment tax credits, various other revenue requirement items, and other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated15% undivided interest that was previously projected to be an increasepurchased by SMEPA. See "Termination of approximately $60 millionProposed Sale of Undivided Interest to $70 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power, including Section 174 Research and Experimental (R&E) tax deductions, that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan. See "Income Tax Matters"SMEPA" herein for additional information.
Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC could have an adverse impact on the Seven-Year Rate Plan, including the inability to recover items considered as Cost Cap Exceptions.
In the event thatIf the Mississippi PSC does not approveact on the Supplemental Notice or the 2015 Rate Case within 120 days of the Supplemental Notice filing, Mississippi Power withdrawsexpects to put one of the Seven-Year Rate Plan,three viable alternative rate proposals into effect as ultimately revised, temporary rates under bond and subject to refund pursuant to Mississippi state law.
Mississippi Power wouldalso expects to seek additional rate relief to address recovery through alternate means, which could include a traditional rate case.
of the remaining Kemper IGCC assets. In addition to current estimated costs at SeptemberJune 30, 20142015 of $6.10$6.23 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Seven-Year Rate Plan, as ultimately amended or revised, and securitization areKemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
Prudence Reviews
The Mississippi PSC's review of Kemper IGCC costs is ongoing. OnIn August 5, 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the MPUS.Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for

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interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC grantedissued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, interestcarrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
OnIn August 18, 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of SeptemberJune 30, 2014,2015, the regulatory asset balance associated with the Kemper IGCC was $104.3$198 million. The projected balance at March 31, 2016 is estimated to total approximately $180$276 million. The amortization period of 40 years proposed by Mississippi Power for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

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In March 2013,See "2015 Mississippi Supreme Court Decision" herein for additional information related to the July 7, 2015 Mississippi PSC issuedorder terminating the 2013 MPSC Rate Order approving retailMirror CWIP rate increasesand requiring refund of 15% effective March 19, 2013, and 3% effective Januarycollections under Mirror CWIP.
See Note 1 2014, which collectively are designed to collect $156 million annually beginning in 2014. Because the 2013 MPSC Rate Order did not provide for the inclusionfinancial statements of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. To comply with the 2013 MPSC Rate Order, Mississippi Power is deferring the collections under the approved rates through the in-service date"Regulatory Assets and Liabilities" in a regulatory liability to be amortized and used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Mississippi Power is accruing interest costs on the unamortized balance of such regulatory liability for the benefit of retail customers. The dispositionItem 8 of the regulatory liability will be determined by the Mississippi PSC in future cost recovery mechanism proceedings.Form 10-K for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights in the event thatas Mississippi Power doeshas not satisfysatisfied its contractual obligation with respect to deliveries ofdeliver captured CO2 by May 11, 2015. WhileSince May 11, 2015, Mississippi Power has received no indication from either Denbury orbeen engaged in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their intent to terminate their respectiveagreement that do not affect pricing or minimum purchase quantities. Any termination or material modification of these agreements any termination could result in a material reduction in future by-productchemical product sales revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.
The ultimate outcome of these matters cannot be determined at this time.
Proposed Sale of Undivided Interest to SMEPA
In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the April 2011 power supply agreement were $17.5 million in 2013. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014.

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In 2012 and on January 2, 2014, Mississippi Power received $150 million and $75 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing,extent Mississippi Power would be requiredis not able to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposits have been presented as a current liability in Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Mississippi Power's Condensed Statements of Cash Flows herein. In July 2013, Southern Company enteredenter into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.
By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle with respect to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The parties agreed to further amend the APA as follows: (1) Mississippi Power agreed to cap at $2.88 billion the portion of the purchase price for development and construction costs, net of the Cost Cap Exceptions; title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the plant's in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date.
The letter agreement also provides for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service. In addition, if the parties approve an amendment to the APA incorporating the terms of the letter agreement but do not execute the amendment before December 31, 2014, the parties agreed to extend the current APA through December 31, 2015.
The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement incorporating the principles of the amended APA, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase.
On October 9, 2014, Mississippi Power received an additional $50 million deposit from SMEPA to be applied to the purchase.other similar contractual arrangements.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest to SMEPA
In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and SMEPA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits Section 174 Research and Experimental Deduction," respectively, herein for additional information about the Kemper IGCC.information. The ultimate outcome of thesethis tax mattersmatter cannot be determined at this time.
Bonus Depreciation
In January 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which will apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million.
Investment Tax Credits
The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through September 30, 2014, Mississippi Power had recorded tax benefits

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totaling $276.4 million for the Phase II credits, of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.
Section 174 Research and Experimental Deduction
For the 2013 tax year, Southern Company included in its consolidated federal income tax return a deduction for R&E expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Mississippi Power recorded an unrecognized tax benefit of approximately $100 million as of September 30, 2014. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits" herein for additional information.
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 air quality and water standards, has increased generallyoccurred throughout the U.S. In particular, personal injury, property damage, and otherThis litigation has included claims for damages alleged to have been caused by CO2 and other emissions, coal combustion residuals,CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.matters.
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 in Note (B) to the Condensed Financial Statements 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 ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See the NotesNote (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Sierra Club Settlement Agreement
On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC and the scrubber project at Plant Daniel Units 1 and 2. In addition, the Sierra Club agreed to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings for the Kemper IGCC, including, but not limited to, the prudence review, and Plant Daniel for a period of three years from the date of the Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw all appeals associated with certification of the Kemper IGCC and the Plant Daniel Units 1 and 2 scrubber project, which the applicable courts granted in the third quarter 2014.
Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a 15-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In accordance with the Sierra Club Settlement Agreement, Mississippi Power paid $7 million in the third quarter 2014, recognized in other income (expense), net in Mississippi Power's Condensed Statements of Operations herein. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also

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agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "PSC Matters – Environmental Compliance Overview Plan" herein for additional information.
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, Pension and Other Postretirement Benefits, and AFUDC.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2014,2015, Mississippi Power further extended the scheduled in-service date for the Kemper IGCC to the first half of 2016 and revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery or any joint owner contributions for any costs related coststo the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.
As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $418.0$23 million ($258.114 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380.0$380 million ($234.7235 million after tax) in the first quarter 2014, $40.0$40 million ($24.725 million after tax) in the fourth quarter 2013, $150.0$150 million ($92.693 million after tax) in the third quarter 2013, $450.0$450 million ($277.9278 million after tax) in the second quarter 2013, $462.0$462 million ($285.3285 million after tax) in the first quarter 2013, and $78.0$78 million ($48.248 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of $1.98$2.08 billion ($1.221.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through SeptemberJune 30, 2014.2015.
Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations.operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $20$25 million to $30 million per month, whichwhich includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" 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 and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Mississippi Power has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. Mississippi Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Mississippi Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Recently Issued Accounting Standards
On May 28, 2014, theThe Financial Accounting Standards Board issuedBoard's (FASB) ASC 606, Revenue from Contracts with Customers. ASC 606, revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016.2017. Mississippi Power is currently evaluatingcontinues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Mississippi Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Mississippi Power's financial condition was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections, which as of June 30, 2015 was approximately $353 million including associated carrying costs, and the termination of the Mirror CWIP rate will further adversely impact Mississippi Power's financial condition and its ability to obtain financing needed for normal business operations and completion of the Kemper IGCC. Earnings for the ninesix months ended SeptemberJune 30, 2015 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. Earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC; however,IGCC.
In addition to funding normal business operations and projected capital expenditures, Mississippi Power's financial condition remained stable at September 30, 2014 as a resultcash requirements primarily consist of capital contributions$900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs. In addition, Mississippi Power byissued an 18-month promissory note to Southern Company.Company in the aggregate principal amount of approximately $301 million related to the refund to SMEPA and expects to enter into a similar promissory note with Southern Company to fund the Mirror CWIP refund. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA," "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order,"" – 2015 Mississippi Supreme Court Decision," and " – 2015 Rate Case" herein for additional information. For the three-year period from 2015 through 2017, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental equipment for existing generating units, including the Plant Daniel scrubber project, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. See "Sources of Capital" herein for additional information.
Through SeptemberJune 30, 2014,2015, Mississippi Power has incurred non-recoverable cash expenditures of $1.18$1.62 billion and is expected to incur approximately $0.8$0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.
During the first ninesix months of 2014,2015, Mississippi Power received $310.0 million in equity contributions and a $220.0 million loan from Southern Company which was repaid on September 29, 2014. In October 2014, Mississippi Power received an additional $100$75 million in equity contributions from Southern Company. In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. On June 3, 2015, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company as a result of Southern Company's refund of approximately $301 million in deposits and associated interest to SMEPA in connection with the termination of the APA. Mississippi Power intends to continue to monitor its access to short-termutilize operating cash flows and long-term capital marketslines of credit (to the extent available) as well as loans and, bank credit arrangements. Management intends to utilizeunder certain circumstances, equity contributions and/or loans from Southern Company and cash, as well as commercial paper, lines of credit, and bank notes as market conditions permit, to fund Mississippi Power's short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled $504.7$309 million for the first ninesix months of 2014,2015, an increase of $218.0$131 million as compared to the corresponding period in 2013.2014. The increase in cash provided from operating activities is primarily due to Kemper IGCC collections that are being deferred for future rate mitigation,R&E tax deductions and bonus depreciation reducing tax payments, an increase in fuel recovery, and a decrease in receivables, and increases inpartially offset by the timing of payments for accounts payable and accrued compensation, partially offset by investment tax credits relatedfuel purchases. See Notes (B) and Note (G) to the Kemper IGCC, income taxes primarily related to the Kemper IGCC, lower fuel inventory additions compared to the prior year, and an increase in under-recovered regulatory clause revenue.Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $1.0 billion$460 million for the first ninesix months of 20142015 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $490.1$230 million for the first ninesix months of 20142015 primarily due to an increase in equityshort-term bank loans, capital contributions the issuance of bank notes,from Southern Company, and the receipt of an additional SMEPA deposit,short-term borrowings, partially offset by a returnredemptions of paid in capital.long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs," " – Regulatory Assets and Liabilities," and " – Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
Significant balance sheet changes for the first ninesix months of 20142015 include an increasea decrease in securities due within one year of $798.0 million and a decrease in long-term debt of $533.7$349 million, primarily due to bank loansrefinancing or replacing maturing by the end of the third quarter 2015, as well as an increase in thelong-term debt with short-term loans. Additionally, long-term debt increased $301 million and interest-bearing refundable deposit fromdecreased $275 million, due to an intercompany loan for repayment of the SMEPA of

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$75 million.deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased $212.4 million,$439 million; other regulatory asset,assets, deferred increased $54.8 million,$97 million; and otherthe Mirror CWIP regulatory liabilities, deferredliability increased $122.7$82 million primarily due to the Kemper IGCC. Additional changes included an increase in prepaid income taxes of $128.0 million, an increase in accrued income taxes of $86.4 million,associated with construction, operation, and an increase in deferred charges related to income taxes of $57.4 million primarily related to R&E tax deductions and investment tax creditscollections related to the Kemper IGCC. See FUTURE EARNINGS POTENTIAL "Income Tax Matters""Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current; accrued income taxes; accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and other deferred credits and liabilities increased primarily due to R&E tax deductions and the related reserve. Additional changes include increases in notes payable primarily due to new short-term bank loans and asset retirement obligations due to the CCR Rule. Total common stockholder's equity decreased $155.5increased $164 million primarily due to the estimated probable loss on the Kemper IGCC partially offset by the receipt of $310.0$75 million in capital contributions from Southern Company.Company and due to net income during the second quarter 2015.
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, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $812$900 million will be required through SeptemberJune 30, 20152016 to fund maturities of long-termbank term loans scheduled to mature on April 1, 2016 and $30 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs. See "Sources of Capital" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $1.5$1.0 billion for 2014, $804in 2015, $354 million in 2016, and $229 million for 2015, and $324 million for 2016,2017, which includes expenditures related to the construction and start-up of the Kemper IGCC of $1.3 billion for 2014, $551$801 million forin 2015 and $75$150 million forin 2016. The amounts related to the construction and start-up of the Kemper IGCC exclude SMEPA's proposed acquisition of a 15% ownership share of the Kemper IGCC for approximately $569 million (including construction costs for all prior periods relating to its proposed ownership interest).
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; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" and Note (B) to the Condensed Financial Statements under "Integrated Coal

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.
Sources of Capital
Except as described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows security issuances, termand lines of credit (to the extent available) as well as loans short-term debt, and, under certain circumstances, equity contributions or loans from Southern Company. However,Mississippi Power's financial condition was adversely affected by the issuance of an 18-month promissory note to Southern Company related to the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC. The amount, type, and timing of any future financings if needed, will depend upon regulatory approval, prevailing market conditions, and other factors.factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources"Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Capital"Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Mississippi Supreme Court Decision" of Mississippi Power in Item 7 of the Form 10-K and herein for additional information.
Mississippi Power has received $245.3$245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note (B)3 to the Condensed Financial Statementsfinancial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" hereinin Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. As of June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $1 billion at September$898 million primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs through June 30, 2014, primarily because of securities due within one year. Management2015. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions and/or loans from Southern Company and cash, as well as commercial paper, lines of credit, and bank notes as market conditions permit, to fund Mississippi Power's short-term capital needs.
At SeptemberJune 30, 2014,2015, Mississippi Power had approximately $89.9$212 million of cash and cash equivalents. Committed credit arrangements with banks at SeptemberJune 30, 20142015 were as follows:
Expires(a)
Expires(a)
   
Executable Term
Loans
 
Due Within One
Year
Expires(a)
   
Executable Term
Loans
 
Due Within One
Year
2014 2015 2016 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
20152015 2016 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions)(in millions) (in millions) (in millions) (in millions)(in millions) (in millions) (in millions) (in millions)
$15
 $120
 $165
 $300
 $300
 $25
 $40
 $65
 $70
40
 $255
 $295
 $265
 $30
 $40
 $70
 $225
(a)No credit arrangements expire in 2017 or 2018.
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.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

A portion of the $265 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $40 million.
Most of these bank credit arrangements contain covenants that limit debt levels and typically contain cross default provisions to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specified threshold. Mississippi Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements, as needed prior to expiration.
A portion of the $300 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2014 was approximately $40.1 million.
In connection therewith, Mississippi Power may also meet short-term cash needs throughseek to extend the maturity dates and/or increase or decrease the lending commitments thereunder.
To the extent available, Mississippi Power may seek to utilize a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power arewould be loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.
Mississippi Power had no commercial paper orDetails of short-term debt outstanding during the three-month period ended September 30, 2014.borrowings were as follows:
  
Short-term Debt at
June 30, 2015
 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Short-term bank debt $505
 1.4% $460
 1.4% $505
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.
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.Baa3 or below. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At SeptemberJune 30, 2014,2015, the maximum potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 wereequaled approximately $259$282 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system 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 couldhas impacted and may continue to impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.
On June 5, 2015, Fitch downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power.
Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Mississippi Power) on CreditWatch with negative implications.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities
In January 2014,March 2015, Mississippi Power repaid at maturity a $75 million bank term loan.
In April 2015, Mississippi Power entered into an 18-monthtwo floating rate bank loanloans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loan was for $250 millionloans in an aggregate principal amount and proceeds were used forof $275 million, working capital, and other general corporate purposes, including Mississippi Power's continuousongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In 2012, January 2014, and subsequent to September 30, 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 10.132% per annum for the period ended September 30, 2014 and 9.932% per annum for 2013, and are refundable to SMEPA upon termination of the asset purchase agreement related to such purchase or within 15 days of a request by SMEPA for a full or partial refund. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.
In May 2014,June 2015, Mississippi Power issued a 19-monthan 18-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loannote was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program. This loan was repaid on September 29, 2014.
In May 2014 and August 2014, the Mississippi Business Finance Corporation (MBFC) issued $12.3 million and $10.5 million, respectively,an aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Powerapproximately $301 million, the amount paid by Southern Company Project), Series 2013A for the benefit of Mississippi Power and proceeds were used to reimburse Mississippi Power for the costSMEPA pursuant to Southern Company's guarantee of the acquisition, construction, equipping, installation, and improvementreturn of certain equipment and facilities forSMEPA's deposit in connection with the lignite mining facility relatedtermination of the APA. See Note (B) to the Kemper IGCC. Any future issuancesCondensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of the Series 2013A bonds will be used for this same purpose. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities"Proposed Sale of Mississippi Power in Item 7 of the Form 10-KUndivided Interest to SMEPA" herein for additional information.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, 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.

127132



SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

128133



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
2014 2013 2014 20132015 2014 2015 2014
(in thousands) (in thousands)(in millions) (in millions)
Operating Revenues:              
Wholesale revenues, non-affiliates$331,878
 $265,752
 $870,093
 $705,828
$250
 $260
 $481
 $538
Wholesale revenues, affiliates102,631
 96,795
 242,527
 263,624
85
 68
 199
 140
Other revenues747
 2,220
 2,293
 5,517
2
 1
 4
 2
Total operating revenues435,256
 364,767
 1,114,913
 974,969
337
 329
 684
 680
Operating Expenses:              
Fuel178,281
 133,464
 420,896
 363,466
105
 118
 243
 243
Purchased power, non-affiliates28,156
 19,673
 72,643
 56,553
18
 17
 34
 45
Purchased power, affiliates12,796
 7,011
 58,475
 21,158
4
 16
 14
 46
Other operations and maintenance46,347
 41,309
 168,392
 154,920
69
 69
 121
 122
Depreciation and amortization59,508
 41,094
 162,524
 126,152
60
 52
 118
 103
Taxes other than income taxes5,458
 5,719
 16,842
 16,526
6
 6
 12
 11
Total operating expenses330,546

248,270
 899,772
 738,775
262

278
 542
 570
Operating Income104,710
 116,497
 215,141
 236,194
75
 51
 142
 110
Other Income and (Expense):              
Interest expense, net of amounts capitalized(22,983) (12,961) (66,952) (53,923)(23) (22) (45) (44)
Other income (expense), net5,511
 (791) 5,596
 (2,739)1
 
 1
 
Total other income and (expense)(17,472) (13,752) (61,356) (56,662)(22) (22) (44) (44)
Earnings Before Income Taxes87,238
 102,745
 153,785
 179,532
53
 29
 98
 66
Income taxes21,960
 17,592
 22,177
 37,265
Income taxes (benefit)1
 (3) 13
 
Net Income65,278
 85,153
 131,608
 142,267
52
 32
 85
 66
Less: Net income attributable to noncontrolling interest1,647
 
 3,694
 
Less: Net income attributable to noncontrolling interests6
 1
 6
 2
Net Income Attributable to Southern Power Company$63,631
 $85,153
 $127,914
 $142,267
$46
 $31
 $79
 $64
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 For the Three Months
Ended September 30,
 For the Nine Months
Ended September 30,
 2014 2013 2014 2013
 (in thousands) (in thousands)
Net Income$65,278
 $85,153
 $131,608
 $142,267
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of $(1), $-, $(1) and $-,
respectively
(1) 
 (1) 
Reclassification adjustment for amounts included in net income,
net of tax of $52, $213, $115 and $2,310 respectively
84
 338
 281
 3,619
Total other comprehensive income (loss)83
 338
 280
 3,619
Less: Comprehensive income attributable to noncontrolling interest1,647
 
 3,694
 
Comprehensive Income Attributable to Southern Power Company$63,714
 $85,491
 $128,194
 $145,886
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Net Income$52
 $32
 $85
 $66
Other comprehensive income (loss)
 
 
 
Less: Comprehensive income attributable to noncontrolling interests6
 1
 6
 2
Comprehensive Income Attributable to Southern Power Company$46
 $31
 $79
 $64
The accompanying notes as they relate to Southern Power are an integral part of these condensedconsolidated financial statements.

129134



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For the Nine Months
Ended September 30,
For the Six Months
Ended June 30,
2014 20132015 2014
(in thousands)(in millions)
Operating Activities:      
Net income$131,608
 $142,267
$85
 $66
Adjustments to reconcile net income to net cash provided from operating activities —      
Depreciation and amortization, total158,264
 131,955
121
 105
Deferred income taxes(6,340) 83,331
59
 (3)
Investment tax credits38,215
 (25,137)153
 26
Amortization of investment tax credits(10) (5)
Deferred revenues(2,452) 3,136
(21) (24)
Accrued income taxes, non-current100
 
Other, net3,853
 962
10
 7
Changes in certain current assets and liabilities —      
-Receivables(62,757) (28,486)(26) (34)
-Fossil fuel stock(1,565) 881
5
 (1)
-Materials and supplies(3,455) (5,902)
-Prepaid income taxes38,716
 (12,485)(102) 21
-Other current assets(720) (2,017)
 (1)
-Accounts payable26,989
 (4,282)(31) 24
-Accrued taxes62,124
 12,550
(110) 7
-Accrued interest(13,451) (8,306)
-Other current liabilities2,000
 235
18
 5
Net cash provided from operating activities371,029
 288,702
251
 193
Investing Activities:      
Plant acquisition(217,547) (111,600)
Plant acquisitions(408) (213)
Property additions(14,782) (463,873)(154) (11)
Change in construction payables(3,282) 292
38
 (3)
Payments pursuant to long-term service agreements(41,782) (40,978)(45) (23)
Investment in restricted cash(166) (20,000)
Other investing activities(9,996) (1,724)(1) (11)
Net cash used for investing activities(287,555) (637,883)(570) (261)
Financing Activities:      
Increase in notes payable, net19,995
 120,798
Proceeds —    
Senior notes
 300,000
Capital contributions(3,628) 1,897
Other long-term debt10,199
 22,722
Repayments — Other long-term debt(818) (220)
Distributions to noncontrolling interest(150) (146)
Contributions from noncontrolling interest7,492
 16,802
Increase (decrease) in notes payable, net(195) 73
Proceeds — Senior notes650
 
Distributions to noncontrolling interests(1) 
Contributions from noncontrolling interests78
 7
Payment of common stock dividends(98,340) (96,840)(65) (66)
Other financing activities(184) (2,287)(3) 9
Net cash provided from (used for) financing activities(65,434) 362,726
Net cash provided from financing activities464
 23
Net Change in Cash and Cash Equivalents18,040
 13,545
145
 (45)
Cash and Cash Equivalents at Beginning of Period68,744
 28,592
75
 69
Cash and Cash Equivalents at End of Period$86,784
 $42,137
$220
 $24
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —      
Interest (net of $(113) and $7,682 capitalized for 2014 and 2013, respectively)$78,496
 $55,190
Interest (net of $1 and $- capitalized for 2015 and 2014, respectively)$35
 $43
Income taxes, net(91,193) (6,518)(72) (59)
Noncash transactions — accrued property additions at end of period549
 36,370
Noncash transactions — Accrued property additions at end of period38
 5
The accompanying notes as they relate to Southern Power are an integral part of these condensedconsolidated financial statements.

130135



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets At September 30,
2014
 At December 31,
2013
 At June 30,
2015
 At December 31,
2014
 (in thousands) (in millions)
Current Assets:        
Cash and cash equivalents $86,784
 $68,744
 $220
 $75
Receivables —        
Customer accounts receivable 103,740
 73,497
 106
 77
Other accounts receivable 9,107
 3,983
 11
 15
Affiliated companies 46,089
 38,391
 40
 34
Fossil fuel stock, at average cost 20,743
 19,178
 17
 22
Materials and supplies, at average cost 58,234
 54,780
 59
 58
Prepaid service agreements — current 30,996
 81,206
Prepaid income taxes 47,374
 54,732
 122
 19
Other prepaid expenses 8,518
 7,915
Assets from risk management activities 810
 182
Deferred income taxes, current 144
 306
Other current assets 16
 21
Total current assets 412,395
 402,608
 735
 627
Property, Plant, and Equipment:        
In service 4,941,745
 4,696,134
 6,047
 5,657
Less accumulated provision for depreciation 981,568
 871,963
 1,125
 1,035
Plant in service, net of depreciation 3,960,177
 3,824,171
 4,922
 4,622
Construction work in progress 11,329
 9,843
 201
 11
Total property, plant, and equipment 3,971,506
 3,834,014
 5,123
 4,633
Other Property and Investments:        
Goodwill 1,839
 1,839
 2
 2
Other intangible assets, net of amortization of $7,583 and $5,614 at
September 30, 2014 and December 31, 2013, respectively
 47,787
 43,505
Other intangible assets, net of amortization of $10 and $8 at
June 30, 2015 and December 31, 2014, respectively
 69
 47
Total other property and investments 49,626
 45,344
 71
 49
Deferred Charges and Other Assets:        
Prepaid long-term service agreements 83,403
 73,676
 141
 124
Other deferred charges and assets — affiliated 2,556
 4,605
 13
 5
Other deferred charges and assets — non-affiliated 89,097
 68,853
 143
 112
Total deferred charges and other assets 175,056
 147,134
 297
 241
Total Assets $4,608,583
 $4,429,100
 $6,226
 $5,550
The accompanying notes as they relate to Southern Power are an integral part of these condensedconsolidated financial statements.

131136



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity At September 30,
2014
 At December 31,
2013
Liabilities and Stockholders' Equity At June 30,
2015
 At December 31,
2014
 (in thousands) (in millions)
Current Liabilities:        
Securities due within one year $531,184
 $599
 $525
 $525
Notes payable 19,995
 
 8
 195
Accounts payable —        
Affiliated 89,853
 56,661
 65
 78
Other 11,842
 20,747
 55
 30
Accrued taxes —    
Accrued income taxes 8,939
 161
 7
 72
Other accrued taxes 13,115
 2,662
Accrued interest 14,901
 28,352
 31
 30
Other current liabilities 6,549
 18,492
 53
 17
Total current liabilities 696,378
 127,674
 744
 947
Long-term Debt 1,098,078
 1,619,241
 1,737
 1,095
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 749,528
 724,390
 760
 863
Accumulated deferred investment tax credits 396,020
 340,269
 693
 601
Accrued income taxes, non-current 100
 
Deferred capacity revenues — affiliated 26,989
 15,279
 9
 15
Other deferred credits and liabilities — affiliated 858
 1,621
 
 1
Other deferred credits and liabilities — non-affiliated 10,740
 7,896
 22
 18
Total deferred credits and other liabilities 1,184,135
 1,089,455
 1,584
 1,498
Total Liabilities 2,978,591
 2,836,370
 4,065
 3,540
Redeemable Noncontrolling Interest 39,813
 28,778
 41
 39
Common Stockholder's Equity:        
Common stock, par value $.01 per share —        
Authorized — 1,000,000 shares        
Outstanding — 1,000 shares 
 
 
 
Paid-in capital 1,025,407
 1,029,035
 1,176
 1,176
Retained earnings 561,573
 531,998
 587
 573
Accumulated other comprehensive income 3,199
 2,919
 4
 3
Total common stockholder's equity 1,590,179
 1,563,952
 1,767
 1,752
Total Liabilities and Stockholder's Equity $4,608,583
 $4,429,100
Noncontrolling Interest 353
 219
Total Stockholders' Equity 2,120
 1,971
Total Liabilities and Stockholders' Equity $6,226
 $5,550
The accompanying notes as they relate to Southern Power are an integral part of these condensedconsolidated financial statements.

132137

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRDSECOND QUARTER 20142015 vs. THIRDSECOND QUARTER 20132014
AND
YEAR-TO-DATE 20142015 vs. YEAR-TO-DATE 20132014


OVERVIEW
Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants, and entry into PPAs primarily with investor ownedinvestor-owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.
Southern Power and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% byDuring the six months ended June 30, 2015, Southern Power acquired allapproximately 353 MWs of the outstanding membership interests of Adobe Solar, LLC (Adobe) and Macho Springs Solar, LLC (Macho Springs) on April 17, 2014 and May 22, 2014, respectively. The twoadditional solar facilities began commercial operationincluding the five Georgia construction projects located in May 2014 withTaylor and Butler Counties, as well as the approximate 20-MW Adobe solar photovoltaic facility serving a PPA with Southern California Edison (SCE) through 2034Lost Hills, Blackwell, and the approximate 50-MW Macho Springs solar photovoltaic facility serving a PPA with El Paso Electric Company (EPE) also through 2034.
Subsequent to September 30, 2014,North Star projects located in California. Southern Power through its wholly-owned subsidiary SG2 Holdings, LLC (Holdings), acquired all of the outstanding membership interests of SG2 Imperial Valley, LLC (SG2) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project. SG2 is constructingalso entered into an agreement to acquire an approximately 150-MW solar photovoltaic299-MW wind facility, located in Southern California (Imperial Facility), which is expected to begin commercial operation later in the fourth quarter 2014. Prior to commercial operation, subject toOklahoma, contingent upon certain termsconstruction and conditions, including the payment ofproject milestones. See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" herein for additional agreed upon capital contributions, First Solar will become a non-controlling minority member of Holdings. The Imperial Facility's output is contracted under a 25-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy.information.
To evaluate operating results and to ensure Southern Power's ability to meet its contractual commitments to customers, Southern Power focusescontinues to focus on several key performance indicators. These indicators include peak season equivalent forced outage rate, (Peak Season EFOR), contract availability, and net income. Peak Season EFOR defines the hours during peak demand times when Southern Power's generating units are not available due to forced outages (a low metric is optimal). Contract availability measures the percentage of scheduled hours delivered. Net income is the primary measureFor additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS OVERVIEW "Key Performance Indicators" of Southern Power's financial performance.Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(21.6) (25.3) $(14.4) (10.1)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$15 48.4 $15 23.4
Net income attributable to Southern Power for the thirdsecond quarter 20142015 was $63.6$46 million compared to $85.2$31 million for the corresponding period in 2013.2014. The decreaseincrease was primarily due to an increase in depreciation, lower capitalized interest due to reduced construction, and lower ITCs in income taxes, partially offset by an increase in energy revenue from non-affiliates primarily due to increased revenue from new solar contracts.and lower fuel and purchased power expenses.
Net income attributable to Southern Power for year-to-date 20142015 was $127.9$79 million compared to $142.3$64 million for the corresponding period in 2013.2014. The decreaseincrease was primarily due to a decrease in capacity revenues, increased depreciation arising from new

133

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

solar facilities, lower ITCs in income taxes, and lower capitalized interest due to reduced construction. The decrease waspurchased power expenses, partially offset by an increaseincreases in energy revenue from non-affiliates primarily from new solar contractsdepreciation and beneficial changes in certain state income taxes.
Wholesale Revenues Non-Affiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$66.1 24.9 $164.3 23.3
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(10) (3.8) $(57) (10.6)
Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs 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.

Details
138

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale revenues from non-affiliates for the second quarter 2015 were as follows:
 
Third Quarter
 2014
 
Year-to-Date
2014
 (in millions) (% change) (in millions) (% change)
Wholesale Revenues – Non-Affiliates, prior year$265.8
   $705.8
  
Change resulting from -       
Capacity(4.4) (1.6) (10.0) (1.4)
Energy – solar20.0
 7.5
 60.3
 8.5
Energy – other50.5
 19.0
 114.0
 16.2
Wholesale Revenues – Non-Affiliates, current year$331.9
 24.9 % $870.1
 23.3 %
$250 million compared to $260 million for the corresponding period in 2014. The increasedecrease was due to a $5 million decrease in energy – solar was primarily a result of new solar PPAs. The increase in energy – other, primarily from gas plants, arose from requirements contracts, increased revenue from existing contracts, and energy sales, not under PPAs, primarily as a result of higher demand. The increases weredecreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by aincreased sales volumes and new solar PPAs. The decrease in capacityenergy revenues primarily as a result of periodic scheduled adjustments to requirements contracts. The increase in energy sales reflects a 4.6% and 16.9% increase14% decrease in the average price of energy, andpartially offset by a 47.0% and 26.8%12% increase in KWH salessales. In addition, capacity revenues decreased $5 million primarily due to PPA expirations.
Wholesale revenues from non-affiliates for year-to-date 2015 were $481 million compared to $538 million for the third quartercorresponding period in 2014. The decrease was due to a $44 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and year-to-date 2014, respectively.
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Power Sales Agreements"new solar PPAs. The decrease in energy revenues reflects a 17% decrease in the average price of Southern Powerenergy, partially offset by a 5% increase in Item 7 of the Form 10-K for additional information.KWH sales. In addition, capacity revenues decreased $13 million primarily due to PPA expirations.
Wholesale Revenues Affiliates
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$5.8 6.0 $(21.1) (8.0)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$17 25.0 $59 42.1
Wholesale revenues from sales to affiliate companies 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.
Wholesale revenues from affiliates for the thirdsecond quarter 20142015 were $102.6$85 million compared to $96.8$68 million for the corresponding period in 2013.2014. The increase was the result of a $9.3$10 million increase in energy revenue, primarily due to anrevenues and a $7 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC reflectingas a 13.2%result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 61% increase in KWH sales, partially offset by a 21% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.
Wholesale revenues from affiliates for year-to-date 2015 were $199 million compared to $140 million for the corresponding period in 2014. The increase was the result of a $50 million increase in energy revenues and a $9 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of higherlower natural gas prices. Thisprices, which increased demand for Southern Power Company's resources. The increase wasin energy revenues reflects a 110% increase in KWH sales, partially offset by a $3.5 million22% decrease in the average price of energy. The increase in capacity revenue as arevenues was primarily the result of new PPAs.
Fuel and Purchased Power Expenses
   Second Quarter 2015
vs.
Second Quarter 2014
  Year-to-Date 2015
vs.
Year-to-Date 2014
  (change in millions)
(% change) (change in millions) (% change)
Fuel $(13) (11.0) $
 
Purchased power – non-affiliates 1
 5.9 (11) (24.4)
Purchased power – affiliates (12) (75.0) (32) (69.6)
Total fuel and purchased power expenses $(24)   $(43)  
Southern Power's PPAs for natural gas-fired generation generally provide that the completionpurchasers are responsible for substantially all of an existing contract for Plant Dahlberg.the cost of fuel. Consequently, any increase or decrease in such fuel cost is generally

134139

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale revenues from affiliates for year-to-date 2014 were $242.5 million compared to $263.6 million for the corresponding period in 2013. The decrease was the result of a decrease in energy revenue, primarily due to a $24.2 million decrease in energy sales under the IIC, reflecting a 25.2% decrease in KWH sales, primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. Also contributing to the decrease was a $4.6 million decrease in capacity revenue as a result of the completion of an existing contract for Plant Dahlberg. The decrease was partially offset by a $7.7 million increase in energy revenues under existing contracts, reflecting a 21.7% increase in the average price of energy and a 14.2% increase in KWH sales, primarily as a result of higher natural gas prices and increased demand.
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
   Third Quarter 2014
vs.
Third Quarter 2013
  Year-to-Date 2014
vs.
Year-to-Date 2013
  (change in millions)
(% change) (change in millions) (% change)
Fuel $44.9
 33.6 $57.4
 15.8
Purchased power – non-affiliates 8.4
 42.9 16.1
 28.6
Purchased power – affiliates 5.8
 82.8 37.3
 175.8
Total fuel and purchased power expenses $59.1
   $110.8
  
Southern Power PPAs for natural gas-fired generation generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel cost is generally accompanied by an increase or decrease in related fuel revenuerevenues under the PPAs 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.
Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power Company, affiliate-owned generation,affiliate companies, or external purchases.parties.
In the thirdsecond quarter 2014,2015, total fuel and purchased power expenses were $219.2$127 million compared to $160.1$151 million for the corresponding period in 2013. Fuel and purchased power expenses increased $59.12014. The decrease was the result of a $58 million reflecting a 13.7% increasedecrease in the average cost of fuel and purchased power primarily due to lower natural gas andprices, partially offset by a 14.2%$34 million net increase in the average cost of purchased power primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. This increase also reflects a 19.1% increase in thetotal volume of KWHs generated and purchased and generated primarily as a result of higher demand.due to increased demand resulting from lower natural gas prices.
For year-to-date 2014,2015, total fuel and purchased power expenses were $552.0$291 million compared to $441.2$334 million for the corresponding period in 2013. Fuel2014. The decrease was a result of a $154 million decrease in the average cost of fuel and purchased power expensesprimarily due to lower natural gas prices, partially offset by a $111 million net increase in the total volume of KWHs generated and purchased primarily due to increased $110.8demand resulting from lower natural gas prices.
Fuel
In the second quarter 2015, fuel expense was $105 million reflectingcompared to $118 million for the corresponding period in 2014. The decrease was due to a 24.2% increase in36.1% decrease associated with the average cost of natural gas and a 20.1% increase in the average cost of purchased power primarily as a result of higher natural gas prices and the availability of lower cost affiliate power.
Fuel
In the third quarter 2014, fuel expense was $178.3 million compared to $133.4 million for the corresponding period in 2013. The increase was due to a $22.5 million increase associated with the higher average cost of fuel per KWH generated, primarily due to higher average natural gas prices andpartially offset by a $22.4 million40.6% increase associated with the volume of KWHs generated, primarily due to higher demand.as a result of increased demand resulting from lower natural gas prices.
For year-to-date 2015 and for the corresponding period in 2014, fuel expense was $420.9$243 million. While there was no overall change, a $152 million increase in the total cost of fuel attributable to the volume of KWHs generated was offset by a $152 million decrease in the average cost of natural gas per KWH generated.
Purchased Power Non-Affiliates and Affiliates
In the second quarter 2015, purchased power expense was $22 million compared to $363.5$33 million for the corresponding period in 2013.2014. For year-to-date 2015, purchased power expense was $48 million compared to $91 million for the corresponding period in 2014. The decreases were primarily the result of 37.4% and 45.6% decreases in the volume of KWHs purchased in the second quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices which resulted in higher use of Southern Power Company's generation resources.
Other Operations and Maintenance Expenses
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$—  $(1) (0.8)
In the second quarter 2015 and for the corresponding period in 2014, other operations and maintenance expenses were $69 million. While there was no overall change, a decrease in outage expense of $10 million was offset by a $10 million increase in expenses associated with support services, transmission, and new plants placed in service in 2014 and 2015.
For year-to-date 2015, other operations and maintenance expenses were $121 million compared to $122 million for the corresponding period in 2014. The decrease was primarily due to a $79.1$17 million increase associated with the higher average cost of fuel per KWHdecrease in outage expense,

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generated primarily due to higher average natural gas prices, partiallylargely offset by a $21.7$16 million decreaseincrease in expenses associated with the volume of KWHs generated primarily as a result of the availability of lower cost affiliate power.
Purchased Power
In the third quarter 2014, purchased power expense was $40.9 million compared to $26.7 million for the corresponding period in 2013. The increase was due to a $9.1 million increase associated with the volume of KWHs purchased due to the availability of lower cost affiliate power and a $5.1 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices.
For year-to-date 2014, purchased power expense was $131.1 million compared to $77.7 million for the corresponding period in 2013. The increase was due to a $31.5 million increase associated with the volume of KWHs purchased due to the availability of lower cost affiliate power and a $21.9 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices.
Other Operations and Maintenance Expenses
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$5.0 12.2 $13.5 8.7
In the third quarter 2014, other operations and maintenance expenses were $46.3 million compared to $41.3 million for the corresponding period in 2013. For year-to-date 2014, other operations and maintenance expenses were $168.4 million compared to $154.9 million for the corresponding period in 2013. The increases were primarily due to scheduled outage and maintenance related costs and increases in labor costs, as well as costs associated with the new solar plants.
Depreciation and Amortization
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$18.4 44.8 $36.3 28.8
In the third quarter 2014, depreciation and amortization was $59.5 million compared to $41.1 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $162.5 million compared to $126.2 million for the corresponding period in 2013. The increases were primarily due to an increase in depreciation expense related to solar facilities being placed in service in 2013 and 2014 and additional component depreciation as a result of production being greater during the summer months.
See Note (A) to the Condensed Financial Statements herein for additional information.
Interest Expense, Net of Amounts Capitalized
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$10.0 77.3 $13.0 24.2
In the third quarter 2014, interest expense, net of amounts capitalized was $23.0 million compared to $13.0 million for the corresponding period in 2013. For year-to-date 2014, interest expense, net of amounts capitalized was $66.9 million compared to $53.9 million for the corresponding period in 2013. The increases were primarily due to a decrease in capitalized interest due to reduced construction activities in 2014 and the issuance of senior notes in July 2013.

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Other Income (Expense), Net
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$6.3 N/M $8.3 N/M
N/M – Not meaningful
In the third quarter 2014, other income (expense), net was $5.5 million compared to $(0.8) million for the corresponding period in 2013. For year-to-date 2014, other income (expense), net was $5.6 million compared to $(2.7) million for the corresponding period in 2013. The increases were primarily due to the recognition of a bargain purchase gain arising from a solar acquisition.
See Note (I) to the Condensed Financial Statements herein for additional information.
Income Taxes
Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$4.4 24.8 $(15.1) (40.5)
In the third quarter 2014, income taxes were $22.0 million compared to $17.6 million for the corresponding period in 2013. The increase was primarily due to lower ITC-related items and state apportionment changes, partially offset by lower pretax income and an increase in state income tax credits.
For year-to-date 2014, income taxes were $22.2 million compared to $37.3 million for the corresponding period in 2013. The decrease was primarily due to lower pretax income, the impact of state apportionment changes reducing Southern Power's deferred tax liabilities resulting from the addition ofsupport services, new plants placed in service in 2014 and 2013, a change2015, and transmission.
Depreciation and Amortization
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$8 15.4 $15 14.6
In the second quarter 2015, depreciation and amortization was $60 million compared to $52 million for the corresponding period in 2014. For year-to-date 2015, depreciation and amortization was $118 million compared to $103 million for the corresponding period in 2014. The increases were primarily related to solar facilities placed in service in 2014 and 2015.
Income Taxes (Benefit)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$4 133.3 $13 N/M
N/M – Not meaningful
In the second quarter 2015, income taxes were $1 million compared to an income tax filing methodbenefit of $3 million for North Carolina, an increasethe corresponding period in 2014. For year-to-date 2015, income taxes were $13 million. The increases were primarily due to higher pre-tax earnings in 2015 and beneficial state income tax credits, and beneficial changes in certain state income tax laws2014, partially offset by lower ITC-related items.increased federal income tax benefits related to ITCs in 2015.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern 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:include Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's target market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy, including successfully expanding investments in renewable energy projects, and to construct generating facilities.facilities, including the impact of federal ITCs.
Other factors that could influence future earnings include weather, demand, cost of generating units within the power pool, and operational limitations. 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, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that

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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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Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM) and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, North Carolina, and the EPA's proposed rulesTexas) to revise or remove state implementation plan (SIP) provisions regarding the regulation of excess emissions that occur during periods of startup, shutdown, or malfunction (SSM).SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back toJuly 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for further proceedings. On October 23, 2014, the U.S. Courta number of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements,states, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.
On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama, Florida, Georgia, North Carolina, and North Carolina)Texas. The court's decision leaves the emissions trading program in place and remands the rule to revise their SSM provisions within 18 months after issuance of the finalEPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of the proposed SSM rulethis decision will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challengesadditional rulemaking and cannot be determined at this time.
The ultimate outcome of these matters cannot be determined at this time.
Water QualityGlobal Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.
On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.CO2 from fossil-fuel-fired electric generating units.
On June 18, 2014,August 3, 2015, the EPA publishedreleased pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the proposed Clean Power Plan, setting forthfinal rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to address CO2 emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and finalmeet EPA-mandated CO2 emission rate goalsrates for existing units. The EPA's final guidelines require state plans to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposedmeet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through existing PPAs. However, the ultimate financial and operational impact of the final rules on Southern Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
Acquisitions
During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy, which are included in Southern Power's capital program estimates for modified and2015.
Kay County Wind Facility
On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on

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reconstructed fossil fuel-fired electric generating units. The proposed guidelines and standards could result in operational restrictions and material compliance costs. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through market-based contracts.
On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the Clean Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upon numerous factors. These factors include: the structure, timing, and content of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and court decisions; the impact of future changes in generation and emissions-related technology and costs; and the time periods over which compliance will be required.
On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of the U.S. Supreme Court's decision cannot be determined at this time.
Acquisitions
Adobe Solar, LLC
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Acquisitions" of Southern Power in Item 7 of the Form 10-K and Note (I) to the Condensed Financial Statements herein for additional information.
On April 17, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Adobe from Sun Edison, LLC, the original developer of the project. Adobe constructedperformance testing. Kay Wind is constructing and owns an approximately 20-MW solar photovoltaic299-MW wind facility in KernKay County, California.Oklahoma. The solarwind facility beganis expected to begin commercial operation on May 21, 2014in late 2015, and the entire output of the plantfacility is contracted under aseparate 20-year PPAPPAs with SCE.
Macho Springs Solar, LLCWestar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
Lost Hills-Blackwell Solar Facilities
On May 22, 2014,April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and TRE, through STR, acquiredthe class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the outstanding membership interests of Macho Springs from First Solar Development, LLC,federal tax benefits with respect to the original developer of the project. Macho Springstransaction. Lost Hills Blackwell constructed and owns anthe approximately 50-MW22-MW Lost Hills and the approximately 13-MW Blackwell solar photovoltaic facilityfacilities in LunaKern County, New Mexico. TheCalifornia. These solar facilityfacilities began commercial operation on May 23, 2014April 17, 2015, and thetheir entire output of the plant is contracted under a 20-year PPA with EPE. See Note (I)PPAs, initially to the Condensed Financial Statements herein for additional information.City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years.
SG2 Imperial Valley, LLCNorth Star Solar Facility
Subsequent to SeptemberOn April 30, 2014,2015, Southern Power Company, through its wholly-owned subsidiary Holdings,SRP, acquired all100% of the outstandingclass A membership interests of SG2NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project. SG2project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is constructingentitled to substantially all of the Imperial Facility, anfederal tax benefits with respect to the transaction. North Star constructed and owns the approximately 150-MW61-MW North Star solar photovoltaic facility in Southern California, which is expected to beginFresno County, California. The solar facility began commercial operation later inon June 20, 2015, and the fourth quarter 2014. The Imperial Facility'sentire output of the project is contracted under a 25-year20-year PPA with San DiegoPacific Gas &and Electric Company, a subsidiary of Sempra Energy.Company.
Construction Projects
In connectionDecember 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of five separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this acquisition, Holdings made an aggregate payment (consisting of cash consideration and a secured promissory note) of approximately $128 million to the subsidiary of First Solar and became obligated to pay the contract price as it becomes due under the construction contract for the Imperial Facility. In addition, subject to certain terms and conditions, a subsidiary of First Solar will be admitted as a minority member of Holdings, andtime.

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subsidiaries of each of Southern Power and First Solar, as members of Holdings, will make capital contributionsCompany's construction projects are detailed in the table below:
Solar ProjectSellerNameplate CapacityCounty Location in GeorgiaExpected Commercial Operation DatePPA Counterparty
for Entire Plant Output
PPA Contract PeriodEstimated Construction Cost 
  (MW)    (in millions) 
Taylor CountyN/A146TaylorFourth quarter 2016Cobb, Flint, and Sawnee Electric Membership Corporations25 years$260
-$280 
Decatur ParkwayTradeWind Energy, Inc.84DecaturDecember 2015
Georgia Power(a)
25 years$170
-$173(b)
Decatur CountyTradeWind Energy, Inc.20DecaturDecember 2015
Georgia Power(a)
20 years$45
-$47(b)
ButlerCERSM, LLC and Community Energy, Inc.103TaylorDecember 2016
Georgia Power(a)
30 years$220
-$230(b)
PawpawLongview Solar, LLC30TaylorDecember 2015
Georgia Power(a)
30 years$70
-$80(b)
Butler Solar FarmStrata Solar Development, LLC20TaylorDecember 2015
Georgia Power(a)
20 years$42
-$48(b)
(a) Subject to Holdings that will be used to pay off the previously issued secured promissory note and to fund the Imperial Facility's construction costs. As a result of these capital contributions, the aggregate purchase price payable by Southern Power forFERC approval.
(b) Includes the acquisition is approximately $508 million. Following these capital contributions, Southern Power will indirectly own 100% of the class A membership interests of Holdings and be entitled to 51%price of all cash distributions from Holdings, and First Solar will indirectly own 100% of the class Boutstanding membership interests of Holdings and be entitled to 49% of all cash distributions from Holdings. In addition, Southern Power will be entitled to substantially all of the federal tax benefits with respect to this transaction.
If the Imperial Facility does not achieve substantial completion by a certain date, Southern Power may require that First Solar make a rescission payment to Southern Power in an amount equal to Southern Power's investment in Holdings, and Southern Power would be required to transfer its ownership interests in SG2 back to First Solar.
The ultimate outcome of this matter cannot be determined at this time.interests.
See Note (I) to the Condensed Financial StatementsMANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
Power Sales Agreements
See MANAGEMENT'S DISCUSSION AND ANALYSISBUSINESSFUTURE EARNINGS POTENTIAL"The Southern Company System"Power Sales Agreements" of Southern PowerPower" in Item 71 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.
Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern Power has assumed or entered into additional PPAs duringPower's existing fleet, the past nine months primarily in connection with its acquisitions of solar facilities. The coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of SeptemberJune 30, 20142015 from the period ended December 31, 2013.2014.
FERC Matters
Southern Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

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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, 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 air quality and water standards, has increased generallyoccurred throughout the U.S. In particular, personal injury, property damage, and otherThis litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.matters.
The ultimate outcome of such pending or potential litigation against Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements 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 ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.
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, Depreciation, and ITCs.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Southern Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU has not yet been determined.
On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Power currently reflects unamortized debt issuance costs in other deferred charges and assets – non-affiliated on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Power.

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policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.
Recently Issued Accounting Standards
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Southern Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at SeptemberJune 30, 2014.2015. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangementsagreements 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 $371.0$251 million for the first ninesix months of 2014, an increase of $82.3 million as2015, compared to $193 million for the first ninesix months of 2013.2014. The increase in cash provided from operating activities was primarily due to cash received for ITCs related to new plants placedlower purchased power costs and an increase in service in 2013 and 2014.income tax benefits received. Net cash used for investing activities totaled $287.6$570 million for the first ninesix months of 20142015 primarily due to the Lost Hills, Blackwell, and North Star acquisitions and expenditures related to the acquisitionsconstruction of Adobe and Macho Springs and payments pursuant to long-term service agreements.new solar facilities. Net cash used forprovided from financing activities totaled $65.4$464 million for the first ninesix months of 20142015 primarily due to the paymentissuance of common stock dividends.additional senior notes in May 2015. Fluctuations in cash flow from financing activities vary yearfrom period to yearperiod based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninesix months of 20142015 include a $136.0$300 million increase in plant in service, net of depreciation primarily due to the Lost Hills, Blackwell, and North Star acquisitions and a $190 million increase in CWIP primarily due to the construction of Adobe and Macho Springs.new solar facilities. Other significant changes which wereinclude an increase in long-term debt of $642 million primarily theas a result of the timing and amountissuance of ITCs recognizedsenior notes in 2014 as compared to 2013, include a $55.8 million increase in accumulated deferred investment tax credits, and a $25.1 million increase in accumulated deferred income taxes. Additionally, there was a $20.0 million increase in notes payable for commercial paper and a $33.2 million increase in affiliated accounts payable.May 2015.
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, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. ApproximatelySubsequent to June 30, 2015, $525 million will be required through September 30, 2015 to fundof long-term debt was repaid at maturity. There are no other scheduled maturities of long-term debt.debt through June 30, 2016.
The constructioncapital 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 and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to be approximately $800 million$1.4 billion for 2014,2015, which includes expenditures related to the acquisitionapproximately $1.3 billion for acquisitions and/or construction of SG2 of approximately $508 million.new generating facilities. See Note (I) to the Condensed Financial Statements herein for additional information. Actual constructioncapital costs may vary from these estimates because of changes in factors such as: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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sources of Capital
Southern Power may useplans 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, external funds, orshort-term debt, securities issuances, term loans, and equity capital or loanscontributions 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.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 Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. In 2015, Southern Power has utilized the capital markets to issue additional senior notes and expects to utilize the capital

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

markets, bank term loans, and commercial paper markets, as the source of funds for the majority of its maturities and to meet short-term liquidity needs, including funding acquisition and construction costs.
To meet liquidity and capital resource requirements, Southern Power had at SeptemberJune 30, 20142015 cash and cash equivalents of approximately $86.8$220 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $499$466 million is unused.
The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power Company.Power. Southern Power Company is currently in compliance with all covenants in the Facility.
Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power Company's commercial paper program. Subject to applicable market conditions, Southern Power Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. 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'sPower Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes.purposes, including maturing debt. Subsequent to June 30, 2015, commercial paper was used to partially fund the maturity of long-term debt in July 2015.
Details of short-term borrowings were as follows:
  
Commercial Paper at
the End of the Period
 
Commercial Paper During the Period(a)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
September 30, 2014: $20
 0.3% $44
 0.3% $83
  
Commercial Paper at
the End of the Period
 
Commercial Paper During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
June 30, 2015: $
 % $163
 0.6% $339
(a)(*) Average and maximum amounts are based upon daily balances during the three-month period ended SeptemberJune 30, 2014.2015.
ManagementSouthern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, short-term bank notes, and cash.operating cash flows.
Credit Rating Risk
Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at June 30, 2015 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and Baa2$9
At BBB- and/or Baa3320
Below BBB- and/or Baa31,081

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The maximum potential collateral requirements under these contracts at September 30, 2014 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and Baa2$9
At BBB- and/or Baa3318
Below BBB- and/or Baa31,018
Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Power Company'sPower's ability to access capital markets, particularly the short-term debt market.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power'sPower Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.
Financing Activities
During the nine months ended September 30, 2014,In May 2015, Southern Power prepaid $0.8Company issued $350 million aggregate principal amount of long-term debt payable to TRE and issued $3.9 million due April 30, 2034, $5.3 million due May 31, 2034, $0.8 million due April 30, 2033, and an additional $0.1 millionSeries 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2032 under promissory notes payable to TRE related to the financing of Adobe, Macho Springs, Campo Verde Solar, LLC, and Apex Nevada Solar, LLC, respectively.2015.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power Company 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
(UNAUDITED)


INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
Note Page Number
A
B
C
D
E
F
G
H
I
J





INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.
RegistrantApplicable Notes
Southern CompanyA, B, C, D, E, F, G, H, I, J
Alabama PowerA, B, C, E, F, G, H
Georgia PowerA, B, C, E, F, G, H
Gulf PowerA, B, C, E, F, G, H
Mississippi PowerA, B, C, E, F, G, H
Southern PowerA, B, C, D, E, G, H, I


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)

(A)INTRODUCTION
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 20132014 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended SeptemberJune 30, 20142015 and 2013.2014. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. In March 2015, in connection with this retirement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.
In June 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error, as well as the current period. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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(UNAUDITED)

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.
On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of any registrant.
Asset Retirement Obligations
See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and AlabamaMississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information.information regarding the EPA's regulation of CCR.
AssetOn April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new asset retirement obligations (ARO) for facilities that are computedsubject to the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the present valuequantities of CCR at each site, the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. In September 2014, Alabama Power performed a new ARO liability cost study relatedtraditional operating companies expect to Alabama Power's assets, which increased the estimated ARO liability by approximately $52 million.periodically update these estimates.
As of SeptemberJune 30, 2014 and 2013,2015, details of the AROAROs, including those related to Alabama Power's assetsthe CCR Rule, included in Southern Company's and Alabama Power'sthe traditional operating companies' Condensed Balance Sheets herein arewere as follows:

2014
2013Southern Company Alabama Power Georgia Power 
Gulf
Power
 Mississippi Power
(in millions)(in millions)
Balance at beginning of year$730

$589
$2,201  $829  $1,255  $17  $48 
Liabilities incurred


612  401    71  97 
Liabilities settled(2)

(10) (1) (9)    
Accretion33

29
53  23  28    1 
Cash flow revisions52

102
58    82  4  2 
Balance at end of period$813

$720
$2,914  $1,252  $1,356  $92  $148 
The increaseincreases in liabilities incurred and cash flow revisions as of Septemberfor the six months ended June 30, 20142015 primarily relatesrelate to an increase in Alabama Power's AROs associated with asbestos at its steam generation facilities.facilities impacted by the CCR Rule.
In connection with a proposed settlement related to the closure of Plant Scholz, Gulf Power may incur additional AROs associated with CCR of approximately $15 million to $35 million.

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(UNAUDITED)
Depreciation
Beginning in 2014, Southern Power changed the method of depreciation for its property, plant, and equipment from composite depreciation to component depreciation. As a result, certain generation assets are depreciated on a units-of-production basis to better match outage and maintenance costs to the usage of, and revenues from, these assets. The expense will fluctuate quarterly based on unit run time, but this change in methodology is not expected to have a material impact on an annual basis on the financial statements of Southern Company or Southern Power. The book value of plant-in-service as of September 30, 2014 that is depreciated on a units of production basis was approximately $470 million.
Recently Issued Accounting Standards
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The registrants are currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

(B)CONTINGENCIES AND REGULATORY MATTERS
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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 air quality and water standards, has increased generallyoccurred throughout the U.S. In particular, personal injury, property damage, and otherThis litigation has included claims for damages alleged to have been caused by CO2 and other emissions, coal combustion residuals,CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Environmental Matters
New Source Review Actions
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions seeksought penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) has been actively litigatedwas partially settled in 2006 through a consent decree with the EPA, and additional claims remain pending in the U.S. District Court for the Northern District of Alabama, resulting inAlabama. On June 25, 2015, the U.S. Department of Justice filed a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment forjoint stipulation between Alabama Power, onthe EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims and dismissal offor relief alleged in the case with prejudice in 2011. In September 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of

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(UNAUDITED)

against Alabama Power, and the case has been transferred back toPower. If approved by the U.S. District Court for the Northern District of Alabama, for further proceedings.Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
Southern Company and each traditional operating company believe each such traditional operating company complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.
Environmental RemediationPerformance Evaluation Plan
The Southern Company system must comply with environmental laws and regulations that coverOn March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations,Mississippi PSC suspended the Southern Company system could incur substantial costsfiling to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.
Georgia Power's environmental remediation liability as of September 30, 2014 was $19 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claimsallow it more time for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.
Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.
In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In February 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion ruling that Georgia Power has no liability in the private action. In May 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.
review. The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors andthis matter cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $49.5 million as of September 30, 2014. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subjecttime.

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NOTES TO THE CONDENSED MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)CONDITION AND RESULTS OF OPERATIONS

to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, there was no impact on net income as a result of these liabilities.Ad Valorem Tax Adjustment
In 2003,On April 23, 2015, Mississippi Power and numerous other entities were designated byfiled its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates. On May 26, 2015, the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers.PSC suspended the filing to allow it more time to review. The TCEQ approved the final site remediation plan in December 2013 and, on March 28, 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability is $0.6 million as of September 30, 2014 and is expected to be recovered through the ECO Plan.
The finalultimate outcome of these mattersthis matter cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent
Integrated Coal Gasification Combined Cycle
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Integrated Coal Gasification Combined Cycle" of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
Nuclear Fuel Disposal Cost Litigation
Acting through the DOEin Item 7 and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
As a result of the first lawsuit, Georgia Power recovered approximately $27 million, based on its ownership interests, and Alabama Power recovered approximately $17 million, representing the vast majority of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In 2012, Alabama Power credited the award to cost of service for the benefit of customers. Also in 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers.
In 2008 and again on March 4, 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2005 through December 31, 2010 and from January 1, 2011 through December 31, 2013, respectively. Damages will continue to accumulate until the issue is resolved or storage is provided. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.
FERC Matters
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding the authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the costs subject to the cost cap and the Cost Cap Exceptions remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court decision), and actual costs incurred as of June 30, 2015, as adjusted for the Court's decision, are as follows:

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Cost Category
2010 Project Estimate(f)
 Current Estimate Actual Costs at June 30, 2015
 (in billions)
Plant Subject to Cost Cap(a)
$2.40
 $4.96
 $4.51
Lignite Mine and Equipment0.21 0.23 0.23
CO2 Pipeline Facilities
0.14 0.11 0.11
AFUDC(b)(c)
0.17 0.62 0.52
Combined Cycle and Related Assets Placed in
  Service – Incremental(d)

 0.02
 
General Exceptions0.05 0.10 0.08
Deferred Costs(c)(e)

 0.19 0.15
Total Kemper IGCC(a)(c)
$2.97
 $6.23
 $5.60
(a)
The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.
(b)Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.
(c)Amounts in the Current Estimate reflect estimated costs through March 31, 2016.
(d)Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.
(e)The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."
(f)
The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.08 billion), $2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, $16 million in other deferred charges and assets, and $24 million in AROs in the balance sheet, with $1 million previously expensed.
Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23 million ($14 million after tax) in the second quarter 2015 and $9 million ($6 million after tax) in the first quarter 2015. These amounts are in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. The increases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to equipment rework, scope modifications, and the related additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion

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cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.
Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material.
Rate Recovery of Kemper IGCC Costs
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 2015 Rate Case and any alternative proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements.
2013 Settlement Agreement
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the

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estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.
2013 MPSC Rate Order
Consistent with the terms of the 2013 Settlement Agreement, in March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC through the in-service date until directed to do otherwise by the Mississippi PSC.
In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.
In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Mississippi Power.
2015 Mississippi Supreme Court Decision
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.
2015 Rate Case
As a result of the 2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On

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May 15, 2015, Mississippi Power filed the 2015 Rate Case with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
On July 10, 2015, Mississippi Power filed a Supplemental Notice with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal, In-Service Asset Proposal, for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.
The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
If the Mississippi PSC does not act on the Supplemental Notice or the 2015 Rate Case within 120 days of the Supplemental Notice filing, Mississippi Power expects to put one of the three viable alternative rate proposals into effect as temporary rates under bond and subject to refund pursuant to Mississippi state law.
Mississippi Power also expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 2015 of $6.23 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
Prudence Reviews
The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for

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interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of June 30, 2015, the regulatory asset balance associated with the Kemper IGCC was $198 million. The projected balance at March 31, 2016 is estimated to total approximately $276 million. The amortization period for any such costs approved for recovery remains subject to approval by the Mississippi PSC.
See "2015 Mississippi Supreme Court Decision" herein for additional information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.
See Note 1 to the financial statements of Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact

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on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest to SMEPA
In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and SMEPA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits Section 174 Research and Experimental Deduction," respectively, herein for additional information. The ultimate outcome of this tax 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 air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
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 in Note (B) to the Condensed Financial Statements 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 ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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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, Pension and Other Postretirement Benefits, and AFUDC.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2015, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.
As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of $2.08 billion ($1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2015.
Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

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Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" 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 and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's constructionadditional information.
Asset Retirement Obligations
AROs are computed as the fair value of the Kemper IGCC.ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Mississippi Power has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. Mississippi Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On March 31, 2014,April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Mississippi Power reached a settlement agreement with its wholesale customersrecorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and filed a requestpost-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the FERCCCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Mississippi Power considers the liabilities for an increaseAROs to be critical accounting estimates.
See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Mississippi Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the Municipalbalance sheet as a direct deduction from the carrying amount of that debt liability and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, approved by the FERC on May 20, 2014, provides that base rates under the MRA cost-based electric tariff will increase approximately $10.1 million annually, with revised ratesis effective for services renderedfiscal years beginning May 1, 2014.after December 15, 2015. Mississippi Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its

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MISSISSIPPI POWER COMPANY
NOTES TO THE CONDENSED MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)CONDITION AND RESULTS OF OPERATIONS

Retail Regulatory Mattersbalance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.
AlabamaFINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Mississippi Power's financial condition was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections, which as of June 30, 2015 was approximately $353 million including associated carrying costs, and the termination of the Mirror CWIP rate will further adversely impact Mississippi Power's financial condition and its ability to obtain financing needed for normal business operations and completion of the Kemper IGCC. Earnings for the six months ended June 30, 2015 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. Earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC.
In addition to funding normal business operations and projected capital expenditures, Mississippi Power's cash requirements primarily consist of $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs. In addition, Mississippi Power issued an 18-month promissory note to Southern Company in the aggregate principal amount of approximately $301 million related to the refund to SMEPA and expects to enter into a similar promissory note with Southern Company to fund the Mirror CWIP refund. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA," "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order,"" – 2015 Mississippi Supreme Court Decision," and " – 2015 Rate Case" herein for additional information. For the three-year period from 2015 through 2017, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental equipment for existing generating units, including the Plant Daniel scrubber project, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. See "Sources of Capital" herein for additional information.
Through June 30, 2015, Mississippi Power has incurred non-recoverable cash expenditures of $1.62 billion and is expected to incur approximately $0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.
During the first six months of 2015, Mississippi Power received $75 million in equity contributions from Southern Company. In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. On June 3, 2015, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company as a result of Southern Company's refund of approximately $301 million in deposits and associated interest to SMEPA in connection with the termination of the APA. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled $309 million for the first six months of 2015, an increase of $131 million as compared to the corresponding period in 2014. The increase in cash provided from operating activities is primarily due to R&E tax deductions and bonus depreciation reducing tax payments, an increase in fuel recovery, and a decrease in receivables, partially offset by the timing of payments for accounts payable and fuel purchases. See Notes (B) and Note (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $460 million for the first six months of 2015 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $230 million for the first six months of 2015 primarily due to short-term bank loans, capital contributions from Southern Company, and short-term borrowings, partially offset by redemptions of long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2015 include a decrease in securities due within one year of $349 million, primarily due to refinancing or replacing maturing long-term debt with short-term loans. Additionally, long-term debt increased $301 million and interest-bearing refundable deposit decreased $275 million, due to an intercompany loan for repayment of the SMEPA deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased $439 million; other regulatory assets, deferred increased $97 million; and the Mirror CWIP regulatory liability increased $82 million primarily associated with construction, operation, and collections related to the Kemper IGCC. See – "Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current; accrued income taxes; accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and other deferred credits and liabilities increased primarily due to R&E tax deductions and the related reserve. Additional changes include increases in notes payable primarily due to new short-term bank loans and asset retirement obligations due to the CCR Rule. Total common stockholder's equity increased $164 million primarily due to the receipt of $75 million in capital contributions from Southern Company and due to net income during the second quarter 2015.
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, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $900 million will be required through June 30, 2016 to fund maturities of bank term loans scheduled to mature on April 1, 2016 and $30 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs. See "Sources of Capital" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $1.0 billion in 2015, $354 million in 2016, and $229 million for 2017, which includes expenditures related to the construction of the Kemper IGCC of $801 million in 2015 and $150 million in 2016.
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; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (B) to the Condensed Financial Statements under "Integrated Coal

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.
Sources of Capital
Except as described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. Mississippi Power's financial condition was adversely affected by the issuance of an 18-month promissory note to Southern Company related to the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Mississippi Supreme Court Decision" of Mississippi Power in Item 7 of the Form 10-K and herein for additional information.
Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note 3 to the financial statements of Southern Company and AlabamaMississippi Power under "Retail Regulatory Matters Alabama Power" and "Retail Regulatory Matters," respectively,"Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for additional information regarding Alabamalegislation related to the securitization of certain costs of the Kemper IGCC.
In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. As of June 30, 2015, Mississippi Power's recoverycurrent liabilities exceeded current assets by approximately $898 million primarily due to $900 million of retailbank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs through various regulatory clausesJune 30, 2015. Mississippi Power intends to utilize operating cash flows and accounting orders. The recovery balancelines of each regulatory clausecredit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.
At June 30, 2015, Mississippi Power had approximately $212 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2015 were as follows:
Regulatory Clause
Balance Sheet Line Item
September 30,
2014

December 31,
2013




(in millions)
Rate CNP Environmental – Under
Deferred under recovered regulatory clause revenues
$

$7
  Under recovered regulatory clause revenues, current 25
 
Rate CNP PPA – Under
Deferred under recovered regulatory clause revenues
46

18
  Under recovered regulatory clause revenues, current 9
 
Retail Energy Cost Recovery – Over
Other regulatory liabilities, current
44

27


Deferred over recovered regulatory clause revenues


15
Natural Disaster Reserve
Other regulatory liabilities, deferred
87

96
Georgia Power
Rate Plans
Expires   
Executable Term
Loans
 
Due Within One
Year
2015 2016 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions) (in millions) (in millions) (in millions)
$40
 $255
 $295
 $265
 $30
 $40
 $70
 $225
See Note 36 to the financial statements of Southern Company and GeorgiaMississippi Power under "Retail Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively,"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.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

A portion of the $265 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $40 million.
Most of these bank credit arrangements contain covenants that limit debt levels and typically contain cross default provisions to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specified threshold. Mississippi Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements, as needed prior to expiration. In connection therewith, Mississippi Power may seek to extend the maturity dates and/or increase or decrease the lending commitments thereunder.
To the extent available, Mississippi Power may seek to utilize a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power would be loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
  
Short-term Debt at
June 30, 2015
 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Short-term bank debt $505
 1.4% $460
 1.4% $505
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.
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 BBB- and/or Baa3 or below. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At June 30, 2015, the maximum potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $282 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system 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 has impacted and may continue to impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.
On June 5, 2015, Fitch downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power.
Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Mississippi Power) on CreditWatch with negative implications.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities
In March 2015, Mississippi Power repaid at maturity a $75 million bank term loan.
In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In June 2015, Mississippi Power issued an 18-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposit in connection with the termination of the APA. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

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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 June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Operating Revenues:       
Wholesale revenues, non-affiliates$250
 $260
 $481
 $538
Wholesale revenues, affiliates85
 68
 199
 140
Other revenues2
 1
 4
 2
Total operating revenues337
 329
 684
 680
Operating Expenses:       
Fuel105
 118
 243
 243
Purchased power, non-affiliates18
 17
 34
 45
Purchased power, affiliates4
 16
 14
 46
Other operations and maintenance69
 69
 121
 122
Depreciation and amortization60
 52
 118
 103
Taxes other than income taxes6
 6
 12
 11
Total operating expenses262

278
 542
 570
Operating Income75
 51
 142
 110
Other Income and (Expense):       
Interest expense, net of amounts capitalized(23) (22) (45) (44)
Other income (expense), net1
 
 1
 
Total other income and (expense)(22) (22) (44) (44)
Earnings Before Income Taxes53
 29
 98
 66
Income taxes (benefit)1
 (3) 13
 
Net Income52
 32
 85
 66
Less: Net income attributable to noncontrolling interests6
 1
 6
 2
Net Income Attributable to Southern Power Company$46
 $31
 $79
 $64
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Net Income$52
 $32
 $85
 $66
Other comprehensive income (loss)
 
 
 
Less: Comprehensive income attributable to noncontrolling interests6
 1
 6
 2
Comprehensive Income Attributable to Southern Power Company$46
 $31
 $79
 $64
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Six Months
Ended June 30,
 2015 2014
 (in millions)
Operating Activities:   
Net income$85
 $66
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total121
 105
Deferred income taxes59
 (3)
Investment tax credits153
 26
Amortization of investment tax credits(10) (5)
Deferred revenues(21) (24)
Accrued income taxes, non-current100
 
Other, net10
 7
Changes in certain current assets and liabilities —   
-Receivables(26) (34)
-Fossil fuel stock5
 (1)
-Prepaid income taxes(102) 21
-Other current assets
 (1)
-Accounts payable(31) 24
-Accrued taxes(110) 7
-Other current liabilities18
 5
Net cash provided from operating activities251
 193
Investing Activities:   
Plant acquisitions(408) (213)
Property additions(154) (11)
Change in construction payables38
 (3)
Payments pursuant to long-term service agreements(45) (23)
Other investing activities(1) (11)
Net cash used for investing activities(570) (261)
Financing Activities:   
Increase (decrease) in notes payable, net(195) 73
Proceeds — Senior notes650
 
Distributions to noncontrolling interests(1) 
Contributions from noncontrolling interests78
 7
Payment of common stock dividends(65) (66)
Other financing activities(3) 9
Net cash provided from financing activities464
 23
Net Change in Cash and Cash Equivalents145
 (45)
Cash and Cash Equivalents at Beginning of Period75
 69
Cash and Cash Equivalents at End of Period$220
 $24
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $1 and $- capitalized for 2015 and 2014, respectively)$35
 $43
Income taxes, net(72) (59)
Noncash transactions — Accrued property additions at end of period38
 5
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets At June 30,
2015
 At December 31,
2014
  (in millions)
Current Assets:    
Cash and cash equivalents $220
 $75
Receivables —    
Customer accounts receivable 106
 77
Other accounts receivable 11
 15
Affiliated companies 40
 34
Fossil fuel stock, at average cost 17
 22
Materials and supplies, at average cost 59
 58
Prepaid income taxes 122
 19
Deferred income taxes, current 144
 306
Other current assets 16
 21
Total current assets 735
 627
Property, Plant, and Equipment:    
In service 6,047
 5,657
Less accumulated provision for depreciation 1,125
 1,035
Plant in service, net of depreciation 4,922
 4,622
Construction work in progress 201
 11
Total property, plant, and equipment 5,123
 4,633
Other Property and Investments:    
Goodwill 2
 2
Other intangible assets, net of amortization of $10 and $8 at
June 30, 2015 and December 31, 2014, respectively
 69
 47
Total other property and investments 71
 49
Deferred Charges and Other Assets:    
Prepaid long-term service agreements 141
 124
Other deferred charges and assets — affiliated 13
 5
Other deferred charges and assets — non-affiliated 143
 112
Total deferred charges and other assets 297
 241
Total Assets $6,226
 $5,550
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders' Equity At June 30,
2015
 At December 31,
2014
  (in millions)
Current Liabilities:    
Securities due within one year $525
 $525
Notes payable 8
 195
Accounts payable —    
Affiliated 65
 78
Other 55
 30
Accrued income taxes 7
 72
Accrued interest 31
 30
Other current liabilities 53
 17
Total current liabilities 744
 947
Long-term Debt 1,737
 1,095
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 760
 863
Accumulated deferred investment tax credits 693
 601
Accrued income taxes, non-current 100
 
Deferred capacity revenues — affiliated 9
 15
Other deferred credits and liabilities — affiliated 
 1
Other deferred credits and liabilities — non-affiliated 22
 18
Total deferred credits and other liabilities 1,584
 1,498
Total Liabilities 4,065
 3,540
Redeemable Noncontrolling Interest 41
 39
Common Stockholder's Equity:    
Common stock, par value $.01 per share —    
Authorized — 1,000,000 shares    
Outstanding — 1,000 shares 
 
Paid-in capital 1,176
 1,176
Retained earnings 587
 573
Accumulated other comprehensive income 4
 3
Total common stockholder's equity 1,767
 1,752
Noncontrolling Interest 353
 219
Total Stockholders' Equity 2,120
 1,971
Total Liabilities and Stockholders' Equity $6,226
 $5,550
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2015 vs. SECOND QUARTER 2014
AND
YEAR-TO-DATE 2015 vs. YEAR-TO-DATE 2014


OVERVIEW
Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.
During the six months ended June 30, 2015, Southern Power acquired approximately 353 MWs of additional solar facilities including the five Georgia construction projects located in Taylor and Butler Counties, as well as the Lost Hills, Blackwell, and North Star projects located in California. Southern Power also entered into an agreement to acquire an approximately 299-MW wind facility, located in Oklahoma, contingent upon certain construction and project milestones. See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" herein for additional information.
Southern Power continues to focus on several key performance indicators. These indicators include peak season equivalent forced outage rate, contract availability, and net income. 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
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$15 48.4 $15 23.4
Net income attributable to Southern Power for the second quarter 2015 was $46 million compared to $31 million for the corresponding period in 2014. The increase was primarily due to increased revenue and lower fuel and purchased power expenses.
Net income attributable to Southern Power for year-to-date 2015 was $79 million compared to $64 million for the corresponding period in 2014. The increase was primarily due to a decrease in purchased power expenses, partially offset by increases in depreciation and income taxes.
Wholesale RevenuesNon-Affiliates
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(10) (3.8) $(57) (10.6)
Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale revenues from non-affiliates for the second quarter 2015 were $250 million compared to $260 million for the corresponding period in 2014. The decrease was due to a $5 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and new solar PPAs. The decrease in energy revenues reflects a 14% decrease in the average price of energy, partially offset by a 12% increase in KWH sales. In addition, capacity revenues decreased $5 million primarily due to PPA expirations.
Wholesale revenues from non-affiliates for year-to-date 2015 were $481 million compared to $538 million for the corresponding period in 2014. The decrease was due to a $44 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and new solar PPAs. The decrease in energy revenues reflects a 17% decrease in the average price of energy, partially offset by a 5% increase in KWH sales. In addition, capacity revenues decreased $13 million primarily due to PPA expirations.
Wholesale RevenuesAffiliates
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$17 25.0 $59 42.1
Wholesale revenues from sales to affiliate companies 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.
Wholesale revenues from affiliates for the second quarter 2015 were $85 million compared to $68 million for the corresponding period in 2014. The increase was the result of a $10 million increase in energy revenues and a $7 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 61% increase in KWH sales, partially offset by a 21% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.
Wholesale revenues from affiliates for year-to-date 2015 were $199 million compared to $140 million for the corresponding period in 2014. The increase was the result of a $50 million increase in energy revenues and a $9 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 110% increase in KWH sales, partially offset by a 22% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.
Fuel and Purchased Power Expenses
   Second Quarter 2015
vs.
Second Quarter 2014
  Year-to-Date 2015
vs.
Year-to-Date 2014
  (change in millions)
(% change) (change in millions) (% change)
Fuel $(13) (11.0) $
 
Purchased power – non-affiliates 1
 5.9 (11) (24.4)
Purchased power – affiliates (12) (75.0) (32) (69.6)
Total fuel and purchased power expenses $(24)   $(43)  
Southern Power's PPAs for natural gas-fired generation generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in such fuel cost is generally

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accompanied by an increase or decrease in related fuel revenues under the PPAs 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.
Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power Company, affiliate companies, or external parties.
In the second quarter 2015, total fuel and purchased power expenses were $127 million compared to $151 million for the corresponding period in 2014. The decrease was the result of a $58 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $34 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.
For year-to-date 2015, total fuel and purchased power expenses were $291 million compared to $334 million for the corresponding period in 2014. The decrease was a result of a $154 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $111 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.
Fuel
In the second quarter 2015, fuel expense was $105 million compared to $118 million for the corresponding period in 2014. The decrease was due to a 36.1% decrease associated with the average cost of natural gas per KWH generated, partially offset by a 40.6% increase associated with the volume of KWHs generated, primarily as a result of increased demand resulting from lower natural gas prices.
For year-to-date 2015 and for the corresponding period in 2014, fuel expense was $243 million. While there was no overall change, a $152 million increase in the total cost of fuel attributable to the volume of KWHs generated was offset by a $152 million decrease in the average cost of natural gas per KWH generated.
Purchased Power Non-Affiliates and Affiliates
In the second quarter 2015, purchased power expense was $22 million compared to $33 million for the corresponding period in 2014. For year-to-date 2015, purchased power expense was $48 million compared to $91 million for the corresponding period in 2014. The decreases were primarily the result of 37.4% and 45.6% decreases in the volume of KWHs purchased in the second quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices which resulted in higher use of Southern Power Company's generation resources.
Other Operations and Maintenance Expenses
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$—  $(1) (0.8)
In the second quarter 2015 and for the corresponding period in 2014, other operations and maintenance expenses were $69 million. While there was no overall change, a decrease in outage expense of $10 million was offset by a $10 million increase in expenses associated with support services, transmission, and new plants placed in service in 2014 and 2015.
For year-to-date 2015, other operations and maintenance expenses were $121 million compared to $122 million for the corresponding period in 2014. The decrease was primarily due to a $17 million decrease in outage expense,

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largely offset by a $16 million increase in expenses associated with support services, new plants placed in service in 2014 and 2015, and transmission.
Depreciation and Amortization
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$8 15.4 $15 14.6
In the second quarter 2015, depreciation and amortization was $60 million compared to $52 million for the corresponding period in 2014. For year-to-date 2015, depreciation and amortization was $118 million compared to $103 million for the corresponding period in 2014. The increases were primarily related to solar facilities placed in service in 2014 and 2015.
Income Taxes (Benefit)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$4 133.3 $13 N/M
N/M – Not meaningful
In the second quarter 2015, income taxes were $1 million compared to an income tax benefit of $3 million for the corresponding period in 2014. For year-to-date 2015, income taxes were $13 million. The increases were primarily due to higher pre-tax earnings in 2015 and beneficial state income tax changes in 2014, partially offset by increased federal income tax benefits related to ITCs in 2015.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern 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 Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy, including successfully expanding investments in renewable energy projects, and to construct generating facilities, including the impact of federal ITCs.
Other factors that could influence future earnings include weather, demand, cost of generating units within the power pool, and operational limitations. 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, water quality, or other environmental and health concerns could also significantly affect Southern Power. 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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Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM) and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, North Carolina, and Texas) to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, Florida, Georgia, North Carolina, and Texas. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Power's 2013 ARP.results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through existing PPAs. However, the ultimate financial and operational impact of the final rules on Southern Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
Acquisitions
During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy, which are included in Southern Power's capital program estimates for 2015.
Kay County Wind Facility
On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on

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performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
Lost Hills-Blackwell Solar Facilities
On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years.
North Star Solar Facility
On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately 61-MW North Star solar facility in Fresno County, California. The solar facility began commercial operation on June 20, 2015, and the entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company.
Construction Projects
In December 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of five separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this time.

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Southern Power Company's construction projects are detailed in the table below:
Solar ProjectSellerNameplate CapacityCounty Location in GeorgiaExpected Commercial Operation DatePPA Counterparty
for Entire Plant Output
PPA Contract PeriodEstimated Construction Cost 
  (MW)    (in millions) 
Taylor CountyN/A146TaylorFourth quarter 2016Cobb, Flint, and Sawnee Electric Membership Corporations25 years$260
-$280 
Decatur ParkwayTradeWind Energy, Inc.84DecaturDecember 2015
Georgia Power(a)
25 years$170
-$173(b)
Decatur CountyTradeWind Energy, Inc.20DecaturDecember 2015
Georgia Power(a)
20 years$45
-$47(b)
ButlerCERSM, LLC and Community Energy, Inc.103TaylorDecember 2016
Georgia Power(a)
30 years$220
-$230(b)
PawpawLongview Solar, LLC30TaylorDecember 2015
Georgia Power(a)
30 years$70
-$80(b)
Butler Solar FarmStrata Solar Development, LLC20TaylorDecember 2015
Georgia Power(a)
20 years$42
-$48(b)
(a) Subject to FERC approval.
(b) Includes the acquisition price of all outstanding membership interests.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.
Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern Power's existing fleet, the coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of June 30, 2015 from the period ended December 31, 2014.
FERC Matters
Southern Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the terms of the 2013 ARP, on October 3, 2014, Georgiatraditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the following tariff adjustmentsenergy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the Georgia PSC to become effective January 1, 2015 pending its approval:
Increase the traditional base tariffs by approximately $107 million to cover additional capacity costs;
Increase the environmental compliance cost recovery tariff by approximately $32 million;
Increase the demand-side management tariffs by approximately $3 million; and
Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.
FERC. The ultimate outcome of this matter cannot be determined at this time.

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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, 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 air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Renewables Development" and "Retail Regulatory Matters – Renewables Development," respectively, in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.
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 additional information.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, Depreciation, and ITCs.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Southern Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On May 20, 2014,February 18, 2015, the Georgia PSC approved Georgia Power's applicationFASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the certificationprimary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of two PPAs executedthis ASU has not yet been determined.
On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in April 2013the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Power currently reflects unamortized debt issuance costs in other deferred charges and assets – non-affiliated on its balance sheet. Upon adoption, the purchasereclassification will not have a material impact on the results of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.
As a resultoperations, financial position, or cash flows of amendments executed during 2014, the biomass PPAs classified as non-affiliate capital leases with related long-term obligations totaling $641 million as of December 31, 2013 no longer meet the definition of a lease or will be accounted for as operating leases. Due to these amendments, as well as others executed during 2014, total non-affiliate operating lease long-term obligations increased by $103 million. As such, estimated long-term obligations for non-affiliate operating leases have been updated to $113 million for 2015, $117 million for 2016, $145 million for 2017, $150 million for 2018, and $1.7 billion for 2019 and thereafter. Estimated long-termSouthern Power.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at June 30, 2015. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements 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 $251 million for the first six months of 2015, compared to $193 million for the first six months of 2014. The increase in cash provided from operating activities was primarily due to lower purchased power costs and an increase in income tax benefits received. Net cash used for investing activities totaled $570 million for the first six months of 2015 primarily due to the Lost Hills, Blackwell, and North Star acquisitions and expenditures related to the construction of new solar facilities. Net cash provided from financing activities totaled $464 million for the first six months of 2015 primarily due to the issuance of additional senior notes in May 2015. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2015 include a $300 million increase in plant in service, net of depreciation primarily due to the Lost Hills, Blackwell, and North Star acquisitions and a $190 million increase in CWIP primarily due to the construction of new solar facilities. Other significant changes include an increase in long-term debt of $642 million primarily as a result of the issuance of senior notes in May 2015.
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, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. Subsequent to June 30, 2015, $525 million of long-term debt was repaid at maturity. There are no other scheduled maturities of long-term debt through June 30, 2016.
The capital 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 and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to be approximately $1.4 billion for 2015, which includes approximately $1.3 billion for acquisitions and/or construction of new generating facilities. See Note (I) to the Condensed Financial Statements herein for additional information. Actual capital 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 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, securities issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. In 2015, Southern Power has utilized the capital markets to issue additional senior notes and expects to utilize the capital

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markets, bank term loans, and commercial paper markets, as the source of funds for the majority of its maturities and to meet short-term liquidity needs, including funding acquisition and construction costs.
To meet liquidity and capital resource requirements, Southern Power had at June 30, 2015 cash and cash equivalents of approximately $220 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $466 million is unused.
The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power Company is currently in compliance with all covenants in the Facility.
Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power Company's commercial paper program. Subject to applicable market conditions, Southern Power Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. 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 Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Subsequent to June 30, 2015, commercial paper was used to partially fund the maturity of long-term debt in July 2015.
Details of short-term borrowings were as follows:
  
Commercial Paper at
the End of the Period
 
Commercial Paper During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
June 30, 2015: $
 % $163
 0.6% $339
(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and operating cash flows.
Credit Rating Risk
Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at June 30, 2015 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and Baa2$9
At BBB- and/or Baa3320
Below BBB- and/or Baa31,081

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Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Power's ability to access capital markets, particularly the short-term debt market.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.
Financing Activities
In May 2015, Southern Power Company issued $350 million aggregate principal amount of Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power Company 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
(UNAUDITED)


INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
NotePage Number
A
B
C
D
E
F
G
H
I
J





INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.
RegistrantApplicable Notes
Southern CompanyA, B, C, D, E, F, G, H, I, J
Alabama PowerA, B, C, E, F, G, H
Georgia PowerA, B, C, E, F, G, H
Gulf PowerA, B, C, E, F, G, H
Mississippi PowerA, B, C, E, F, G, H
Southern PowerA, B, C, D, E, G, H, I


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)


(A)INTRODUCTION
obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See Note 7 to thecondensed quarterly financial statements of Georgia Power under "Commitments – Fueleach registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and Purchased Power Agreements"regulations of the SEC. The Condensed Balance Sheets as of December 31, 2014 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2015 and 2014. Certain information and footnote disclosures normally included in Item 8annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K for additional information.
Integrated Resource Plan
See Note 3 toare generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" and "Retail Regulatory Matters – Integrated Resource Plans," respectively,the notes thereto included in Item 8the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the Form 10-Koperating results to be expected for additional information.the full year.
GeorgiaCertain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
On February 6, 2015, Gulf Power filed a request with the Georgia PSC on January 10, 2014announced plans to cancel the proposed biomass fuel conversion ofretire its coal-fired generation at Plant Mitchell Unit 3 (155Smith Units 1 and 2 (357 MWs) because it would not be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3by March 31, 2016. In March 2015, in connection with this retirement, Gulf Power reclassified the triennial Integrated Resource Plannet carrying value of these units from plant in 2016.service, net of depreciation, to other utility plant, net. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.
In June 2015, Georgia Power plansidentified an error affecting the billing to continuea small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to operateJune 30, 2015. In the unit as needed until the Mercury and Air Toxics Standards rule becomes effective in April 2015.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company andsecond quarter 2015, Georgia Power under "Retail Regulatory Matters –recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8evaluated the effects of the Form 10-K for additional information.
As of September 30, 2014, Georgia Power's under recovered fuel balance totaled $175 million and is included in deferred charges and other assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. As of December 31, 2013, Georgia Power's over recovered fuel balance totaled $58 million and is included in current liabilities and other deferred credits and liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein. Georgia Power's next fuel case is expected to be filed with the Georgia PSC by February 27, 2015.
Fuel cost recovery revenues as recordedthis error on the financial statements are adjusted for differences in actual recoverable fuel costsinterim and amounts billed in current regulated rates. Accordingly, changes inannual periods that included the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.
Storm Damage Recovery
See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.
Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $105 million and $37 million, respectively.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, and pending litigation.
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments,error, as well as adjustmentsthe current period. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for change orders, and performance bonusesrevenue recognition effective for earlyfiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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(UNAUDITED)

completion and unit performance. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owedOn February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Contractor underConsolidation Analysis, which makes certain changes to both the Vogtle 3variable interest model and 4 Agreement. Georgia Power's proportionate sharethe voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.
On April 7, 2015, the FASB issued ASU No. 2015-03, 45.7%Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The Vogtle 3ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and 4 Agreement providesis effective for liquidated damages uponfiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the Contractor's failure to fulfillreclassification will not have a material impact on the schedule and performance guarantees. The Contractor's liabilityresults of operations, financial position, or cash flows of any registrant.
Asset Retirement Obligations
See Note 1 to the Vogtle Ownersfinancial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for scheduleadditional information regarding the EPA's regulation of CCR.
On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and performance liquidated damages and warranty claims isMississippi Power recorded new asset retirement obligations (ARO) for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a cap.
Certain payment obligationsresult of Westinghouse and Stone & Webster, Inc. understate requirements in Georgia which closely align with the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breachesrequirements of the Vogtle 3CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and 4 Agreementpost-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates.
As of June 30, 2015, details of the AROs, including those related to the CCR Rule, included in Southern Company's and the traditional operating companies' Condensed Balance Sheets herein were as follows:
 Southern Company Alabama Power Georgia Power 
Gulf
Power
 Mississippi Power
 (in millions)
Balance at beginning of year$2,201  $829  $1,255  $17  $48 
Liabilities incurred612  401    71  97 
Liabilities settled(10) (1) (9)    
Accretion53  23  28    1 
Cash flow revisions58    82  4  2 
Balance at end of period$2,914  $1,252  $1,356  $92  $148 
The increases in liabilities incurred and cash flow revisions for the six months ended June 30, 2015 primarily relate to an increase in AROs associated with facilities impacted by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.CCR Rule.
In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challengesconnection with a proposed settlement related to the construction and licensingclosure of Plant Vogtle Units 3 and 4, at the federal and state level, andScholz, Gulf Power may incur additional challenges are expected as construction proceeds.
In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariffAROs associated with CCR of approximately $223$15 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On October 31, 2014, Georgia Power filed to increase the NCCR tariff by approximately $27 million effective January 1, 2015 pending Georgia PSC approval. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2014, approximately $23 million of these 2009 and 2010 costs remained unamortized in CWIP.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, Georgia Power's eighth VCM report filed in February 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the construction period are estimated to total approximately $2.0 billion.
In September 2013, the Georgia PSC approved a stipulation entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. On August 19, 2014, the Georgia PSC approved a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), including construction capital costs incurred, which through December 31, 2013 totaled $2.6 billion. Georgia Power resumed filing semi-annual reports$35 million.

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(UNAUDITED)

(B)CONTINGENCIES AND REGULATORY MATTERS
withSee Note 3 to the eleventh VCM report filed on August 28, 2014, which requests approvalfinancial statements of an additional $0.2 billionthe registrants in costs incurred from January 1, 2014 through June 30, 2014.Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In 2012, the Vogtle Ownersaddition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the Contractor began negotiations regardingenvironment, 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 air quality and water standards, has occurred throughout the costs associatedU.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with design changessuch matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the DCD and the delaysfinancial statements of each registrant in the timing of approvalItem 8 of the DCDForm 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Environmental Matters
New Source Review Actions
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and issuanceGeorgia Power alleging violations of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the termsNew Source Review (NSR) provisions of the Vogtle 3Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and 4 Agreement. Also in 2012,Mississippi Power. These civil actions sought penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power and the other Vogtle Owners filed suit against the Contractor(including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the SouthernNorthern District of Georgia seekingsince 2001. The case against Alabama Power (including claims involving a declaratory judgment thatunit co-owned by Mississippi Power) was partially settled in 2006 through a consent decree with the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia PowerEPA, and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the suitclaims remain pending in the U.S. District Court for the SouthernNorthern District of Georgia alleging that (i)Alabama. On June 25, 2015, the design changesU.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the DCD imposed2006 consent decree to resolve all remaining claims for relief alleged in the case against Alabama Power. If approved by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations, but the Contractor subsequently asserted, and may from time to time continue to assert, that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power does not agree with either the proposed cost or schedule adjustments or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.
Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in the fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessaryU.S. District Court for the operationNorthern District of Plant Vogtle Units 3Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and 4, or other issues could arisea cap on certain units and may further impact project schedulerequirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and cost. While Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project scheduleBarry; pay a $100,000 civil penalty; and believes the Contractor is responsible for any related costs, Contractor performance and progressinvest $1.5 million in recent months on the assembly and installation of the shield building and structural modules have resulted in additional schedule pressure.
Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.electric transportation infrastructure projects over three years.
The ultimate outcome of these matters cannot be determined at this time.

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(UNAUDITED)

Gulf Power
Retail Base Rate Case
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.
In December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $5.4 million reduction in depreciation expense in the first nine months of 2014.
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The recovery balance of each regulatory clause follows:
Recovery Clause
Balance Sheet Location
September 30, 2014
December 31, 2013




(in millions)
Fuel Cost Recovery – Under
Under recovered regulatory clause revenues
$41.3

$21.0
Purchased Power Capacity Recovery – Over
Other regulatory liabilities, current
6.8


Purchased Power Capacity Recovery – Under
Under recovered regulatory clause revenues


2.8
Environmental Cost Recovery – Under
Under recovered regulatory clause revenues
6.3

14.4
Energy Conservation Cost Recovery – Under
Under recovered regulatory clause revenues
2.6

7.0
On October 22, 2014, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2015. The net effect of the approved changes is a $41.2 million increase in annual revenue for 2015. The increased revenues will not have a significant impact on net income since most of the revenues will be offset by expenses.
Retail Fuel Cost Recovery
See Note 1 and Note 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.
Gulf Power has established fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first half of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested for 2014. Under recovered fuel costs at September 30, 2014 totaled $41.3 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.

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(UNAUDITED)

Mississippi Power
Energy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information.
On June 3, 2014, the Mississippi PSC approved Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. On October 17, 2014, Mississippi Power filed a revised compliance filing, which proposed an increase of $6.7 million in retail revenues for the period December 2014 through December 2015. The Mississippi PSC approved the revised filing on November 4, 2014.
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.
On March 18, 2014,17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2013,2014, which indicated no surcharge or refund. On March 31, 2014,26, 2015, the Mississippi PSC suspended the filing to allow it more time for review.
On June 3, 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for Mississippi Power and other regulated electric utilities in Mississippi.
The ultimate outcome of these mattersthis matter cannot be determined at this time.
System Restoration Rider
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – System Restoration Rider" in Item 8 of the Form 10-K for additional information.
On April 1, 2014, the Mississippi PSC approved Mississippi Power's request to continue a zero System Restoration Rider rate for 2014 and to accrue approximately $3.3 million to the property damage reserve in 2014.
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.
In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a 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 $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project in December 2015. As of September 30, 2014, total project expenditures were $464.1 million, of which Mississippi Power's portion was $236.3 million, plus AFUDC of $16.1 million.
On August 1, 2014, Mississippi Power entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the

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FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)CONDITION AND RESULTS OF OPERATIONS

CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On August 28, 2014, the Chancery Court dismissed the appeal.
In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. As of September 30, 2014, $5.5 million of Plant Greene County CWIP had been reclassified as a regulatory asset. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Greene County and Watson. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Southern Company's and Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Mississippi Power's fuel cost recovery.
At September 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $13.1 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.
Ad Valorem Tax Adjustment
See Note 3 to the financial statements ofOn April 23, 2015, Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information.
On May 6, 2014, the Mississippi PSC approved Mississippi Power'sfiled its annual ad valorem tax adjustment factor filing for 2014,2015, which requested an annual rate increasedecrease of 0.38%0.35%, or $3.6$2 million in annual retail revenues, primarily due to an increasea decrease in property taxaverage millage rates. On May 26, 2015, the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.
Integrated Coal Gasification Combined Cycle
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Project ApprovalOverview
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC, which the Sierra Club appealed to the Chancery Court. Later in 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. In January 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.
On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN, which the Mississippi Supreme Court granted on September 11, 2014. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.
Kemper IGCC Schedule and Cost EstimateIGCC.
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4$2.4 billion,, net of $245.3$245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants)Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline

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facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88$2.88 billion,, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions), as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.
The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service onusing natural gas onin August 9, 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. In accordance with a Mississippi PSC order, on August 18, 2014, Mississippi Power provided an analysisRecovery of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of (1) the continued collection of rates as prescribed by the 2013 MPSC Rate Order (defined below), with the current recognition as revenue of the related equity return on all assets placed in service, and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account, (2) the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC, and (3) the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurredand the Cost Cap Exceptions remains subject to support operation ofreview and approval by the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" herein for additional information.
The ultimate outcome of this matter cannot be determined at this time.

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Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court decision), and actual costs incurred as of SeptemberJune 30, 20142015, as adjusted for the Kemper IGCCCourt's decision, are as follows:

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Cost Category
2010 Project Estimate(f)
 Current Estimate Actual Costs at September 30, 2014
2010 Project Estimate(f)
 Current Estimate Actual Costs at June 30, 2015
(in billions)(in billions)
Plant Subject to Cost Cap(a)
$2.40
 $4.86
 $4.06
$2.40
 $4.96
 $4.51
Lignite Mine and Equipment0.21 0.23 0.230.21 0.23 0.23
CO2 Pipeline Facilities
0.14 0.11 0.100.14 0.11 0.11
AFUDC(b)(c)
0.17 0.62 0.410.17 0.62 0.52
Combined Cycle and Related Assets Placed in
Service – Incremental
(d)

 
 

 0.02
 
General Exceptions0.05 0.10 0.070.05 0.10 0.08
Regulatory Asset(c)(e)

 0.18 0.10
Deferred Costs(c)(e)

 0.19 0.15
Total Kemper IGCC(a)(c)
$2.97
 $6.10
 $4.97
$2.97
 $6.23
 $5.60
(a)
The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap.cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.
(b)Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.
(c)Amounts in the Current Estimate reflect estimated costs through March 31, 2016.
(d)Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service onin August 9, 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.
(e)The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."
(f)
The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
Of the total costs, including post-in-service costs for the lignite mine, incurred as of SeptemberJune 30, 2014, $2.882015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $1.98$2.08 billion), $104.3$2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, and $3.9$16 million in other deferred charges and assets, and $24 million in Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and $1.1AROs in the balance sheet, with $1 million was previously expensed.
Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related coststo the construction of the Kemper IGCC that exceed the $2.88$2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Southern Company and Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $418.0$23 million ($258.114 million after tax) in the thirdsecond quarter 20142015 and $380.0$9 million ($234.76 million after tax) in the first quarter 2014.2015. These amounts are in addition to charges totaling $1.18 billion$868 million ($728.7536 million after tax) recognized through December 31, 2013., $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. The first quarter 2014 revisedincreases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to decreases in construction labor productivity at the Kemper IGCC due in large part to adverse weather, unexpected excessive craft labor turn-over, and unanticipated installation inefficiencies, as well as additional risk related to the expected in-service date. The third quarter 2014 revised cost estimate primarily reflects costs related to the extension of the project schedule for the remainder of the Kemper IGCC (including the gasifierequipment rework, scope modifications, and the gas clean-up facilities) as a resultrelated additional labor costs in support of matters related to the time expected to be required for start-up activities and operational readiness including enhancing the scope of specialized operator training.activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $20$25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion

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cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.
Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and

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inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations.operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88$2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and Mississippi Power's statements of operations and these changes could be material.
Rate Recovery of Kemper IGCC Costs
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the Seven-Year2015 Rate Plan (described below)Case and otherany alternative proceedings related proceedings duringto the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements.
2013 Settlement Agreement
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, establishesestablished the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4$2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88$2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowsallowed Mississippi Power to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in February 2013. Mississippi Power intendsPower's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88$2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the

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estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the Seven-Yearproposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Plan (described below)Mitigation Plan) as approved by the Mississippi PSC. The rate recovery necessaryCourt's decision did not impact Mississippi Power's ability to recover the annual costs of securitization is expected to be filed and become effective following completion of the Mississippi PSC's prudence review of the costs to be securitized. With the extension of the Kemper IGCC in-service date, under certain potential scenarios, the amount eligible to be securitized may exceed $1.0 billion. In that event, Mississippi Power would expect to pursue rate recovery of any additional eligible costs.
The 2013 Settlement Agreement provides that Mississippi Power may terminate the 2013 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secureutilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 2013 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the 2013 Settlement

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Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS) to implement the requirements of the 2013 Settlement Agreement.additional information.
2013 MPSC Rate Order
Consistent with the terms of the 2013 Settlement Agreement, in January 2013, Mississippi Power filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013.
In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively arewere designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order). For the first nine months of 2014, $121.9 million has been collected, with $16.8 million recognized in retail revenues in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein. Since March 2013, $220.0 million has been collected, with $27.1 million recognized in retail revenues in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein.
service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88$2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC and to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates through the in-service date unlessuntil directed to do otherwise by the Mississippi PSC.
In March 2013, a legal challenge to the 2013 MPSC Rate Order was filed by Thomas A. Blanton with the Mississippi Supreme Court, which remains pending againstAugust 2014, Mississippi Power andprovided an analysis of the Mississippi PSC. On April 22, 2014, the Mississippi Supreme Court requested further briefing in this proceeding on a number of substantive issues relating to the 2013 MPSC Rate Order. An adverse outcome could affect the rates that went into effect on March 19, 2013 and January 1, 2014 and the related amounts deferred as a regulatory liability.
See "Regulatory Assets and Liabilities" herein for additional information.
Seven-Year Rate Plan
In March 2013, Mississippi Power, in compliance with the 2013 MPSC Rate Order, filed a revision to the proposed rate recovery plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (Seven-Year Rate Plan), which is still under review by the Mississippi PSC. In the Seven-Year Rate Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, is integral to the Seven-Year Rate Plan, which contemplates amortizationbenefits of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC will review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" herein for additional information.
The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of

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2012 (ATRA), which currently requires that assets be placed in service in 2014. While Mississippi Power placedplacing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, onincluding the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.
In addition, Mississippi Power's August 9, 2014 extensionfiling with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date forof the remainder of the Kemper IGCC beyond 2014IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Mississippi Power.
2015 Mississippi Supreme Court Decision
On February 12, 2015, the Court issued its decision in the losslegal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of tax benefitsKemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to bonus depreciationthe Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under current law. The estimated valuethe 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to retail customersthe Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.
2015 Rate Case
As a result of the bonus depreciation tax benefits not2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On

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May 15, 2015, Mississippi Power filed the 2015 Rate Case with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
On July 10, 2015, Mississippi Power filed a Supplemental Notice with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal, In-Service Asset Proposal, for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the associated common facilities portionIn-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.
The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC is approximately $130 millionrelated to $160 million.
Mississippi Power plans to further revise the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to investment tax credits, various other revenue requirement items, and other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated15% undivided interest that was previously projected to be an increasepurchased by SMEPA. See "Termination of approximately $60 millionProposed Sale of Undivided Interest to $70 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power, including Section 174 Research and Experimental (R&E) tax deductions, that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan. See "Income Tax Matters"SMEPA" herein for additional information.
Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC could have an adverse impact on the Seven-Year Rate Plan, including the inability to recover items considered as Cost Cap Exceptions.
In the event thatIf the Mississippi PSC does not approveact on the Supplemental Notice or the 2015 Rate Case within 120 days of the Supplemental Notice filing, Mississippi Power withdrawsexpects to put one of the Seven-Year Rate Plan,three viable alternative rate proposals into effect as ultimately revised, temporary rates under bond and subject to refund pursuant to Mississippi state law.
Mississippi Power wouldalso expects to seek additional rate relief to address recovery through alternate means, which could include a traditional rate case.
of the remaining Kemper IGCC assets. In addition to current estimated costs at SeptemberJune 30, 20142015 of $6.10$6.23 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Seven-Year Rate Plan, as ultimately amended or revised, and securitization areKemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
Prudence Reviews
The Mississippi PSC's review of Kemper IGCC costs is ongoing. OnIn August 5, 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the MPUS.Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for

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interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC grantedissued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, interestcarrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
OnIn August 18, 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of SeptemberJune 30, 2014,2015, the regulatory asset balance associated with the Kemper IGCC was $104.3$198 million. The projected balance at March 31, 2016 is estimated to total approximately $180$276 million. The amortization period of 40 years proposed by Mississippi Power for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

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In March 2013,See "2015 Mississippi Supreme Court Decision" herein for additional information related to the July 7, 2015 Mississippi PSC issuedorder terminating the 2013 MPSC Rate Order approving retailMirror CWIP rate increasesand requiring refund of 15% effective March 19, 2013, and 3% effective Januarycollections under Mirror CWIP.
See Note 1 2014, which collectively are designed to collect $156 million annually beginning in 2014. Because the 2013 MPSC Rate Order did not provide for the inclusionfinancial statements of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. To comply with the 2013 MPSC Rate Order, Mississippi Power is deferring the collections under the approved rates through the in-service date"Regulatory Assets and Liabilities" in a regulatory liability to be amortized and used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Mississippi Power is accruing interest costs on the unamortized balance of such regulatory liability for the benefit of retail customers. The dispositionItem 8 of the regulatory liability will be determined by the Mississippi PSC in future cost recovery mechanism proceedings.Form 10-K for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights in the event thatas Mississippi Power doeshas not satisfysatisfied its contractual obligation with respect to deliveries ofdeliver captured CO2 by May 11, 2015. WhileSince May 11, 2015, Mississippi Power has received no indication from either Denbury orbeen engaged in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their intent to terminate their respectiveagreement that do not affect pricing or minimum purchase quantities. Any termination or material modification of these agreements any termination could result in a material reduction in future by-productchemical product sales revenues and could have a material financial impact

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest to SMEPA
In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and SMEPA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits Section 174 Research and Experimental Deduction," respectively, herein for additional information. The ultimate outcome of this tax 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 air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
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 in Note (B) to the Condensed Financial Statements 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 ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a 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
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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, Pension and Other Postretirement Benefits, and AFUDC.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2015, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.
As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of $2.08 billion ($1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2015.
Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

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Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" 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 and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Mississippi Power has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. Mississippi Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Mississippi Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Mississippi Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Mississippi Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Mississippi Power's financial condition was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections, which as of June 30, 2015 was approximately $353 million including associated carrying costs, and the termination of the Mirror CWIP rate will further adversely impact Mississippi Power's financial condition and its ability to obtain financing needed for normal business operations and completion of the Kemper IGCC. Earnings for the six months ended June 30, 2015 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. Earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC.
In addition to funding normal business operations and projected capital expenditures, Mississippi Power's cash requirements primarily consist of $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs. In addition, Mississippi Power issued an 18-month promissory note to Southern Company in the aggregate principal amount of approximately $301 million related to the refund to SMEPA and expects to enter into a similar promissory note with Southern Company to fund the Mirror CWIP refund. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA," "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order,"" – 2015 Mississippi Supreme Court Decision," and " – 2015 Rate Case" herein for additional information. For the three-year period from 2015 through 2017, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental equipment for existing generating units, including the Plant Daniel scrubber project, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. See "Sources of Capital" herein for additional information.
Through June 30, 2015, Mississippi Power has incurred non-recoverable cash expenditures of $1.62 billion and is expected to incur approximately $0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.
During the first six months of 2015, Mississippi Power received $75 million in equity contributions from Southern Company. In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. On June 3, 2015, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company as a result of Southern Company's refund of approximately $301 million in deposits and associated interest to SMEPA in connection with the termination of the APA. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled $309 million for the first six months of 2015, an increase of $131 million as compared to the corresponding period in 2014. The increase in cash provided from operating activities is primarily due to R&E tax deductions and bonus depreciation reducing tax payments, an increase in fuel recovery, and a decrease in receivables, partially offset by the timing of payments for accounts payable and fuel purchases. See Notes (B) and Note (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $460 million for the first six months of 2015 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $230 million for the first six months of 2015 primarily due to short-term bank loans, capital contributions from Southern Company, and short-term borrowings, partially offset by redemptions of long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2015 include a decrease in securities due within one year of $349 million, primarily due to refinancing or replacing maturing long-term debt with short-term loans. Additionally, long-term debt increased $301 million and interest-bearing refundable deposit decreased $275 million, due to an intercompany loan for repayment of the SMEPA deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased $439 million; other regulatory assets, deferred increased $97 million; and the Mirror CWIP regulatory liability increased $82 million primarily associated with construction, operation, and collections related to the Kemper IGCC. See – "Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current; accrued income taxes; accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and other deferred credits and liabilities increased primarily due to R&E tax deductions and the related reserve. Additional changes include increases in notes payable primarily due to new short-term bank loans and asset retirement obligations due to the CCR Rule. Total common stockholder's equity increased $164 million primarily due to the receipt of $75 million in capital contributions from Southern Company and due to net income during the second quarter 2015.
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, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $900 million will be required through June 30, 2016 to fund maturities of bank term loans scheduled to mature on April 1, 2016 and $30 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs. See "Sources of Capital" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $1.0 billion in 2015, $354 million in 2016, and $229 million for 2017, which includes expenditures related to the construction of the Kemper IGCC of $801 million in 2015 and $150 million in 2016.
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; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (B) to the Condensed Financial Statements under "Integrated Coal

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.
Sources of Capital
Except as described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. Mississippi Power's financial condition was adversely affected by the issuance of an 18-month promissory note to Southern Company related to the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Mississippi Supreme Court Decision" of Mississippi Power in Item 7 of the Form 10-K and herein for additional information.
Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. As of June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $898 million primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs through June 30, 2015. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.
At June 30, 2015, Mississippi Power had approximately $212 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2015 were as follows:
Expires   
Executable Term
Loans
 
Due Within One
Year
2015 2016 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions) (in millions) (in millions) (in millions)
$40
 $255
 $295
 $265
 $30
 $40
 $70
 $225
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.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

A portion of the $265 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $40 million.
Most of these bank credit arrangements contain covenants that limit debt levels and typically contain cross default provisions to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specified threshold. Mississippi Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements, as needed prior to expiration. In connection therewith, Mississippi Power may seek to extend the maturity dates and/or increase or decrease the lending commitments thereunder.
To the extent available, Mississippi Power may seek to utilize a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power would be loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
  
Short-term Debt at
June 30, 2015
 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Short-term bank debt $505
 1.4% $460
 1.4% $505
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.
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 BBB- and/or Baa3 or below. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At June 30, 2015, the maximum potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $282 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system 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 has impacted and may continue to impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.
On June 5, 2015, Fitch downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power.
Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Mississippi Power) on CreditWatch with negative implications.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities
In March 2015, Mississippi Power repaid at maturity a $75 million bank term loan.
In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In June 2015, Mississippi Power issued an 18-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposit in connection with the termination of the APA. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

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SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

133



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Operating Revenues:       
Wholesale revenues, non-affiliates$250
 $260
 $481
 $538
Wholesale revenues, affiliates85
 68
 199
 140
Other revenues2
 1
 4
 2
Total operating revenues337
 329
 684
 680
Operating Expenses:       
Fuel105
 118
 243
 243
Purchased power, non-affiliates18
 17
 34
 45
Purchased power, affiliates4
 16
 14
 46
Other operations and maintenance69
 69
 121
 122
Depreciation and amortization60
 52
 118
 103
Taxes other than income taxes6
 6
 12
 11
Total operating expenses262

278
 542
 570
Operating Income75
 51
 142
 110
Other Income and (Expense):       
Interest expense, net of amounts capitalized(23) (22) (45) (44)
Other income (expense), net1
 
 1
 
Total other income and (expense)(22) (22) (44) (44)
Earnings Before Income Taxes53
 29
 98
 66
Income taxes (benefit)1
 (3) 13
 
Net Income52
 32
 85
 66
Less: Net income attributable to noncontrolling interests6
 1
 6
 2
Net Income Attributable to Southern Power Company$46
 $31
 $79
 $64
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2015 2014 2015 2014
 (in millions) (in millions)
Net Income$52
 $32
 $85
 $66
Other comprehensive income (loss)
 
 
 
Less: Comprehensive income attributable to noncontrolling interests6
 1
 6
 2
Comprehensive Income Attributable to Southern Power Company$46
 $31
 $79
 $64
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Six Months
Ended June 30,
 2015 2014
 (in millions)
Operating Activities:   
Net income$85
 $66
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total121
 105
Deferred income taxes59
 (3)
Investment tax credits153
 26
Amortization of investment tax credits(10) (5)
Deferred revenues(21) (24)
Accrued income taxes, non-current100
 
Other, net10
 7
Changes in certain current assets and liabilities —   
-Receivables(26) (34)
-Fossil fuel stock5
 (1)
-Prepaid income taxes(102) 21
-Other current assets
 (1)
-Accounts payable(31) 24
-Accrued taxes(110) 7
-Other current liabilities18
 5
Net cash provided from operating activities251
 193
Investing Activities:   
Plant acquisitions(408) (213)
Property additions(154) (11)
Change in construction payables38
 (3)
Payments pursuant to long-term service agreements(45) (23)
Other investing activities(1) (11)
Net cash used for investing activities(570) (261)
Financing Activities:   
Increase (decrease) in notes payable, net(195) 73
Proceeds — Senior notes650
 
Distributions to noncontrolling interests(1) 
Contributions from noncontrolling interests78
 7
Payment of common stock dividends(65) (66)
Other financing activities(3) 9
Net cash provided from financing activities464
 23
Net Change in Cash and Cash Equivalents145
 (45)
Cash and Cash Equivalents at Beginning of Period75
 69
Cash and Cash Equivalents at End of Period$220
 $24
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $1 and $- capitalized for 2015 and 2014, respectively)$35
 $43
Income taxes, net(72) (59)
Noncash transactions — Accrued property additions at end of period38
 5
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets At June 30,
2015
 At December 31,
2014
  (in millions)
Current Assets:    
Cash and cash equivalents $220
 $75
Receivables —    
Customer accounts receivable 106
 77
Other accounts receivable 11
 15
Affiliated companies 40
 34
Fossil fuel stock, at average cost 17
 22
Materials and supplies, at average cost 59
 58
Prepaid income taxes 122
 19
Deferred income taxes, current 144
 306
Other current assets 16
 21
Total current assets 735
 627
Property, Plant, and Equipment:    
In service 6,047
 5,657
Less accumulated provision for depreciation 1,125
 1,035
Plant in service, net of depreciation 4,922
 4,622
Construction work in progress 201
 11
Total property, plant, and equipment 5,123
 4,633
Other Property and Investments:    
Goodwill 2
 2
Other intangible assets, net of amortization of $10 and $8 at
June 30, 2015 and December 31, 2014, respectively
 69
 47
Total other property and investments 71
 49
Deferred Charges and Other Assets:    
Prepaid long-term service agreements 141
 124
Other deferred charges and assets — affiliated 13
 5
Other deferred charges and assets — non-affiliated 143
 112
Total deferred charges and other assets 297
 241
Total Assets $6,226
 $5,550
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders' Equity At June 30,
2015
 At December 31,
2014
  (in millions)
Current Liabilities:    
Securities due within one year $525
 $525
Notes payable 8
 195
Accounts payable —    
Affiliated 65
 78
Other 55
 30
Accrued income taxes 7
 72
Accrued interest 31
 30
Other current liabilities 53
 17
Total current liabilities 744
 947
Long-term Debt 1,737
 1,095
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 760
 863
Accumulated deferred investment tax credits 693
 601
Accrued income taxes, non-current 100
 
Deferred capacity revenues — affiliated 9
 15
Other deferred credits and liabilities — affiliated 
 1
Other deferred credits and liabilities — non-affiliated 22
 18
Total deferred credits and other liabilities 1,584
 1,498
Total Liabilities 4,065
 3,540
Redeemable Noncontrolling Interest 41
 39
Common Stockholder's Equity:    
Common stock, par value $.01 per share —    
Authorized — 1,000,000 shares    
Outstanding — 1,000 shares 
 
Paid-in capital 1,176
 1,176
Retained earnings 587
 573
Accumulated other comprehensive income 4
 3
Total common stockholder's equity 1,767
 1,752
Noncontrolling Interest 353
 219
Total Stockholders' Equity 2,120
 1,971
Total Liabilities and Stockholders' Equity $6,226
 $5,550
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

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SECOND QUARTER 2015 vs. SECOND QUARTER 2014
AND
YEAR-TO-DATE 2015 vs. YEAR-TO-DATE 2014


OVERVIEW
Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.
During the six months ended June 30, 2015, Southern Power acquired approximately 353 MWs of additional solar facilities including the five Georgia construction projects located in Taylor and Butler Counties, as well as the Lost Hills, Blackwell, and North Star projects located in California. Southern Power also entered into an agreement to acquire an approximately 299-MW wind facility, located in Oklahoma, contingent upon certain construction and project milestones. See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" herein for additional information.
Southern Power continues to focus on several key performance indicators. These indicators include peak season equivalent forced outage rate, contract availability, and net income. 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
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$15 48.4 $15 23.4
Net income attributable to Southern Power for the second quarter 2015 was $46 million compared to $31 million for the corresponding period in 2014. The increase was primarily due to increased revenue and lower fuel and purchased power expenses.
Net income attributable to Southern Power for year-to-date 2015 was $79 million compared to $64 million for the corresponding period in 2014. The increase was primarily due to a decrease in purchased power expenses, partially offset by increases in depreciation and income taxes.
Wholesale RevenuesNon-Affiliates
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$(10) (3.8) $(57) (10.6)
Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs 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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Wholesale revenues from non-affiliates for the second quarter 2015 were $250 million compared to $260 million for the corresponding period in 2014. The decrease was due to a $5 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and new solar PPAs. The decrease in energy revenues reflects a 14% decrease in the average price of energy, partially offset by a 12% increase in KWH sales. In addition, capacity revenues decreased $5 million primarily due to PPA expirations.
Wholesale revenues from non-affiliates for year-to-date 2015 were $481 million compared to $538 million for the corresponding period in 2014. The decrease was due to a $44 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and new solar PPAs. The decrease in energy revenues reflects a 17% decrease in the average price of energy, partially offset by a 5% increase in KWH sales. In addition, capacity revenues decreased $13 million primarily due to PPA expirations.
Wholesale RevenuesAffiliates
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$17 25.0 $59 42.1
Wholesale revenues from sales to affiliate companies 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.
Wholesale revenues from affiliates for the second quarter 2015 were $85 million compared to $68 million for the corresponding period in 2014. The increase was the result of a $10 million increase in energy revenues and a $7 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 61% increase in KWH sales, partially offset by a 21% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.
Wholesale revenues from affiliates for year-to-date 2015 were $199 million compared to $140 million for the corresponding period in 2014. The increase was the result of a $50 million increase in energy revenues and a $9 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 110% increase in KWH sales, partially offset by a 22% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.
Fuel and Purchased Power Expenses
   Second Quarter 2015
vs.
Second Quarter 2014
  Year-to-Date 2015
vs.
Year-to-Date 2014
  (change in millions)
(% change) (change in millions) (% change)
Fuel $(13) (11.0) $
 
Purchased power – non-affiliates 1
 5.9 (11) (24.4)
Purchased power – affiliates (12) (75.0) (32) (69.6)
Total fuel and purchased power expenses $(24)   $(43)  
Southern Power's PPAs for natural gas-fired generation generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in such fuel cost is generally

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

accompanied by an increase or decrease in related fuel revenues under the PPAs 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.
Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power Company, affiliate companies, or external parties.
In the second quarter 2015, total fuel and purchased power expenses were $127 million compared to $151 million for the corresponding period in 2014. The decrease was the result of a $58 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $34 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.
For year-to-date 2015, total fuel and purchased power expenses were $291 million compared to $334 million for the corresponding period in 2014. The decrease was a result of a $154 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $111 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.
Fuel
In the second quarter 2015, fuel expense was $105 million compared to $118 million for the corresponding period in 2014. The decrease was due to a 36.1% decrease associated with the average cost of natural gas per KWH generated, partially offset by a 40.6% increase associated with the volume of KWHs generated, primarily as a result of increased demand resulting from lower natural gas prices.
For year-to-date 2015 and for the corresponding period in 2014, fuel expense was $243 million. While there was no overall change, a $152 million increase in the total cost of fuel attributable to the volume of KWHs generated was offset by a $152 million decrease in the average cost of natural gas per KWH generated.
Purchased Power Non-Affiliates and Affiliates
In the second quarter 2015, purchased power expense was $22 million compared to $33 million for the corresponding period in 2014. For year-to-date 2015, purchased power expense was $48 million compared to $91 million for the corresponding period in 2014. The decreases were primarily the result of 37.4% and 45.6% decreases in the volume of KWHs purchased in the second quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices which resulted in higher use of Southern Power Company's generation resources.
Other Operations and Maintenance Expenses
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions) (% change) (change in millions) (% change)
$—  $(1) (0.8)
In the second quarter 2015 and for the corresponding period in 2014, other operations and maintenance expenses were $69 million. While there was no overall change, a decrease in outage expense of $10 million was offset by a $10 million increase in expenses associated with support services, transmission, and new plants placed in service in 2014 and 2015.
For year-to-date 2015, other operations and maintenance expenses were $121 million compared to $122 million for the corresponding period in 2014. The decrease was primarily due to a $17 million decrease in outage expense,

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largely offset by a $16 million increase in expenses associated with support services, new plants placed in service in 2014 and 2015, and transmission.
Depreciation and Amortization
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$8 15.4 $15 14.6
In the second quarter 2015, depreciation and amortization was $60 million compared to $52 million for the corresponding period in 2014. For year-to-date 2015, depreciation and amortization was $118 million compared to $103 million for the corresponding period in 2014. The increases were primarily related to solar facilities placed in service in 2014 and 2015.
Income Taxes (Benefit)
Second Quarter 2015 vs. Second Quarter 2014 Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)
(% change) (change in millions) (% change)
$4 133.3 $13 N/M
N/M – Not meaningful
In the second quarter 2015, income taxes were $1 million compared to an income tax benefit of $3 million for the corresponding period in 2014. For year-to-date 2015, income taxes were $13 million. The increases were primarily due to higher pre-tax earnings in 2015 and beneficial state income tax changes in 2014, partially offset by increased federal income tax benefits related to ITCs in 2015.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern 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 Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy, including successfully expanding investments in renewable energy projects, and to construct generating facilities, including the impact of federal ITCs.
Other factors that could influence future earnings include weather, demand, cost of generating units within the power pool, and operational limitations. 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, water quality, or other environmental and health concerns could also significantly affect Southern Power. 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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Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Air Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM) and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, North Carolina, and Texas) to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, Florida, Georgia, North Carolina, and Texas. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through existing PPAs. However, the ultimate financial and operational impact of the final rules on Southern Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
Acquisitions
During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy, which are included in Southern Power's capital program estimates for 2015.
Kay County Wind Facility
On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
Lost Hills-Blackwell Solar Facilities
On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years.
North Star Solar Facility
On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately 61-MW North Star solar facility in Fresno County, California. The solar facility began commercial operation on June 20, 2015, and the entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company.
Construction Projects
In December 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of five separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this time.

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Southern Power Company's construction projects are detailed in the table below:
Solar ProjectSellerNameplate CapacityCounty Location in GeorgiaExpected Commercial Operation DatePPA Counterparty
for Entire Plant Output
PPA Contract PeriodEstimated Construction Cost 
  (MW)    (in millions) 
Taylor CountyN/A146TaylorFourth quarter 2016Cobb, Flint, and Sawnee Electric Membership Corporations25 years$260
-$280 
Decatur ParkwayTradeWind Energy, Inc.84DecaturDecember 2015
Georgia Power(a)
25 years$170
-$173(b)
Decatur CountyTradeWind Energy, Inc.20DecaturDecember 2015
Georgia Power(a)
20 years$45
-$47(b)
ButlerCERSM, LLC and Community Energy, Inc.103TaylorDecember 2016
Georgia Power(a)
30 years$220
-$230(b)
PawpawLongview Solar, LLC30TaylorDecember 2015
Georgia Power(a)
30 years$70
-$80(b)
Butler Solar FarmStrata Solar Development, LLC20TaylorDecember 2015
Georgia Power(a)
20 years$42
-$48(b)
(a) Subject to FERC approval.
(b) Includes the acquisition price of all outstanding membership interests.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.
Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern Power's existing fleet, the coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of June 30, 2015 from the period ended December 31, 2014.
FERC Matters
Southern Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

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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, 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 air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements 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 ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.
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, Depreciation, and ITCs.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Southern Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU has not yet been determined.
On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Power currently reflects unamortized debt issuance costs in other deferred charges and assets – non-affiliated on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Power.

145

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 June 30, 2015. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements 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 $251 million for the first six months of 2015, compared to $193 million for the first six months of 2014. The increase in cash provided from operating activities was primarily due to lower purchased power costs and an increase in income tax benefits received. Net cash used for investing activities totaled $570 million for the first six months of 2015 primarily due to the Lost Hills, Blackwell, and North Star acquisitions and expenditures related to the construction of new solar facilities. Net cash provided from financing activities totaled $464 million for the first six months of 2015 primarily due to the issuance of additional senior notes in May 2015. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2015 include a $300 million increase in plant in service, net of depreciation primarily due to the Lost Hills, Blackwell, and North Star acquisitions and a $190 million increase in CWIP primarily due to the construction of new solar facilities. Other significant changes include an increase in long-term debt of $642 million primarily as a result of the issuance of senior notes in May 2015.
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, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. Subsequent to June 30, 2015, $525 million of long-term debt was repaid at maturity. There are no other scheduled maturities of long-term debt through June 30, 2016.
The capital 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 and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to be approximately $1.4 billion for 2015, which includes approximately $1.3 billion for acquisitions and/or construction of new generating facilities. See Note (I) to the Condensed Financial Statements herein for additional information. Actual capital 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 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, securities issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. In 2015, Southern Power has utilized the capital markets to issue additional senior notes and expects to utilize the capital

146

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

markets, bank term loans, and commercial paper markets, as the source of funds for the majority of its maturities and to meet short-term liquidity needs, including funding acquisition and construction costs.
To meet liquidity and capital resource requirements, Southern Power had at June 30, 2015 cash and cash equivalents of approximately $220 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $466 million is unused.
The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power Company is currently in compliance with all covenants in the Facility.
Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power Company's commercial paper program. Subject to applicable market conditions, Southern Power Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. 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 Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Subsequent to June 30, 2015, commercial paper was used to partially fund the maturity of long-term debt in July 2015.
Details of short-term borrowings were as follows:
  
Commercial Paper at
the End of the Period
 
Commercial Paper During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
June 30, 2015: $
 % $163
 0.6% $339
(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and operating cash flows.
Credit Rating Risk
Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at June 30, 2015 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and Baa2$9
At BBB- and/or Baa3320
Below BBB- and/or Baa31,081

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Power's ability to access capital markets, particularly the short-term debt market.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.
Financing Activities
In May 2015, Southern Power Company issued $350 million aggregate principal amount of Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power Company 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.

148



NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
(UNAUDITED)


INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
NotePage Number
A
B
C
D
E
F
G
H
I
J





INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.
RegistrantApplicable Notes
Southern CompanyA, B, C, D, E, F, G, H, I, J
Alabama PowerA, B, C, E, F, G, H
Georgia PowerA, B, C, E, F, G, H
Gulf PowerA, B, C, E, F, G, H
Mississippi PowerA, B, C, E, F, G, H
Southern PowerA, B, C, D, E, G, H, I


149



THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)

(A)INTRODUCTION
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2014 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2015 and 2014. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. In March 2015, in connection with this retirement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.
In June 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error, as well as the current period. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

150


NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.
On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of any registrant.
Asset Retirement Obligations
See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new asset retirement obligations (ARO) for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates.
As of June 30, 2015, details of the AROs, including those related to the CCR Rule, included in Southern Company's and the traditional operating companies' Condensed Balance Sheets herein were as follows:
 Southern Company Alabama Power Georgia Power 
Gulf
Power
 Mississippi Power
 (in millions)
Balance at beginning of year$2,201  $829  $1,255  $17  $48 
Liabilities incurred612  401    71  97 
Liabilities settled(10) (1) (9)    
Accretion53  23  28    1 
Cash flow revisions58    82  4  2 
Balance at end of period$2,914  $1,252  $1,356  $92  $148 
The increases in liabilities incurred and cash flow revisions for the six months ended June 30, 2015 primarily relate to an increase in AROs associated with facilities impacted by the CCR Rule.
In connection with a proposed settlement related to the closure of Plant Scholz, Gulf Power may incur additional AROs associated with CCR of approximately $15 million to $35 million.

151


NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(B)CONTINGENCIES AND REGULATORY MATTERS
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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 air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Environmental Matters
New Source Review Actions
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions sought penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) was partially settled in 2006 through a consent decree with the EPA, and additional claims remain pending in the U.S. District Court for the Northern District of Alabama. On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case against Alabama Power. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
The ultimate outcome of these matters cannot be determined at this time.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.
Georgia Power's environmental remediation liability as of June 30, 2015 was $40 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act

152


NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.
Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.
In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In 2013, the U.S. District Court for the Eastern District of North Carolina Western Division ruled that Georgia Power has no liability in the private action and, on March 20, 2015, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court's ruling. Therefore, the private action is now concluded.
The ultimate outcome of these remaining matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $47 million as of June 30, 2015. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
In 2003, Mississippi Power and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers. The TCEQ approved the final site remediation plan in 2013 and, in March 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability was $0.3 million as of June 30, 2015 and is expected to be recovered through the ECO Plan.
The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
Nuclear Fuel Disposal Cost Litigation
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

153


NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. The judgment amounts were paid on March 19, 2015. In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. The final outcome of this matter for Alabama Power cannot be determined at this time; however, no material impact on Southern Company's or Alabama Power's net income is expected as the damage amounts collected from the government are expected to be used for the benefit of customers.
In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of June 30, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
On March 31, 2015, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgo the Municipal and Rural Associations cost-based electric tariff increase reflected in the filing by, among other things, increasing the accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, which was accepted by the FERC on May 13, 2015, provides that the additional accrual of AFUDC was effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $11 million annually, of which $8 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.
Market-Based Rate Authority
The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request

154


NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Alabama Power
See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The recovery balance of each regulatory clause follows:
Regulatory Clause
Balance Sheet Line ItemJune 30, 2015
December 31,
2014



(in millions)
Rate CNP Compliance – Under*

Deferred under recovered regulatory clause revenues$25

$2
  Under recovered regulatory clause revenues, current29
 47
Rate CNP PPA – Under
Deferred under recovered regulatory clause revenues72

29
  Under recovered regulatory clause revenues, current
 27
Retail Energy Cost Recovery – Over
Deferred over recovered regulatory clause revenues72

47
Natural Disaster Reserve
Other regulatory liabilities, deferred81

84
* Formerly Known As Rate CNP Environmental
Rate CNP
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" and of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism and the normal purchases and normal sales (NPNS) exception for wind PPAs.
On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $30 million of non-environmental compliance costs during the first six months of 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under recovered position for Rate CNP Compliance during 2015.
In April 2015, the FASB proposed new accounting guidance to allow the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power currently accounts for its two wind PPAs. On July 9, 2015, the FASB ratified the consensus reached by the Emerging Issues Task Force to allow the exception in such cases and voted to issue a final accounting standard.
Environmental Accounting Order
In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Subject to the final approval of the New Source Review stipulation, Alabama Power will also

155


NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See "Environmental Matters – New Source Review Actions" herein for additional information regarding the NSR actions.
In accordance with an accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's or Alabama Power's financial statements.
Georgia Power
Integrated Resource Plan
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" and "Retail Regulatory Matters – Integrated Resource Plans," respectively, in Item 8 of the Form 10-K for additional information.
To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) and its decertification will be requested in connection with the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Units 7 and 6 and the units were returned to service on May 4, 2015 and June 27, 2015, respectively.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
As of June 30, 2015 and December 31, 2014, Georgia Power's under recovered fuel balance totaled $106 million and $199 million, respectively. For June 30, 2015 and December 31, 2014, the balance is included in current assets and current assets and other deferred charges and assets, respectively, on Southern Company's and Georgia Power's Condensed Balance Sheets herein. Georgia Power expects to file its next fuel case in September 2015. The ultimate outcome of this matter cannot be determined at this time.
Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, and pending litigation.
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to

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Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.
Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.
In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million in 2008 dollars (approximately $591 million in 2015 dollars).The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor subsequently asserted estimated minimum damages related to the amended counterclaim (based on Georgia Power's ownership interest) of approximately $113 million in 2014 dollars (approximately $118 million in 2015 dollars).In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.

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Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Georgia Power's eighth VCM report filed in 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.
On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).
Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.
On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month Contractor delay, and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion.
Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.
Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of

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(UNAUDITED)

such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
Retail Base Rate Case
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.
In December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $19.6 million reduction in depreciation expense in the first six months of 2015.
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The recovery balance of each regulatory clause follows:
Recovery Clause
Balance Sheet Location
June 30, 2015
December 31, 2014




(in millions)
Fuel Cost Recovery – Under
Under recovered regulatory clause revenues
$24

$40
Purchased Power Capacity Recovery – Under
Under recovered regulatory clause revenues
2


Environmental Cost Recovery – Under
Under recovered regulatory clause revenues
7

10
Energy Conservation Cost Recovery – Under
Under recovered regulatory clause revenues


3
Mississippi Power
2015 Rate Case
On May 15, 2015 and July 10, 2015, Mississippi Power filed alternative rate proposals related to recovery of Kemper IGCC-related costs with the Mississippi PSC. See "Integrated Coal Gasification Combined Cycle Rate Recovery of Kemper IGCC Costs 2015 Rate Case" herein for additional information.

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(UNAUDITED)

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.
On March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow it more time for review. The ultimate outcome of this matter cannot be determined at this time.
System Restoration Rider
See Note 1 to the financial statements of Mississippi Power under "Provision for Property Damage" in Item 8 of the Form 10-K for additional information.
On February 2, 2015, Mississippi Power submitted its 2015 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2015 SRR rate remain level at zero and Mississippi Power be allowed to accrue $3 million to the property damage reserve in 2015. On March 3, 2015, the Mississippi PSC suspended the filing to allow it more time for review. The ultimate outcome of this matter cannot be determined at this time.
Environmental Compliance Overview Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" and "Other MattersSierra Club Settlement Agreement" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC and information on Plant Watson Units 4 and 5.
In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which are scheduled to be placed in service in September and November 2015, respectively. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of June 30, 2015, total project expenditures were $604 million, of which Mississippi Power's portion was $308 million, excluding AFUDC of $27 million.
On February 25, 2015, Mississippi Power submitted its annual ECO filing for 2015, which indicated an annual increase in revenues of approximately $8 million. On February 27, 2015, the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.
On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million excluding the reserve for cost of removal and has been reclassified to other regulatory assets, deferred, on Mississippi Power's Condensed Balance Sheet herein in accordance with an accounting order from the Mississippi PSC. Mississippi Power expects to recover through its rates the remaining book value of the retired assets and certain costs, including unusable inventory, associated with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Mississippi Power's fuel cost recovery.
At June 30, 2015, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $24 million compared to under-recovered retail fuel costs of $2 million at December 31, 2014.

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(UNAUDITED)

Ad Valorem Tax Adjustment
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information.
On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates. On May 26, 2015 the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the Kemper IGCC costs subject to the cost cap and the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of June 30, 2015, as adjusted for the Court's decision, are as follows:

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Cost Category
2010 Project Estimate(f)
 Current Estimate Actual Costs at June 30, 2015
 (in billions)
Plant Subject to Cost Cap(a)
$2.40
 $4.96
 $4.51
Lignite Mine and Equipment0.21 0.23 0.23
CO2 Pipeline Facilities
0.14 0.11 0.11
AFUDC(b)(c)
0.17 0.62 0.52
Combined Cycle and Related Assets Placed in
Service – Incremental
(d)

 0.02
 
General Exceptions0.05 0.10 0.08
Deferred Costs(c)(e)

 0.19 0.15
Total Kemper IGCC(a)(c)
$2.97
 $6.23
 $5.60
(a)
The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of theasset purchase agreement (APA) and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.
(b)Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.
(c)Amounts in the Current Estimate reflect estimated costs through March 31, 2016.
(d)Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.
(e)The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."
(f)
The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificatedestimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.08 billion), $2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, $16 million in other deferred charges and assets, and $24 million in AROs in the balance sheet, with $1 million previously expensed.
Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23 million ($14 million after tax) in the second quarter 2015 and $9 million ($6 million after tax) in the first quarter 2015. These amounts are in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $868 million ($536 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively. The increases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to equipment rework, scope modifications, and the related additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up

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(UNAUDITED)

and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.
Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and Mississippi Power's statements of operations and these changes could be material.
Rate Recovery of Kemper IGCC Costs
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 2015 Rate Case and any alternative proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements.
2013 Settlement Agreement
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power's

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intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.
2013 MPSC Rate Order
Consistent with the terms of the 2013 Settlement Agreement, in March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC through the in-service date until directed to do otherwise by the Mississippi PSC.
In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.
In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Southern Company and Mississippi Power.
2015 Mississippi Supreme Court Decision
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.

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2015 Rate Case
As a result of the 2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On May 15, 2015, Mississippi Power sought alternate rate recovery and filed a rate case (2015 Rate Case) with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
On July 10, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (the Supplemental Notice) with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal (In-Service Asset Proposal) for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.
The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
If the Mississippi PSC does not act on the Supplemental Notice or the 2015 Rate Case within 120 days of the Supplemental Notice filing, Mississippi Power expects to put one of the three viable alternative rate proposals into effect as temporary rates under bond and subject to refund pursuant to Mississippi state law.
Mississippi Power also expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 2015 of $6.23 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
Prudence Reviews
The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental

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(UNAUDITED)

Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of June 30, 2015, the regulatory asset balance associated with the Kemper IGCC was $198 million. The projected balance at March 31, 2016 is estimated to total approximately $276 million. The amortization period for any such costs approved for recovery remains subject to approval by the Mississippi PSC.
See "2015 Mississippi Supreme Court Decision" herein for additional information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.
See Note 1 to the financial statements of Southern Company and Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not

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(UNAUDITED)

affect pricing or minimum purchase quantities. Any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest to SMEPA
In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an asset purchase agreement (APA)APA whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the April 2011 power supply agreement were $17.5 million in 2013. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014.

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In 2012 and on January 2, 2014, Mississippi Power received $150 million and $75 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposits have been presented as a current liability in Southern Company's and Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Southern Company's and Mississippi Power's Condensed Statements of Cash Flows herein. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.
By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle with respect to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The parties agreed to further amendOn May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA as follows: (1)between Mississippi Power agreed to cap at $2.88 billion the portionand SMEPA. Mississippi Power previously received a total of the purchase price for development and construction costs, net$275 million of the Cost Cap Exceptions; title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2)deposits from SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the plant's in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continuethat were required to be accrued on the capped development and construction costs, the Cost Cap Exceptions and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment ofreturned to SMEPA with interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date.
The letter agreement also provides for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service. In addition, if the parties approve an amendment to the APA incorporating the terms of the letter agreement but do not execute the amendment before December 31, 2014, the parties agreed to extend the current APA through December 31, 2015.
The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement incorporating the principles of the amended APA, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase.
On October 9, 2014, Mississippi Power received an additional $50 million deposit from SMEPA to be applied to the purchase.
The ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionalitytermination of the Baseload Act currently pending beforeAPA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the Mississippi Supreme Court. The ultimate outcomeaggregate principal amount of any legal challengesapproximately $301 million to this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.Southern Company.

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(UNAUDITED)

Investment Tax Credits and Bonus Depreciation
The IRS allocated $279$279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through SeptemberJune 30, 2014,2015, Mississippi Power had recorded tax benefits totaling $276.4$276 million for the Phase II credits, of which approximately $140$242 million havehad been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the Phase II tax credits will be subjectMississippi Power currently expects to recapture upon completion of SMEPA's purchase of an undivided interest inplace the Kemper IGCC as described above.
In January 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which will apply primarily to the combined cycle and associated common facilities portionfirst half of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million. See "Rate Recovery of Kemper IGCC Costs – Seven-Year Rate Plan" herein for additional information.
2016. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Other MattersSection 174 Research and Experimental Deduction
Sierra Club Settlement Agreement
On August 1, 2014,Southern Company, on behalf of Mississippi Power, entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Clubreflected deductions for research and experimental (R&E) expenditures related to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC in its federal income tax calculations for 2013 and the scrubber project at Plant Daniel Units 1 and 2.2014. In addition, the Sierra Club agreedMay 2015, Southern Company amended its 2008 through 2013 federal income tax returns to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedingsinclude deductions for the Kemper IGCC, including, but not limitedIGCC-related R&E expenditures. Due to the prudence review,uncertainty related to this tax position, Southern Company and Plant Daniel for a periodMississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of three years fromJune 30, 2015. See Note 5 to the datefinancial statements of Southern Company and Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw all appeals associated with certification of the Kemper IGCCForm 10-K and the Plant Daniel Units 1Note (G) herein under "Unrecognized Tax Benefits Section 174 Research and 2 scrubber project, which the applicable courts granted in the third quarter 2014.
Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a 15-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In accordance with the Sierra Club Settlement Agreement, Mississippi Power paid $7 million in the third quarter 2014, recognized in other income (expense), net in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" hereinExperimental Deduction" for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

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(UNAUDITED)

(C)FAIR VALUE MEASUREMENTS
As of SeptemberJune 30, 2014,2015, assets and liabilities measured at fair value on a recurring basis during the period, together with the associated level of the fair value hierarchy, in which they fall, were as follows:
 Fair Value Measurements Using   Fair Value Measurements Using  
As of September 30, 2014: 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Total
As of June 30, 2015: 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Total
 (in millions) (in millions)
Southern Company                
Assets:                
Energy-related derivatives $
 $12
 $
 $12
 $
 $5
 $
 $5
Interest rate derivatives 
 11
 
 11
Nuclear decommissioning trusts(a)
 632
 875
 2
 1,509
 677
 887
 7
 1,571
Cash equivalents 955
 
 
 955
 533
 
 
 533
Other investments 9
 
 1
 10
 9
 
 1
 10
Total $1,596
 $887
 $3
 $2,486
 $1,219
 $903
 $8
 $2,130
Liabilities:                
Energy-related derivatives $
 $53
 $
 $53
 $
 $180
 $
 $180
Interest rate derivatives 
 2
 
 2
 
 14
 
 14
Total $
 $55
 $
 $55
 $
 $194
 $
 $194
                
Alabama Power                
Assets:                
Energy-related derivatives $
 $5
 $
 $5
 $
 $2
 $
 $2
Nuclear decommissioning trusts(b)
                
Domestic equity 399
 78
 
 477
 381
 78
 
 459
Foreign equity 34
 65
 
 99
 51
 50
 
 101
U.S. Treasury and government agency securities 
 34
 
 34
 
 36
 
 36
Corporate bonds 
 98
 
 98
 10
 121
 
 131
Mortgage and asset backed securities 
 19
 
 19
 
 17
 
 17
Other 
 8
 2
 10
 
 6
 7
 13
Cash equivalents 543
 
 
 543
 81
 
 
 81
Total $976
 $307
 $2
 $1,285
 $523
 $310
 $7
 $840
Liabilities:                
Energy-related derivatives $
 $11
 $
 $11
 $
 $48
 $
 $48
Interest rate derivatives 
 1
 
 1
 
 7
 
 7
Total $
 $12
 $
 $12
 $
 $55
 $
 $55

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 Fair Value Measurements Using   Fair Value Measurements Using  
As of September 30, 2014: 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Total
As of June 30, 2015: 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Total
 (in millions) (in millions)
Georgia Power                
Assets:                
Energy-related derivatives $
 $1
 $
 $1
 $
 $3
 $
 $3
Interest rate derivatives 
 5
 
 5
Nuclear decommissioning trusts(b) (c)
                
Domestic equity 191
 2
 
 193
 182
 1
 
 183
Foreign equity 
 132
 
 132
 
 125
 
 125
U.S. Treasury and government agency securities 
 126
 
 126
 
 95
 
 95
Municipal bonds 
 25
 
 25
 
 78
 
 78
Corporate bonds 
 169
 
 169
 
 169
 
 169
Mortgage and asset backed securities 
 114
 
 114
 
 108
 
 108
Other 8
 5
 
 13
 53
 3
 
 56
Total $199
 $574
 $
 $773
 $235
 $587
 $
 $822
Liabilities:                
Energy-related derivatives $
 $12
 $
 $12
 $
 $17
 $
 $17
Interest rate derivatives 
 4
 
 4
Total $
 $21
 $
 $21
                
Gulf Power                
Assets:                
Energy-related derivatives $
 $3
 $
 $3
Cash equivalents 18
 
 
 18
 $18
 $
 $
 $18
Total $18
 $3
 $
 $21
Liabilities:                
Energy-related derivatives $
 $19
 $
 $19
 
 74
 
 74
                
Mississippi Power                
Assets:                
Energy-related derivatives $
 $2
 $
 $2
Cash equivalents 45
 
 
 45
 $182
 $
 $
 $182
Total $45
 $2
 $
 $47
Liabilities:                
Energy-related derivatives $
 $10
 $
 $10
 
 41
 
 41
                
Southern Power                
Assets:                
Energy-related derivatives $
 $1
 $
 $1
Cash equivalents 80
 
 
 80
 $206
 $
 $
 $206
Total $80
 $1
 $
 $81
Liabilities:        
Energy-related derivatives $
 $1
 $
 $1
(a)For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.
(b)Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.purchases, and currencies.
(c)Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2015, approximately $39 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

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(c)Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of September 30, 2014, approximately $58 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.
Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.
For fair value measurements of the investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. Externalexternal pricing vendors are designated for each of the asset classes in the nuclear decommissioning trustsclass with each security discriminatelyspecifically assigned a primary pricing source, based on similar characteristics.source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgment, are also obtained when available.
Investments in private equity and real estate within theAlabama Power's nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
"Other investments" include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. For investments that are not traded in the open market, the price paid willmarket. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed.executions.

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As of SeptemberJune 30, 2014,2015, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
As of September 30, 2014: 
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
As of June 30, 2015: 
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
 (in millions)     (in millions)    
Southern Company      
Nuclear decommissioning trusts:      
Foreign equity funds $132
 None Monthly 5 days $125
 None Monthly 5 days
Equity - commingled funds 65
 None Daily/Monthly Daily/7 days 50
 None Daily Daily
Debt - commingled funds 16
 None Daily 5 days
Other - commingled funds 5
 None Daily Not applicable 3
 None Daily Not applicable
Other - money market funds 8
 None Daily Not applicable 53
 None Daily Not applicable
Trust-owned life insurance 112
 None Daily 15 days 117
 None Daily 15 days
Cash equivalents:      
Money market funds 955
 None Daily Not applicable 533
 None Daily Not applicable
Alabama Power      
Nuclear decommissioning trusts:      
Equity - commingled funds $65
 None Daily/Monthly Daily/7 days $50
 None Daily Daily
Debt - commingled funds 16
 None Daily 5 days
Trust-owned life insurance 112
 None Daily 15 days 117
 None Daily 15 days
Cash equivalents:      
Money market funds 543
 None Daily Not applicable 81
 None Daily Not applicable
Georgia Power      
Nuclear decommissioning trusts:      
Foreign equity funds $132
 None Monthly 5 days $125
 None Monthly 5 days
Other - commingled funds 5
 None Daily Not applicable 3
 None Daily Not applicable
Other - money market funds 8
 None Daily Not applicable 53
 None Daily Not applicable
Gulf Power      
Cash equivalents:      
Money market funds $18
 None Daily Not applicable $18
 None Daily Not applicable
Mississippi Power      
Cash equivalents:      
Money market funds $45
 None Daily Not applicable $182
 None Daily Not applicable
Southern Power      
Cash equivalents:      
Money market funds $80
 None Daily Not applicable $206
 None Daily Not applicable
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts including(including American depositary receipts, European depositary receipts, and global depositary receipts,receipts), and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to

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(UNAUDITED)

permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.

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The commingledother-commingled funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months fromhigh-quality, short-term, liquid debt securities. The funds represent cash collateral received under the date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days Funds' managers' securities lending program and/or less. The assets may be longer termexcess cash held within each separate investment grade fixed income obligations with maturity shortening provisions.account. The primary objective forof the commingled funds is to provide a high level of current income consistent with stability of principal and liquidity. IncludedThe funds invest primarily in, commingled funds as of September 30, 2014 is $5 million representing the investment of cash collateral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. The money market fund within Georgia Power's nuclear decommissioning trusts represents the short-term investment of the trusts' excess cash with the goal of providing the highest possible level of income while preserving capital and maintaining liquidity. The fund's positions are in high-quality, short-term, liquid money market instruments including, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government andor its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities. The fund maintains a dollar-weighted average maturity of 60securities that mature in 90 days or less and is regulated by, and subject to, the money market regulatory requirements set by the SEC.less. Redemptions are available on a same day basis up to the full amount of the investment in the fund. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Alabama Power's nuclear decommissioning trust includestrusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust investstrusts invest in the TOLI in order to minimize the impact of taxes on the portfolioportfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust doestrusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. TheThese commingled funds, along with other equity and debt commingled funds held in Alabama Power's nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three and ninesix months ended SeptemberJune 30, 2014,2015, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, decreasedincreased by $13$44 million and increased by $70$109 million, respectively, at Southern Company. For the three and ninesix months ended SeptemberJune 30, 2014,2015, Alabama Power recorded a decreasean increase in fair value of $8$50 million and an increase of $39$97 million, respectively, as an increase in regulatory liabilities. For the three and six months ended June 30, 2015, Georgia Power recorded a decrease in fair value of $5$6 million and an increase of $31$12 million, respectively, as a reduction of its regulatory asset related to its ARO.
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.

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As of SeptemberJune 30, 2014,2015, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 (in millions) (in millions)
Long-term debt:    
Long-term debt, including securities due within one year:    
Southern Company $23,936
 $25,318
 $26,156
 $26,973
Alabama Power $6,625
 $7,195
 $7,295
 $7,621
Georgia Power $9,597
 $10,167
 $10,379
 $10,767
Gulf Power $1,444
 $1,517
 $1,370
 $1,438
Mississippi Power $2,365
 $2,397
 $2,275
 $2,246
Southern Power $1,629
 $1,745
 $2,262
 $2,302
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offeredavailable to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.the registrants.
(D)STOCKHOLDERS' EQUITY
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effectseffect of both stock options and performance share award units werewas determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
 Three Months
Ended
September 30, 2014

Three Months
Ended
September 30, 2013
 Nine Months
Ended
September 30, 2014
 Nine Months
Ended
September 30, 2013
 Three Months Ended June 30, 2015
Three Months Ended June 30, 2014 Six Months Ended June 30, 2015 Six Months Ended June 30, 2014
 (in millions) (in millions)
As reported shares 898 878 894 874 909
 895
 910
 892
Effect of options and performance share award units 4 3 4 5 3
 4
 4
 4
Diluted shares 902 881 898 879 912
 899
 914
 896
Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 1615 million and 1 million for the three and six months ended June 30, 2015, respectively, and were 8 million and 17 million for the three and ninesix months ended SeptemberJune 30, 2014, respectively, and were 16 million and 1 million for the three and nine months ended September 30, 2013.respectively.

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Changes in Stockholders' Equity
The following table presents year-to-date changes in stockholders' equity of Southern Company:
 
Number of
Common Shares
 Common
Stockholders'
Equity
 
Preferred and
Preference
Stock of
Subsidiaries
 Total
Stockholders'
Equity
Number of
Common Shares
 Common
Stockholders'
Equity
 
Preferred and
Preference
Stock of
Subsidiaries
   Total
Stockholders'
Equity
 Issued Treasury Issued Treasury 
Noncontrolling Interest(*)
 
(in thousands) (in millions)
Balance at December 31, 2014908,502
 (725) $19,949
 $756
 $221
 $20,926
Net income after dividends on preferred and preference stock
 
 1,138
 
 
 1,138
Other comprehensive income (loss)
 
 7
 
 
 7
Stock issued3,222
 
 117
 
 
 117
Stock-based compensation
 
 66
 
 
 66
Stock repurchased, at cost
 (2,599) (115) 
 
 (115)
Cash dividends on common stock
 
 (972) 
 
 (972)
Preference stock redemption
 
 
 (150) 
 (150)
Contributions from noncontrolling interest
 
 
 
 135
 135
Distributions to noncontrolling interest
 
 
 
 (5) (5)
Net income attributable to noncontrolling interest
 
 
 
 4
 4
Other
 25
 (8) 3
 
 (5)
Balance at June 30, 2015911,724
 (3,299) $20,182
 $609
 $355
 $21,146
 (in thousands)   (in millions)             
Balance at December 31, 2013 892,733
 (5,647) $19,008
 $756
 $19,764
892,733
 (5,647) $19,008
 $756
 $
 $19,764
Net income after dividends on preferred and preference stock 
 
 1,680
 
 1,680

 
 962
 
 
 962
Other comprehensive income (loss) 
 
 6
 
 6

 
 4
 
 
 4
Treasury stock re-issued 
 4,996
 225
 
 225

 4,739
 216
 
 
 216
Stock issued 7,781
 
 332
 
 332
3,898
 
 161
 
 
 161
Stock repurchased, at cost 
 
 (5) 
 (5)
 
 (5) 
 
 (5)
Cash dividends on common stock 
 
 (1,390) 
 (1,390)
 
 (920) 
 
 (920)
Other 
 (51) 1
 
 1

 (27) 
 
 
 
Balance at September 30, 2014 900,514
 (702) $19,857
 $756
 $20,613
          
Balance at December 31, 2012 877,803
 (10,035) $18,297
 $707
 $19,004
Net income after dividends on preferred and preference stock 
 
 1,230
 
 1,230
Other comprehensive income (loss) 
 
 11
 
 11
Treasury stock re-issued 
 1,956
 89
 
 89
Stock issued 12,046
 
 484
 49
 533
Stock repurchased, at cost 
 
 (19) 
 (19)
Cash dividends on common stock 
 
 (1,314) 
 (1,314)
Other 
 (30) 
 
 
Balance at September 30, 2013 889,849
 (8,109) $18,778
 $756
 $19,534
Balance at June 30, 2014896,631
 (935) $19,426
 $756
 $
 $20,182
(*) Primarily related to Southern Power Company.
Stock Repurchased
On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through June 30, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market

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purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.
(E)FINANCING
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of SeptemberJune 30, 20142015 was approximately $1.8 billion.$1.9 billion (comprised of approximately $810 million at Alabama Power, $970 million at Georgia Power, $69 million at Gulf Power, and $40 million at Mississippi Power). In addition, at SeptemberJune 30, 2014,2015, the traditional operating companies had $423approximately $368 million (comprised of approximately $200 million at Alabama Power, $122 million at Georgia Power, and $46 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that will bewere required to be remarketedreoffered within the next 12 months. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information. In addition, $98 million of certain pollution control revenue bonds of Georgia Power have been reclassified to securities due within one year in anticipation of redemption in connection with unit retirement decisions. See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" and "Retail Regulatory Matters – Integrated Resource Plans," respectively, in Item 8 of the Form 10-K"Financing Activities" herein for additional information.
The following table outlines the committed credit arrangements by company as of SeptemberJune 30, 2014:2015:
 Expires   
Executable Term
Loans
 
Due Within One
Year
 Expires   
Executable Term
Loans
 
Due Within One
Year
Company 2014
 2015
 2016
 2017 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
 2015
 2016
 2017 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
 (in millions) (in millions) (in millions) (in millions) (in millions) (in millions) (in millions) (in millions)
Southern Company $
 $
 $
 $
 $1,000
 $1,000
 $1,000
 $
 $
 $
 $
 $
 $
 $
 $1,000
 $1,000
 $1,000
 $
 $
 $
 $
Alabama Power 70
 158
 50
 
 1,030
 1,308
 1,308
 58
 
 58
 170
 154
 124
 
 1,030
 1,308
 1,307
 58
 
 58
 170
Georgia Power 
 
 150
 
 1,600
 1,750
 1,736
 
 
 
 
 
 150
 
 1,600
 1,750
 1,737
 
 
 
 150
Gulf Power 20
 60
 165
 30
 
 275
 275
 50
 
 50
 30
 20
 225
 30
 
 275
 275
 50
 
 50
 195
Mississippi Power 15
 120
 165
 
 
 300
 300
 25
 40
 65
 70
 40
 255
 
 
 295
 265
 30
 40
 70
 225
Southern Power 
 
 
 
 500
 500
 499
 
 
 
 
 
 
 
 500
 500
 466
 
 
 
 
Other 
 70
 
 
 
 70
 70
 20
 
 20
 50
 25
 45
 
 
 70
 70
 20
 
 20
 50
Total $105
 $408
 $530
 $30
 $4,130
 $5,203
 $5,188
 $153
 $40
 $193
 $320
 $239
 $799
 $30
 $4,130
 $5,198
 $5,120
 $158
 $40
 $198
 $790
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

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Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first ninesix months of 2014:2015:
Company(a)Senior Note Issuances 
Senior
Note Maturities
 
Revenue
Bond
Issuances and
Remarketings
of Purchased
Bonds(a)
 
Revenue
Bond
Redemptions
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt
Redemptions(b)
Senior Note Issuances 
Senior
Note Redemptions
 
Revenue
Bond
Issuances and
Reofferings
of Purchased
Bonds(b)
 Revenue
Bond
Maturities and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt Redemptions
and
Maturities(c)
(in millions)(in millions)
Southern Company$750
 $350
 $
 $
 $
 $
$600
 $
 $
 $
 $
 $
Alabama Power400
 
 
 
 
 
975
 250
 80
 134
 
 
Georgia Power
 
 40
 37
 1,000
 4

 125
 170
 65
 600
 5
Gulf Power200
 
 42
 29
 
 
Mississippi Power
 
 
 
 493
 222

 
 
 
 
 351
Southern Power
 
 
 
 10
 1
650
 
 
 
 
 
Other
 
 
 
 
 15

 
 
 
 
 9
Elimination(c)

 
 
 
 (220) (220)
Total$1,350
 $350
 $82
 $66
 $1,283
 $22
$2,225
 $375
 $250
 $199
 $600
 $365
(a)Includes remarketing by Gulf Power did not issue or redeem any long-term debt during the first six months of $132015.
(b)Includes reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds previously purchased and held by GulfAlabama Power since December 2013April 2015 and remarketingreofferings by Georgia Power of $40$104.6 million and $65 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2010.2013 and April 2015, respectively.
(b)(c)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
(c)Intercompany loan from Southern Company to Mississippi Power eliminated in Southern Company's Condensed Consolidated Financial Statements. This loan was repaid on September 29, 2014.
Southern Company
In August 2014,June 2015, Southern Company issued $400$600 million aggregate principal amount of Series 2014A 1.30%2015A 2.750% Senior Notes due AugustJune 15, 2017 and $350 million aggregate principal amount of Series 2014B 2.15% Senior Notes due September 1, 2019.2020. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.
Alabama Power
In August 2014,March 2015, Alabama Power issued $400$550 million aggregate principal amount of Series 2014A 4.150%2015A 3.750% Senior Notes due AugustMarch 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, 2044. The2035 and for general corporate purposes, including Alabama Power's continuous construction program.
In April 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power reoffered these bonds to the public in May 2015.
Also in April 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used to redeem in May 2015 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for general corporate purposes, including Alabama Power's continuous construction program.
Georgia Power
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee.
The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB. On February 20, 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount ofprogram.

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$1.0 billion. Georgia Power's reimbursement obligations to the DOE are full recourse and also secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. Power
In connection with its entry into the agreements with the DOE and the FFB,April 2015, Georgia Power incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.
See Note 6 to the financial statements of Southern Companypurchased and Georgia Power in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.
In July 2014, Georgia Power reoffered to the public $40held $65 million aggregate principal amount of Development Authority of MonroeBurke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant SchererVogtle Project), Second Series 2008. Georgia Power reoffered these bonds to the public in May 2015.
In May 2015, Georgia Power reoffered to the public $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2009,2013, which had been previously purchased and held by Georgia Power since 2010.
Gulf Power2013.
In April 2014, GulfJune 2015, Georgia Power executed a loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075 millionmade additional borrowings under the FFB Credit Facility in an aggregate principal amount of Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 for$600 million. The interest rate applicable to the benefit of Gulf Power. The proceeds were used to redeem $29.075$600 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).
In June 2014, Gulf Power reofferedis 3.283% for an interest period that extends to the public $13 million aggregate principal amountfinal maturity date of MBFC Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 2012 (Gulf Power Company Project), which had been previously purchased and held by Gulf Power since December 2013.
In September 2014, Gulf Power issued $200 million aggregate principal amount of Series 2014A 4.55% Senior Notes due October 1,February 20, 2044. The proceeds were used to repayreimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. Georgia Power settled $350 million of interest rate swaps related to this borrowing for approximately $6 million, which will be amortized to interest expense over 10 years.
Mississippi Power
In April 2015, Mississippi Power entered into two floating rate bank loans with a portionmaturity date of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power's continuous construction program, and subsequent to September 30, 2014, for repayment at maturity $75 millionApril 1, 2016, in an aggregate principal amount of Gulf Power's Series K 4.90% Senior Notes due October 1, 2014.
Mississippi Power
In January 2014, Mississippi Power entered into an 18-month floating rate bank loan$475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loan was for $250 millionloans in an aggregate principal amount and proceeds were used forof $275 million, working capital, and other general corporate purposes, including Mississippi Power's continuousongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In January 2014 and subsequent to September 30, 2014,June 2015, Mississippi Power receivedissued an additional $7518-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, and $50 million, respectively,the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of interest-bearing refundable deposits from SMEPA to be applied to the sale price forreturn of SMEPA's deposit in connection with the pending saletermination of an undivided interest in the Kemper IGCC.APA. See Note 3 to the financial statements of Southern Company and Mississippi Power in Item 8 of the Form 10-K(B) under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
As reflected in the table above in "Other Long-Term Debt Issuances," in May 2014, Mississippi Power issued a 19-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loan was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program. This loan was repaid on September 29, 2014.
In May 2014 and August 2014, the MBFC issued $12.3 million and $10.5 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of

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Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose.
Southern Power
During the nine months ended September 30, 2014, Southern Power prepaid $0.8 million of long-term debt payable to Turner Renewable Energy, LLC (TRE) and issued $3.9 million due April 30, 2034, $5.3 million due May 31, 2034, $0.8 million due April 30, 2033, and an additional $0.1 million due June 15, 2032 under promissory notes payable to TRE related to the financing of Adobe Solar, LLC (Adobe), Macho Springs Solar, LLC (Macho Springs), Campo Verde Solar, LLC, and Apex Nevada Solar, LLC, respectively.
(F)RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

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(UNAUDITED)

Components of the net periodic benefit costs for the three and nine months ended September 30, 2014 and 2013 were as follows:
Pension Plans 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
  (in millions)
Three Months Ended September 30, 2014          
Service cost $53
 $12
 $16
 $4
 $3
Interest cost 109
 26
 39
 4
 5
Expected return on plan assets (161) (42) (57) (7) (8)
Amortization:          
Prior service costs 6
 2
 2
 
 
Net (gain)/loss 28
 7
 10
 1
 2
Net cost $35
 $5
 $10
 $2
 $2
Nine Months Ended September 30, 2014          
Service cost $160
 $36
 $47
 $8
 $8
Interest cost 326
 78
 115
 14
 15
Expected return on plan assets (484) (126) (170) (21) (22)
Amortization:          
Prior service costs 19
 5
 7
 1
 1
Net (gain)/loss 83
 23
 30
 3
 4
Net cost $104
 $16
 $29
 $5
 $6
Three Months Ended September 30, 2013          
Service cost $58
 $12
 $17
 $3
 $3
Interest cost 97
 23
 35
 4
 5
Expected return on plan assets (151) (39) (54) (6) (7)
Amortization:          
Prior service costs 7
 2
 3
 
 1
Net (gain)/loss 50
 13
 19
 2
 2
Net cost $61
 $11
 $20
 $3
 $4
Nine Months Ended September 30, 2013          
Service cost $174
 $39
 $52
 $8
 $8
Interest cost 291
 69
 104
 13
 14
Expected return on plan assets (452) (117) (160) (19) (20)
Amortization:          
Prior service costs 20
 5
 8
 1
 1
Net (gain)/loss 150
 39
 56
 6
 7
Net cost $183
 $35
 $60
 $9
 $10

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Postretirement Benefits 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
  (in millions)
Three Months Ended September 30, 2014          
Service cost $5
 $1
 $2
 $
 $
Interest cost 19
 5
 9
 
 
Expected return on plan assets (14) (6) (6) 
 
Amortization:          
Prior service costs 1
 1
 
 
 
Net (gain)/loss 1
 
 
 
 
Net cost $12
 $1
 $5
 $
 $
Nine Months Ended September 30, 2014          
Service cost $16
 $4
 $5
 $1
 $1
Interest cost 59
 15
 26
 2
 2
Expected return on plan assets (44) (19) (19) (1) (1)
Amortization:          
Prior service costs 3
 3
 
 
 
Net (gain)/loss 2
 
 1
 
 
Net cost $36
 $3
 $13
 $2
 $2
Three Months Ended September 30, 2013          
Service cost $6
 $2
 $3
 $
 $
Interest cost 18
 5
 8
 1
 1
Expected return on plan assets (14) (6) (7) (1) 
Amortization:          
Transition obligation 2
 
 1
 
 
Prior service costs 1
 1
 
 
 
Net (gain)/loss 3
 
 2
 
 
Net cost $16
 $2
 $7
 $
 $1
Nine Months Ended September 30, 2013          
Service cost $18
 $5
 $6
 $1
 $1
Interest cost 55
 14
 24
 2
 3
Expected return on plan assets (42) (18) (19) (1) (1)
Amortization:          
Transition obligation 4
 
 3
 
 
Prior service costs 3
 3
 
 
 
Net (gain)/loss 9
 1
 6
 
 
Net cost $47
 $5
 $20
 $2
 $3

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(G)EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS
Effective Tax Rate
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.
Southern Company
Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity.
Southern Company's effective tax rate was 33.9% for the nine months ended September 30, 2014 compared to 33.9% for the corresponding period in 2013. The effective tax rate was impacted by the offsetting increases resulting from higher net income and less benefit related to investment tax credits, and decreases resulting from more non-taxable AFUDC equity, changes in state apportionment, and beneficial changes in certain state income tax laws.
Alabama Power
Alabama Power's effective tax rate was 39.0% for the nine months ended September 30, 2014 compared to 39.3% for the corresponding period in 2013.
Georgia Power
Georgia Power's effective tax rate was 37.2% for the nine months ended September 30, 2014 compared to 38.0% for the corresponding period in 2013.
Gulf Power
Gulf Power's effective tax rate was 37.4% for the nine months ended September 30, 2014 compared to 37.6% for the corresponding period in 2013.
Mississippi Power
Mississippi Power's effective tax rate was (45.5)% for the nine months ended September 30, 2014 compared to (42.1)% for the corresponding period in 2013. The change in the tax benefit was primarily due to an increase in non-taxable AFUDC equity related to the construction of the Kemper IGCC, partially offset by a lower net loss for the current period compared to the corresponding period in 2013.
Southern Power
In May 2015, Southern Power Company issued $350 million aggregate principal amount of Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.
(F)RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Components of the net periodic benefit costs for the three and six months ended June 30, 2015 and 2014 were as follows:
Pension Plans 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
  (in millions)
Three Months Ended June 30, 2015          
Service cost $64
 $15
 $18
 $3
 $3
Interest cost 111
 27
 39
 5
 6
Expected return on plan assets (181) (44) (63) (8) (9)
Amortization:          
Prior service costs 7
 1
 2
 
 1
Net (gain)/loss 54
 13
 19
 2
 2
Net cost $55
 $12
 $15
 $2
 $3
Six Months Ended June 30, 2015          
Service cost $128
 $30
 $36
 $6
 $6
Interest cost 222
 53
 77
 10
 11
Expected return on plan assets (362) (89) (126) (16) (17)
Amortization:          
Prior service costs 13
 3
 5
 
 1
Net (gain)/loss 108
 27
 38
 5
 5
Net cost $109
 $24
 $30
 $5
 $6
Three Months Ended June 30, 2014          
Service cost $54
 $12
 $15
 $1
 $2
Interest cost 108
 26
 38
 5
 5
Expected return on plan assets (162) (42) (56) (7) (7)
Amortization:          
Prior service costs 7
 2
 2
 1
 1
Net (gain)/loss 27
 8
 10
 1
 1
Net cost $34
 $6
 $9
 $1
 $2
Six Months Ended June 30, 2014          
Service cost $107
 $24
 $31
 $4
 $5
Interest cost 217
 52
 76
 10
 10
Expected return on plan assets (323) (84) (113) (14) (14)
Amortization:          
Prior service costs 13
 3
 5
 1
 1
Net (gain)/loss 55
 16
 20
 2
 2
Net cost $69
 $11
 $19
 $3
 $4

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Postretirement Benefits 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
  (in millions)
Three Months Ended June 30, 2015          
Service cost $5
 $2
 $1
 $
 $1
Interest cost 20
 5
 9
 1
 1
Expected return on plan assets (14) (7) (6) (1) (1)
Amortization:          
Prior service costs 1
 
 
 
 
Net (gain)/loss 4
 1
 3
 
 
Net cost $16
 $1
 $7
 $
 $1
Six Months Ended June 30, 2015          
Service cost $11
 $3
 $3
 $
 $1
Interest cost 39
 10
 17
 2
 2
Expected return on plan assets (29) (13) (12) (1) (1)
Amortization:          
Prior service costs 2
 1
 
 
 
Net (gain)/loss 9
 1
 6
 
 
Net cost $32
 $2
 $14
 $1
 $2
Three Months Ended June 30, 2014          
Service cost $6
 $2
 $1
 $1
 $1
Interest cost 20
 5
 9
 1
 1
Expected return on plan assets (15) (7) (7) (1) (1)
Amortization:          
Prior service costs 1
 1
 
 
 
Net (gain)/loss 
 
 1
 
 
Net cost $12
 $1
 $4
 $1
 $1
Six Months Ended June 30, 2014          
Service cost $11
 $3
 $3
 $1
 $1
Interest cost 40
 10
 17
 2
 2
Expected return on plan assets (30) (13) (13) (1) (1)
Amortization:          
Prior service costs 2
 2
 
 
 
Net (gain)/loss 1
 
 1
 
 
Net cost $24
 $2
 $8
 $2
 $2

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(UNAUDITED)

(G)INCOME TAXES
Current and Deferred Income Taxes
State of Georgia Tax Benefits
During the second quarter 2015, an agreement was reached with the Georgia Department of Revenue that will allow Southern Company to utilize a net operating loss carryforward over a four-year period beginning in 2017. Consequently, Southern Company reversed the related valuation allowance and recognized approximately $24 million in net tax benefits as of June 30, 2015. See Note 5 to the financial statements of Southern Company under "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.
Southern Power ITC Carryforwards
Southern Power had federal ITC carryforwards which are expected to result in $428 million of federal income tax benefits as of June 30, 2015, compared to $305 million as of December 31, 2014. The carryforwards as of June 30, 2015 expire between 2031 and 2035 and are expected to be utilized by the end of 2016.
Effective Tax Rate
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.
Mississippi Power
Mississippi Power's effective tax rate was 19.0% for the six months ended June 30, 2015 compared to (51.1)% for the corresponding period in 2014. The increase was primarily due to higher net income, partially offset by a decrease in non-taxable AFUDC equity related to the construction of the Kemper IGCC.
Southern Power
Southern Power's effective tax rate was 14.4%13.7% for the ninesix months ended SeptemberJune 30, 20142015 compared to 20.5%0.3% for the corresponding period in 2013.2014. The decreaseincrease was primarily due to the impact of state apportionmentbeneficial changes which reduced Southern Power's deferred tax liabilities, a change in filing method for North Carolina income tax, an increase inthat impacted 2014 state income tax credits, and beneficial changes in certain state income tax laws. The decrease wastaxes, which were partially offset by lessincreased federal income tax benefitbenefits related to investment tax creditsITCs in the current year.
Unrecognized Tax Benefits
ForSee Note 5 to the 2013 tax year,financial statements of Southern Company under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
Changes during 2015 for unrecognized tax benefits were as follows:
 Mississippi Power Southern Power Southern Company
 (in millions)
Unrecognized tax benefits as of December 31, 2014$165
 $5
 $170
Tax positions from current periods
 2
 2
Tax positions from prior periods230
 
 231
Reductions due to settlements(5) 
 (5)
Balance as of June 30, 2015$390
 $7
 $398
The tax positions from prior periods relate primarily to 2008 through 2013 amended federal income tax returns that were filed to include deductions for Kemper IGCC-related R&E expenditures. See "Section 174 Research and Experimental Deduction" herein for additional information.

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The impact on the effective tax rate, if recognized, was as follows:
 As of June 30, 2015 As of December 31, 2014
 Mississippi Power Southern Power Southern Company Southern Company
 (in millions)
Tax positions impacting the effective tax rate$
 $7
 $8
 $10
Tax positions not impacting the effective tax rate390
 
 390
 160
Balance of unrecognized tax benefits$390
 $7
 $398
 $170
The tax positions impacting the effective tax rate primarily relate to federal income tax benefits related to ITCs. The tax positions not impacting the effective tax rate relate to deductions for Kemper IGCC-related R&E expenditures. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Section 174 Research and Experimental Deduction
Southern Company reduced tax payments for 2014, and included in its 2013 consolidated federal income tax return a deductiondeductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures.
The Kemper IGCC is based on first-of-a-kind technology, and Mississippi Power and Southern Company believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position, Mississippi Power and Southern Company recorded anhad related unrecognized tax benefitbenefits associated with these R&E deductions of approximately $100$390 million and associated interest of $2$5 million as of SeptemberJune 30, 2014.2015.
The ultimate outcome of this matter cannot be determined at this time.

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(UNAUDITED)

(H)DERIVATIVES
Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note (C) herein for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.
Energy-Related Derivatives
The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel

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(UNAUDITED)

prices and prices of electricity because their 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 from its uncontracted generating capacity. Further, the traditional operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.
To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

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(UNAUDITED)

At SeptemberJune 30, 2014,2015, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
 
Net
Purchased
mmBtu
 
Longest
Hedge
Date
 
Longest
Non-Hedge
Date
 
Net
Purchased
mmBtu
 
Longest
Hedge
Date
 
Longest
Non-Hedge
Date
 (in millions)     (in millions)    
Southern Company 232 2018 2017 220 2020 2017
Alabama Power 57 2017  49 2018 
Georgia Power 47 2017  47 2017 
Gulf Power 77 2018  80 2020 
Mississippi Power 49 2017  43 2018 
Southern Power 2  2017 1 2015 2017
In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 75 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 43 million mmBtu for Georgia Power, and 1 million mmBtu for Southern Power.
For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending SeptemberJune 30, 20152016 are immaterial for all registrants.

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(UNAUDITED)

Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.
At SeptemberJune 30, 2014,2015, the following interest rate derivatives were outstanding:
  
Notional
Amount
 
Interest
Rate
Received
 
Weighted
Average
Interest
Rate Paid
 
Hedge
Maturity
Date
 
Fair Value
Gain (Loss)
September 30,
2014
  (in millions)       (in millions)
Cash flow hedges of forecasted debt          
Alabama Power $100
 3-month
LIBOR 
 3.07% October 2025 $(1)
Fair value hedges on existing debt          
Southern Company 250
 1.30% 3-month
LIBOR + 0.17%
 August 2017 (1)
Total $350
       $(2)

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(UNAUDITED)

Subsequent to September 30, 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $100 million.
Subsequent to September 30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amounts of the swaps totaled $900 million.
  
Notional
Amount
 
Interest
Rate
Received
 
Weighted
Average
Interest
Rate Paid
 
Hedge
Maturity
Date
 
Fair Value
Gain (Loss) at June 30,
2015
  (in millions)       (in millions)
Cash Flow Hedges of Forecasted Debt        
Alabama Power $200
 3-month
LIBOR 
 2.93% October 2025 $(7)
Georgia Power 350
 3-month
LIBOR 
 2.57% November 2025 (1)
Cash Flow Hedges of Existing Debt        
Georgia Power 250
 3-month
LIBOR + 0.32%
 0.75% March 2016 
Georgia Power 200
 3-month
LIBOR + 0.40%
 1.01% August 2016 
Fair Value Hedges on Existing Debt        
Southern Company 250
 1.30% 3-month
LIBOR + 0.17%
 August 2017 2
Southern Company 300
 2.75% 
3-month
LIBOR + 0.92%
 June 2020 1
Georgia Power 250
 5.40% 3-month
LIBOR + 4.02%
 June 2018 1
Georgia Power 200
 4.25% 3-month
LIBOR + 2.46%
 December 2019 1
Total $2,000
       $(3)
The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending SeptemberJune 30, 20152016 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2037.
Foreign Currency Derivatives
Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset.
At September 30, 2014, there were no foreign currency derivatives outstanding.
Derivative Financial Statement Presentation and Amounts
At September 30, 2014, the fair value of energy-related derivatives (excluding regulatory hedges) was immaterial. At September 30, 2014, the fair value of energy-related derivatives designated as hedging instruments for regulatory purposes and interest rate derivatives was reflected in the balance sheets as follows:
Asset Derivatives at September 30, 2014
  Fair Value
Derivative Category and Balance Sheet Location 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
  (in millions)
Derivatives designated as hedging instruments for regulatory purposes            
Energy-related derivatives:            
Other current assets $9
 $4
 $1
 $2
 $2
  
Other deferred charges and assets 2
 1
 
 1
 
  
Total derivatives designated as hedging instruments for regulatory purposes $11
 $5
 $1
 $3
 $2
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Interest rate derivatives:            
Other current assets $2
 $
 $
 $
 $
 $
Total asset derivatives $13
 $5
 $1
 $3
 $2
 $

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(UNAUDITED)

Derivative Financial Statement Presentation and Amounts
At June 30, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
Liability Derivatives at September 30, 2014
  Fair Value
Derivative Category and
Balance Sheet Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
  (in millions)
Derivatives designated as hedging instruments for regulatory purposes            
Energy-related derivatives:            
Liabilities from risk management activities (a)
 $27
 $5
 $10
 $7
 $5
  
Other deferred credits and liabilities 25
 6
 2
 12
 5
  
Total derivatives designated as hedging instruments for regulatory purposes $52
 $11
 $12
 $19
 $10
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Interest rate derivatives:            
Other deferred credits and liabilities $4
 $1
 $
 $
 $
 $
Total liability derivatives $56
 $12
 $12
 $19
 $10
 $
Asset Derivatives at June 30, 2015
  Fair Value
Derivative Category and Balance Sheet Location 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
  (in millions)
Derivatives designated as hedging instruments for regulatory purposes            
Energy-related derivatives:            
Other current assets $5
 $2
 $3
 $
 $
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Interest rate derivatives:            
Other current assets $11
 $
 $5
 $
 $
 $
Total asset derivatives $16
 $2
 $8
 $
 $
 $
(a)Georgia Power includes liabilities from risk management activities in other current liabilities.
Liability Derivatives at June 30, 2015
  Fair Value
Derivative Category and
Balance Sheet Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
  (in millions)
Derivatives designated as hedging instruments for regulatory purposes            
Energy-related derivatives:            
Other current liabilities(*)
 $99
 $31
 $15
 $32
 $21
  
Other deferred credits and liabilities 81
 17
 2
 42
 20
  
Total derivatives designated as hedging instruments for regulatory purposes $180
 $48
 $17
 $74
 $41
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Interest rate derivatives:            
Other current liabilities(*)
 $8
��$7
 $1
 $
 $
 $
Other deferred credits and liabilities 6
 
 3
 
 
 
Total derivatives designed as hedging instruments in cash flow and fair value hedges $14
 $7
 $4
 $
 $
 $
Total liability derivatives $194
 $55
 $21
 $74
 $41
 $
(*) Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

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(UNAUDITED)

At December 31, 2013,2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
Asset Derivatives at December 31, 2013
Asset Derivatives at December 31, 2014Asset Derivatives at December 31, 2014
 Fair Value Fair Value
Derivative Category and Balance Sheet Location 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
 (in millions) (in millions)
Derivatives designated as hedging instruments for regulatory purposes                        
Energy-related derivatives:                        
Other current assets $16
 $5
 $3
 $5
 $3
   $7
 $1
 $6
 $
 $
  
Other deferred charges and assets 7
 2
 2
 2
 2
   
 
 1
 
 
  
Total derivatives designated as hedging instruments for regulatory purposes $23
 $7
 $5
 $7
 $5
 N/A
 $7
 $1
 $7
 $
 $
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges                        
Interest rate derivatives:                        
Other current assets $3
 $
 $
 $
 $
 $
 $7
 $
 $5
 $
 $
 $
Other deferred charges and assets 1
 
 1
 
 
 
Total derivatives designated as hedging instruments in cash flow and fair value hedges $8
 $
 $6
 $
 $
 $
Derivatives not designated as hedging instruments                        
Energy-related derivatives:                        
Other deferred charges and assets 1
 
 
 
 
 1
Other current assets $6
 $
 $
 $
 $
 $5
Total asset derivatives $27
 $7
 $5
 $7
 $5
 $1
 $21
 $1
 $13
 $
 $
 $5

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(UNAUDITED)

Liability Derivatives at December 31, 2014
  Fair Value
Derivative Category and
Balance Sheet Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Power 
  (in millions)
Derivatives designated as hedging instruments for regulatory purposes            
Energy-related derivatives:            
Other current liabilities(*)
 $118
 $32
 $23
 $37
 $26
 

Other deferred credits and liabilities 79
 21
 4
 35
 19
 

Total derivatives designated as hedging instruments for regulatory purposes $197
 $53
 $27
 $72
 $45
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Interest rate derivatives:            
Other current liabilities(*)
 $17
 $8
 $9
 $
 $
 $
Other deferred credits and liabilities 7
 
 5
 
 
 
Total derivatives designated as hedging instruments in cash flow and fair value hedges $24
 $8
 $14
 $
 $
 $
Derivatives not designated as hedging instruments            
Energy-related derivatives:            
Other current liabilities $4
 $
 $
 $
 $
 $4
Total liability derivatives $225
 $61
 $41
 $72
 $45
 $4
Liability Derivatives at December 31, 2013
  Fair Value
Derivative Category and
Balance Sheet Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Power 
  (in millions)
Derivatives designated as hedging instruments for regulatory purposes            
Energy-related derivatives:            
Liabilities from risk management activities (a)
 $26
 $3
 $13
 $6
 $4
 

Other deferred credits and liabilities 29
 5
 8
 11
 6
 

Total derivatives designated as hedging instruments for regulatory purposes $55
 $8
 $21
 $17
 $10
 N/A
Derivatives not designated as hedging instruments            
Energy-related derivatives:            
Liabilities from risk management activities $1
 $
 $
 $
 $
 $1
Total liability derivatives $56
 $8
 $21
 $17
 $10
 $1
(a) Georgia(*) Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities in other current liabilities.activities."
The derivative contracts of Southern Company, the traditional operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and are reported gross on each registrant's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at SeptemberJune 30, 20142015 and December 31, 20132014 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.

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(UNAUDITED)

Derivative Contracts at September 30, 2014
Derivative Contracts at June 30, 2015Derivative Contracts at June 30, 2015
 Fair Value Fair Value
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
 (in millions) (in millions)
Assets                        
Energy-related derivatives:                        
Energy-related derivatives presented in the Balance Sheet (a)
 $12
 $5
 $1
 $3
 $2
 $1
 $5
 $2
 $3
 $
 $
 $
Gross amounts not offset in the Balance Sheet (b)
 (11) (4) (1) (3) (2) 
 (5) (2) (3) 
 
 
Net energy-related derivative assets $1
 $1
 $
 $
 $
 $1
 $
 $
 $
 $
 $
 $
Interest rate derivatives:            
Interest rate derivatives presented in the Balance Sheet (a)
 $11
 $
 $5
 $
 $
 $
Gross amounts not offset in the Balance Sheet (b)
 (8) 
 (3) 
 
 
Net interest rate derivative assets $3
 $
 $2
 $
 $
 $
Liabilities                        
Energy-related derivatives:                        
Energy-related derivatives presented in the Balance Sheet (a)
 $53
 $11
 $12
 $19
 $10
 $1
 $180
 $48
 $17
 $74
 $41
 $
Gross amounts not offset in the Balance Sheet (b)
 (11) (4) (1) (3) (2) 
 (5) (2) (3) 
 
 
Net energy-related derivative liabilities $42
 $7
 $11
 $16
 $8
 $1
 $175
 $46
 $14
 $74
 $41
 $
Interest rate derivatives:            
Interest rate derivatives presented in the Balance Sheet (a)
 $14
 $7
 $4
 $
 $
 $
Gross amounts not offset in the Balance Sheet (b)
 (8) 
 (3) 
 
 
Net interest rate derivative liabilities $6
 $7
 $1
 $
 $
 $
(a) None of the registrants offsetoffsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

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(UNAUDITED)

Derivative Contracts at December 31, 2013
Derivative Contracts at December 31, 2014Derivative Contracts at December 31, 2014
 Fair Value Fair Value
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Power
 (in millions) (in millions)
Assets                        
Energy-related derivatives:                        
Energy-related derivatives presented in the Balance Sheet (a)
 $24
 $7
 $5
 $7
 $5
 $1
 $13
 $1
 $7
 $
 $
 $5
Gross amounts not offset in the Balance Sheet (b)
 (22) (5) (5) (6) (4) 
 (9) 
 (7) 
 
 
Net energy-related derivative assets $2
 $2
 $
 $1
 $1
 $1
 $4
 $1
 $
 $
 $
 $5
Interest rate derivatives:            
Interest rate derivatives presented in the Balance Sheet (a)
 $8
 $
 $6
 $
 $
 $
Gross amounts not offset in the Balance Sheet (b)
 (8) 
 (6) 
 
 
Net interest rate derivative assets $
 $
 $
 $
 $
 $
Liabilities                        
Energy-related derivatives:                        
Energy-related derivatives presented in the Balance Sheet (a)
 $56
 $8
 $21
 $17
 $10
 $1
 $201
 $53
 $27
 $72
 $45
 $4
Gross amounts not offset in the Balance Sheet (b)
 (22) (5) (5) (6) (4) 
 (9) 
 (7) 
 
 
Net energy-related derivative liabilities $34
 $3
 $16
 $11
 $6
 $1
 $192
 $53
 $20
 $72
 $45
 $4
Interest rate derivatives:            
Interest rate derivatives presented in the Balance Sheet (a)
 $24
 $8
 $14
 $
 $
 $
Gross amounts not offset in the Balance Sheet (b)
 (8) 
 (6) 
 
 
Net interest rate derivative liabilities $16
 $8
 $8
 $
 $
 $
(a) None of the registrants offsetoffsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

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(UNAUDITED)

At SeptemberJune 30, 20142015 and December 31, 2013,2014, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at September 30, 2014
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 2015Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 2015
Derivative Category and Balance Sheet
Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 (in millions) (in millions)
Energy-related derivatives:                    
Other regulatory assets, current $(27) $(5) $(10) $(7) $(5) $(99) $(31) $(15) $(32) $(21)
Other regulatory assets, deferred (25) (6) (2) (12) (5) (81) (17) (2) (42) (20)
Other regulatory liabilities, current(a) 9
 4
 1
 2
 2
 5
 2
 3
 
 
Other regulatory liabilities, deferred (a)(b)
 2
 1
 
 1
 
 
 
 
 
 
Total energy-related derivative gains (losses) $(41) $(6) $(11) $(16) $(8) $(175) $(46) $(14) $(74) $(41)
(a)Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.
(a) Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.
(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2014
Derivative Category and Balance Sheet
Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
  (in millions)
Energy-related derivatives:          
Other regulatory assets, current $(118) $(32) $(23) $(37) $(26)
Other regulatory assets, deferred (79) (21) (4) (35) (19)
Other regulatory liabilities, current (a)
 7
 1
 6
 
 
Other regulatory liabilities, deferred (b)
 
 
 1
 
 
Total energy-related derivative gains (losses) $(190) $(52) $(20) $(72) $(45)
(a) Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.
(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.
For the three months ended June 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
Derivatives in Cash Flow
Hedging Relationships
 
Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion)
 
Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)
  Statements of Income Location Amount
  2015 2014   2015 2014
  (in millions)   (in millions)
Southern Company          
Interest rate derivatives $31
 $
 Interest expense, net of amounts capitalized $(2) $(2)
Alabama Power          
Interest rate derivatives $7
 $
 Interest expense, net of amounts capitalized $(1) $
Georgia Power          
Interest rate derivatives $24
 $
 Interest expense, net of amounts capitalized $(1) $
Mississippi Power          
Interest rate derivatives $
 $
 Interest expense, net of amounts capitalized $
 $(1)
Southern Power          
Interest rate derivatives $
 $
 Interest expense, net of amounts capitalized $
 $(1)

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(UNAUDITED)

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2013
Derivative Category and Balance Sheet
Location
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
  (in millions)
Energy-related derivatives:          
Other regulatory assets, current $(26) $(3) $(13) $(6) $(4)
Other regulatory assets, deferred (29) (5) (8) (11) (6)
Other regulatory liabilities, current 16
 5
 3
 5
 3
Other regulatory liabilities, deferred (a)
 7
 2
 2
 2
 2
Total energy-related derivative gains (losses) $(32) $(1) $(16) $(10) $(5)
(a)Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.
For the three and ninesix months ended SeptemberJune 30, 20142015 and 2013,2014, the pre-tax effects of interest rate and foreign currency derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for all registrants. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on the statements of income were offset by changes to the carrying value of long-term debt and the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on the statements of income were offset by changes in the fair value of the purchase commitment related to equipment purchases.
For the three and nine months ended September 30, 2014 and 2013, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.
For the three and six months ended June 30, 2015 and 2014, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.
For the three and six months ended June 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
For the three and ninesix months ended SeptemberJune 30, 20142015 and 2013,2014, the pre-tax effects of energy-related and foreign currency derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.
For Southern Power's energy-related derivatives not designated as hedging instruments a portion of the pre-tax realized and unrealized gains and losses was associated with hedging fuel price risk of certain PPA customers and had no impact on net income or on fuel expense as presented in Southern Company's and Southern Power's statements of incomewere immaterial for the three and nine months ended September 30, 2014 and 2013. This third party hedging activity has been discontinued.all registrants.
Contingent Features
The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At SeptemberJune 30, 2014,2015, the registrants' collateral posted with their derivative counterparties was immaterial.
At SeptemberJune 30, 2014,2015, the fair value of derivative liabilities with contingent features was $26$49 million for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $26$49 million and include certain agreements that could require collateral in the event that one or more Southern Company 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. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have

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(UNAUDITED)

investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
(I)ACQUISITIONS
Adobe Solar, LLC
See Note 2 to the financial statements of Southern Power under "Adobe Solar,"2014 – SG2 Imperial Valley, LLC" in Item 8 of the Form 10-K for additional information.
On April 17, 2014, Southern Power and TRE, through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, acquired all of During the outstanding membership interests of Adobe from Sun Edison, LLC,second quarter 2015, the original developer of the project. Adobe constructed and owns an approximately 20-MW solar photovoltaic facility in Kern County, California. The solar facility began commercial operation on May 21, 2014 and the entire output of the plant is contracted under a 20-year PPA with Southern California Edison Company. The acquisition was in accordance with Southern Power's overall growth strategy.
Southern Power's acquisition of Adobe included cash consideration of approximately $96.2 million. The fair values of the assets liabilities,acquired of SG2 Imperial Valley, LLC were finalized and intangibles acquired were recorded as follows: $83.5$707 million toas property, plant, and equipment $14.5and $20 million to receivablesas prepayments related to reimbursable transmission costs and $6.3 millionservices.
During 2015, Southern Power Company acquired or contracted to PPA intangible, resultingacquire the following projects in a $5.1 million bargain purchase gainaccordance with a $2.9 million deferred tax liability. The bargain purchase gain is included in other income (expense), net in Southern Company's and Southern Power's Condensed Consolidated Statements of Income herein.its overall growth strategy. Acquisition-related costs were expensed as incurred and were not material.
Macho Springs Solar, LLCKay County Wind Facility
On May 22, 2014,February 24, 2015, Southern Power and TRE,Company, through STR, acquiredits wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Macho Springs from First Solar Development, Kay Wind, LLC the original developer of the project. Macho Springs constructed(Kay Wind) for approximately $492 million, with potential purchase price adjustments based on performance testing. Kay Wind is constructing and owns an approximately 50-MW solar photovoltaic299-MW wind facility in LunaKay County, New Mexico.Oklahoma. The solarwind facility beganis expected to begin commercial operation on May 23, 2014in late 2015, and the entire output of the plantfacility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time.
Lost Hills-Blackwell Solar Facilities
On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a 20-year PPAwholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with El Paso respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company,. The acquisition was in accordance with Southern Power's overall growth strategy.
Southern Power's acquisition of Macho Springs included cash consideration of that together extend approximately $130.0 million.29 years. As of SeptemberJune 30, 2014,2015, the fair valuevalues of the assets acquired waswere recorded primarilyas follows: $98 million as property, plant, and equipment;equipment and $9 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material.
SG2 Imperial Valley, LLCNorth Star Solar Facility
Subsequent to SeptemberOn April 30, 2014,2015, Southern Power Company, through its wholly-owned subsidiary SG2 Holdings, LLC (Holdings),SRP, acquired all100% of the outstandingclass A membership interests of SG2 Imperial Valley,NS Solar Holdings, LLC (SG2)(North Star) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project. SG2project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is constructing anentitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately 150-MW61-MW North Star solar photovoltaic facility in Southern California (Imperial Facility), which is expected to beginFresno County, California. The solar facility began commercial operation later inon June 20, 2015, and the fourth quarter 2014. The Imperial Facility'sentire output of the project is contracted under a 25-year20-year PPA with San DiegoPacific Gas &and Electric Company, a subsidiaryCompany. As of Sempra Energy. This PPA will be accounted forJune 30, 2015, the fair values of the assets acquired were recorded as follows: $266 million as property, plant, and equipment, $24 million as an operating lease.intangible asset, and $21 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration.
Construction Projects
In December 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of the Imperial Facility alignsfive separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy.
In connection withstrategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this acquisition, Holdings made an aggregate payment (consisting of cash consideration and a secured promissory note) of approximately $128 million to the subsidiary of First Solar and became obligated to pay the contract price as it becomes due under the construction contract for the Imperial Facility. The allocation oftime.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

the purchase price to individual assets has not been finalized. In addition, subject to certain terms and conditions, a subsidiary of First Solar will be admitted as a minority member of Holdings, and as the members of Holdings will make additional agreed upon capital contributions to Holdings that will be used to pay off the previously issued secured promissory note and to fund the Imperial Facility's construction costs. As a result of these capital contributions, the aggregate purchase price payable by Southern Power forCompany's construction projects are detailed in the table below:
Solar ProjectSellerNameplate CapacityCounty Location in GeorgiaExpected Commercial Operation DatePPA Counterparty for Entire Plant OutputPPA Contract PeriodEstimated Construction Cost 
  (MW)    (in millions) 
Taylor CountyN/A146TaylorFourth quarter 2016Cobb, Flint, and Sawnee Electric Membership Corporations25 years$260
-$280 
Decatur ParkwayTradeWind Energy, Inc.84DecaturDecember 2015
Georgia Power(a)
25 years$170
-$173(b)
Decatur CountyTradeWind Energy, Inc.20DecaturDecember 2015
Georgia Power(a)
20 years$45
-$47(b)
ButlerCERSM, LLC and Community Energy, Inc.103TaylorDecember 2016
Georgia Power(a)
30 years$220
-$230(b)
PawpawLongview Solar, LLC30TaylorDecember 2015
Georgia Power(a)
30 years$70
-$80(b)
Butler Solar FarmStrata Solar Development, LLC20TaylorDecember 2015
Georgia Power(a)
20 years$42
-$48(b)
(a) Subject to FERC approval.
(b) Includes the acquisition is approximately $508 million. Following these capital contributions, Southern Power will indirectly own 100% of the class A membership interests of Holdings and be entitled to 51%price of all cash distributions from Holdings, and First Solar will indirectly own 100% of the class Boutstanding membership interests of Holdings and be entitled to 49% of all cash distributions from Holdings. In addition, Southern Power will be entitled to substantially all of the federal tax benefits with respect to this transaction.
If the Imperial Facility does not achieve substantialcompletion by a certain date, Southern Power may require that First Solar make a rescission payment to Southern Power in an amount equal to Southern Power's investment in Holdings, and Southern Power would be required to transfer its ownership interests in SG2 back to First Solar (the Rescission Payment and Transfer).
The ultimate outcome of this matter cannot be determined at this time; however, Holdings believes the likelihood of the Rescission Payment and Transfer to be remote at the acquisition date.interests.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(J) SEGMENT AND RELATED INFORMATION
The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.
Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $103$85 million and $243$199 million for the three and ninesix months ended SeptemberJune 30, 2014,2015, respectively, and $97$68 million and $264$140 million for the three and ninesix months ended SeptemberJune 30, 2013,2014, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the three and ninesix months ended SeptemberJune 30, 20142015 and 20132014 was as follows:
Electric Utilities      Electric Utilities      
Traditional
Operating
Companies
 
Southern
Power
 Eliminations Total 
All
Other
 Eliminations Consolidated
Traditional
Operating
Companies
 
Southern
Power
 Eliminations Total 
All
Other
 Eliminations Consolidated
(in millions)(in millions)
Three Months Ended September 30, 2014:             
Three Months Ended June 30, 2015:             
Operating revenues$5,007
 $435
 $(115) $5,327
 $34
 $(22) $5,339
$4,077
 $337
 $(90) $4,324
 $43
 $(30) $4,337
Segment net income (loss)(a)(b)
658
 64
 
 722
 (2) (2) 718
561
 46
 
 607
 18
 4
 629
Nine Months Ended September 30, 2014:             
Six Months Ended June 30, 2015:             
Operating revenues$13,594
 $1,115
 $(301) $14,408
 $114
 $(72) $14,450
$8,025
 $684
 $(213) $8,496
 $83
 $(59) $8,520
Segment net income (loss)(a)(c)
1,557
 128
 
 1,685
 
 (5) 1,680
1,038
 79
 
 1,117
 21
 
 1,138
Total assets at September 30, 2014$62,419
 $4,609
 $(166) $66,862
 $1,304
 $(512) $67,654
Three Months Ended September 30, 2013:             
Total assets at June 30, 2015$67,362
 $6,226
 $(277) $73,311
 $1,360
 $(490) $74,181
Three Months Ended June 30, 2014:             
Operating revenues$4,744
 $365
 $(104) $5,005
 $35
 $(23) $5,017
$4,209
 $329
 $(84) $4,454
 $39
 $(26) $4,467
Segment net income (loss)(b)(a)
765
 85
 
 850
 (1) 3
 852
580
 31
 
 611
 2
 (2) 611
Nine Months Ended September 30, 2013:             
Six Months Ended June 30, 2014:             
Operating revenues$12,430
 $975
 $(285) $13,120
 $108
 $(68) $13,160
$8,587
 $680
 $(186) $9,081
 $80
 $(50) $9,111
Segment net income (loss)(a)(c)
1,099
 142
 
 1,241
 (12) 1
 1,230
899
 64
 
 963
 2
 (3) 962
Total assets at December 31, 2013$59,447
 $4,429
 $(101) $63,775
 $1,077
 $(306) $64,546
Total assets at December 31, 2014$64,644
 $5,550
 $(131) $70,063
 $1,156
 $(296) $70,923
(a) After dividends on preferred and preference stock of subsidiaries.
(b) Segment net income (loss) for the traditional operating companies for the three months ended SeptemberJune 30, 2014 and September 30, 20132015 includes a $418.0$23 million pre-tax charge ($258.114 million after tax) and a $150.0 million pre-tax charge ($92.6 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.
(c) Segment net income (loss) for the traditional operating companies for the ninesix months ended SeptemberJune 30, 2015 and June 30, 2014 and September 30, 2013 includes $798.0a $32 million in pre-tax chargescharge ($492.820 million after tax) and $1.14 billion ina $380 million pre-tax chargescharge ($704.0235 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

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(UNAUDITED)

Products and Services
  Electric Utilities' Revenues
Period Retail Wholesale Other Total
  (in millions)
Three Months Ended September 30, 2014 $4,558
 $600
 $169
 $5,327
Three Months Ended September 30, 2013 4,319
 520
 166
 5,005
         
Nine Months Ended September 30, 2014 $12,186
 $1,719
 $503
 $14,408
Nine Months Ended September 30, 2013 11,237
 1,406
 477
 13,120
  Electric Utilities' Revenues
Period Retail Wholesale Other Total
  (in millions)
Three Months Ended June 30, 2015 $3,714
 $448
 $162
 $4,324
Three Months Ended June 30, 2014 3,770
 515
 169
 4,454
         
Six Months Ended June 30, 2015 $7,256
 $915
 $325
 $8,496
Six Months Ended June 30, 2014 7,628
 1,119
 334
 9,081

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PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.
Item 1A. Risk Factors.
See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
Item 6.    Exhibits.2. Unregistered Sales of Equity Securities and Use of Proceeds
(c) Issuer Purchases of Equity Securities
2015
Total Number of
Shares
Purchased (*)
Average Price
Paid Per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or
Programs (*)
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (*)
April 1 – April 30
N/AN/AN/A
May 1 – May 31
N/AN/AN/A
June 1 – June 30
N/AN/AN/A
Total
N/AN/A17,400,634
(*)On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. There were no repurchases under this program in the second quarter 2015. As of June 30, 2015, Southern Company had repurchased a total of 2,599,366 shares under this program.

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Item 6.    Exhibits.
The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.
(3) Articles of Incorporation and By-Laws
(a)1-By-laws of Southern Company as amended effective May 27, 2015, and as presently in effect. (Designated in Form 8-K dated May 27, 2015, File No. 1-3526, as Exhibit 3.1.)
 (4) Instruments Describing Rights of Security Holders, Including Indentures
    
 Southern Company
    
 (a)1-NinthEleventh Supplemental Indenture to the Senior Note Indenture dated as of August 22, 2014,June 12, 2015, providing for the issuance of the Series 2014A 1.30%2015A 2.750% Senior Notes due AugustJune 15, 2017.2020. (Designated in Form 8-K dated August 19, 2014,June 9, 2015, File No. 1-3526, as Exhibit 4.2(a).4.2.)
    
 (a)2Southern Power
(f)1-TenthSixth Supplemental Indenture to the Senior Note Indenture dated as of August 22, 2014,May 20, 2015, providing for the issuance of the Series 2014B 2.15%2015A 1.500% Senior Notes due SeptemberJune 1, 2019.2018. (Designated in Form 8-K dated August 19, 2014,May 14, 2015, File No. 1-3526,333-98553, as Exhibit 4.2(b)4.4(a).)
    
(f)2-Seventh Supplemental Indenture to Senior Note Indenture dated as of May 20, 2015, providing for the issuance of the Series 2015B 2.375% Senior Notes due June 1, 2020. (Designated in Form 8-K dated May 14, 2015, File No. 333-98553, as Exhibit 4.4(b).)
(10) Material Contracts
Southern Company
#(a)1-Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)
#*(a)2-First Amendment to the Deferred Compensation Plan for Outside Directors of The Southern Company, effective April 1, 2015.
 Alabama Power
    
#*(b)1-Fifty-Second Supplemental IndentureFirst Amendment to the Senior Note Indenture dated asDeferred Compensation Plan for Outside Directors of August 26, 2014, providingAlabama Power Company, effective June 1, 2015.
#(b)2-Outside Directors Stock Plan for the issuance of the Series 2014A 4.150% Senior Notes due August 15, 2044.The Southern Company and its Subsidiaries. (Designated in Form 8-K dated August 20, 2014,Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3164,1-3526, as Exhibit 4.6.Appendix A.)
    
Georgia Power
*(c)1-Amendment No. 1 to Loan Guarantee Agreement between Georgia Power and the DOE, dated as of June 4, 2015.
#(c)2-Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)
 Gulf Power
    

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#*(d)1-Twenty-First Supplemental IndentureFirst Amendment to the Senior Note Indenture dated asDeferred Compensation Plan for Outside Directors of September 23, 2014, providingGulf Power Company, effective April 1, 2015.
#(d)2-Outside Directors Stock Plan for the issuance of the Series 2014A 4.55% Senior Notes due October 1, 2044.The Southern Company and its Subsidiaries. (Designated in Form 8-K dated September 16, 2014,Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 001-31737,1-3526, as Exhibit 4.2.Appendix A.)
    
Mississippi Power
#*(e)1-First Amendment to the Deferred Compensation Plan for Outside Directors of Mississippi Power Company, effective April 1, 2015.
#(e)2-Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)
 (24) Power of Attorney and Resolutions
    
 Southern Company
    
 (a)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013,2014, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference..)
    
 Alabama Power
    
 (b)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013,2014, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference..)
    
 (b)2-Power of Attorney for Mark A. Crosswhite. (Designated in the Form 10-Q for the quarter ended March 31, 2014, File No. 1-3164 as Exhibit 24(b)2 and incorporated herein by reference.)
 Georgia Power
    
 (c)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013,2014, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference..)
    

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 Gulf Power
    
 (d)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013,2014, File No. 001-31737 as Exhibit 24(d)(1) and incorporated herein by reference..)
    
*(d)2-Power of Attorney for Xia Liu.
 Mississippi Power
    
 (e)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013,2014, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference..)
    
 Southern Power
    
 (f)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013,2014, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference..)
    
 (31) Section 302 Certifications
    
 Southern Company
    
 *(a)1-Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(a)2-Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Alabama Power
    
 *(b)1-Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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 *(b)2-Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Georgia Power
    
 *(c)1-Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(c)2-Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Gulf Power
    
 *(d)1-Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(d)2-Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Mississippi Power
    
 *(e)1-Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(e)2-Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Southern Power
    
 *(f)1-Certificate of Southern Power'sPower Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(f)2-Certificate of Southern Power'sPower Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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

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 Southern Power
    
 *(f)-Certificate of Southern Power'sPower Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
    
 (101) XBRL Related Documents
    
 *INS-XBRL Instance Document
 *SCH-XBRL Taxonomy Extension Schema Document
 *CAL-XBRL Taxonomy Calculation Linkbase Document
 *DEF-XBRL Definition Linkbase Document
 *LAB-XBRL Taxonomy Label Linkbase Document
 *PRE-XBRL Taxonomy Presentation Linkbase Document

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THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  THE SOUTHERN COMPANY
    
By Thomas A. Fanning
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Art P. Beattie
  Executive Vice President and Chief Financial Officer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: November 6, 2014August 5, 2015

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ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  ALABAMA POWER COMPANY
    
By Mark A. Crosswhite 
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Philip C. Raymond
  Executive Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: November 6, 2014August 5, 2015

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GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  GEORGIA POWER COMPANY
    
By W. Paul Bowers
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By W. Ron Hinson
  Executive Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: November 6, 2014August 5, 2015

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GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  GULF POWER COMPANY
    
By S. W. Connally, Jr.
  President and Chief Executive Officer
  (Principal Executive Officer)
    
By Richard S. TeelXia Liu
  Vice President and Chief Financial Officer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: November 6, 2014August 5, 2015

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MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  MISSISSIPPI POWER COMPANY
    
By G. Edison Holland, Jr.
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Moses H. Feagin
  Vice President, Treasurer, and Chief Financial Officer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: November 6, 2014August 5, 2015

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SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  SOUTHERN POWER COMPANY
    
By Oscar C. Harper IV
  President and Chief Executive Officer
  (Principal Executive Officer)
    
By William C. Grantham
  Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: November 6, 2014August 5, 2015

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