Table of Contents


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
 
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 20152016
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 March 31, 20152016
The Southern Company Par Value $5 Per Share 908,261,371918,258,425
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 5,642,717
Mississippi Power Company Without Par Value 1,121,000
Southern Power Company Par Value $0.01 Per Share 1,000
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q
March 31, 20152016


  
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
March 31, 20152016


  
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.
 


4

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DEFINITIONS
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 in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
AFUDCAllowance for funds used during construction
AGL ResourcesAGL Resources Inc.
Alabama PowerAlabama Power Company
ASCAccounting Standards Codification
ASUAccounting Standards Update
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
Bridge AgreementSenior unsecured Bridge Credit Agreement, dated as of September 30, 2015, among Southern Company, the lenders identified therein, and Citibank, N.A.
CCRCoal 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
CODCommercial operation date
ContractorWestinghouse and its affiliate, WECTEC Global Project Services Inc. (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.
CPCNCertificate of public convenience and necessity
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
FASBFinancial Accounting Standards Board
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, 20142015
GAAPGenerallyU.S. generally accepted accounting principles
Georgia PowerGeorgia Power Company
Gulf PowerGulf Power Company
IGCCIntegrated coal gasification combined cycle
IICIntercompany interchange contract
Internal Revenue CodeInternal Revenue Code of 1986, as amended
IRSInternal Revenue Service
ITCInvestment tax credit
Kemper IGCCIGCC facility under construction by Mississippi Power in Kemper County, Mississippi
KWHKilowatt-hour
LIBORLondon Interbank Offered Rate
MATS ruleMercury and Air Toxics Standards rule
MergerThe merger of Merger Sub with and into AGL Resources on the terms and subject to the conditions set forth in the Merger Agreement, with AGL Resources continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company

5



DEFINITIONS
(continued)
TermMeaning
Merger AgreementAgreement and Plan of Merger, dated as of August 23, 2015, among Southern Company, AGL Resources, and Merger Sub
Merger SubAMS Corp., a wholly-owned, direct subsidiary of Southern Company
Mirror CWIPA regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers
Mississippi PowerMississippi Power Company
mmBtuMillion British thermal units
Moody'sMoody's Investors Service, Inc.
MWMegawatt

5



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 Georgia Power's Plant Vogtle
power poolThe operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power Company (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPAPower purchase agreement
PSCPublic Service Commission
PTCProduction tax credit
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
Rate RSEAlabama Power's Rate Stabilization and Equalization plan
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
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


6



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 proposed securitization, Mississippi PSC approval of a rate recovery plan, including 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 2015, and satisfaction of requirements to utilize ITCs and grants;
Mississippi PSC review of the prudence of Kemper IGCC costs;



7



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, the potential financing of the Merger, the expected timing of the completion of the Merger, the strategic goals for the wholesale business, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates of acquisitions and construction projects, filings with state and federal regulatory authorities, federal income tax benefits, 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 regulating emissions, discharges, and disposal to air, water, and land, 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, without limitation, 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, operating, 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;
actions related to cost recovery for the Kemper IGCC, including the ultimate outcome and impact of the February 2015 decision of the Mississippi Supreme Court, the Mississippi Power's request for rehearing of such decision,PSC's December 2015 rate order, and any furtherrelated legal or regulatory proceedings, regarding any settlement agreement between Mississippi PowerPSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the Mississippi PSC,ultimate impact of the March 2013 rate order regarding retail rate increases, ortermination of the Baseload Act;proposed sale of an interest in the Kemper IGCC to SMEPA;



7



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and the successful performance of 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 expected timing, likelihood, and benefits of completion of the Merger, including the failure to receive, on a timely basis or otherwise, the required approvals by government or regulatory agencies (including the terms of such approvals), the possibility that long-term financing for the Merger may not be put in place prior to the closing, the risk that a condition to closing of the Merger or funding of the Bridge Agreement may not be satisfied, the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and AGL Resources will be greater than expected, the credit ratings of the combined company or its subsidiaries may be different from what the parties expect, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, the diversion of management time on Merger-related issues, and the impact of legislative, regulatory, and competitive changes;
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;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any 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 (or sell excess 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-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.


8



THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

9



THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Operating Revenues:      
Retail revenues$3,542
 $3,858
$3,377
 $3,542
Wholesale revenues467
 604
396
 467
Other electric revenues163
 165
181
 163
Other revenues11
 17
11
 11
Total operating revenues4,183
 4,644
3,965
 4,183
Operating Expenses:      
Fuel1,212
 1,647
911
 1,212
Purchased power144
 187
165
 144
Other operations and maintenance1,122
 986
1,106
 1,122
Depreciation and amortization487
 497
541
 487
Taxes other than income taxes252
 247
256
 252
Estimated loss on Kemper IGCC9
 380
53
 9
Total operating expenses3,226
 3,944
3,032
 3,226
Operating Income957
 700
933
 957
Other Income and (Expense):      
Allowance for equity funds used during construction63
 57
53
 63
Interest expense, net of amounts capitalized(213) (206)(246) (213)
Other income (expense), net(8) (7)(21) (8)
Total other income and (expense)(158) (156)(214) (158)
Earnings Before Income Taxes799
 544
719
 799
Income taxes274
 176
222
 274
Consolidated Net Income525
 368
497
 525
Less:   
Dividends on Preferred and Preference Stock of Subsidiaries17
 17
11
 17
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries$508
 $351
Net income attributable to noncontrolling interests1
 
Consolidated Net Income Attributable to Southern Company$485
 $508
Common Stock Data:      
Earnings per share (EPS) —      
Basic EPS$0.56
 $0.39
$0.53
 $0.56
Diluted EPS$0.56
 $0.39
$0.53
 $0.56
Average number of shares of common stock outstanding (in millions)      
Basic910
 890
916
 910
Diluted915
 893
922
 915
Cash dividends paid per share of common stock$0.5250
 $0.5075
$0.5425
 $0.5250
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.


10

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Consolidated Net Income$525
 $368
$497
 $525
Other comprehensive income (loss):      
Qualifying hedges:      
Changes in fair value, net of tax of $(11) and $-, respectively(18) 
Changes in fair value, net of tax of $(72) and $(11), respectively(117) (18)
Reclassification adjustment for amounts included in net income,
net of tax of $1 and $1, respectively
1
 1
2
 1
Pension and other post retirement benefit plans:      
Reclassification adjustment for amounts included in net income,
net of tax of $1 and $-, respectively
2
 1
Reclassification adjustment for amounts included in net income,
net of tax of $1 and $1, respectively
1
 2
Total other comprehensive income (loss)(15) 2
(114) (15)
Less:   
Dividends on preferred and preference stock of subsidiaries(17) (17)11
 17
Comprehensive Income$493
 $353
Comprehensive income attributable to noncontrolling interests1
 
Consolidated Comprehensive Income Attributable to Southern Company$371
 $493
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.


11

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Three Months
Ended March 31,
 2015 2014
 (in millions)
Operating Activities:   
Consolidated net income$525
 $368
Adjustments to reconcile consolidated net income to net cash provided from operating activities —   
Depreciation and amortization, total578
 587
Deferred income taxes113
 (37)
Allowance for equity funds used during construction(63) (57)
Stock based compensation expense56
 28
Estimated loss on Kemper IGCC9
 380
Other, net4
 (42)
Changes in certain current assets and liabilities —   
-Receivables180
 (128)
-Fossil fuel stock76
 441
-Materials and supplies4
 (5)
-Other current assets(89) (114)
-Accounts payable(426) (109)
-Accrued taxes197
 (44)
-Accrued compensation(381) (144)
-Mirror CWIP40
 34
-Other current liabilities90
 (55)
Net cash provided from operating activities913
 1,103
Investing Activities:   
Property additions(1,097) (1,180)
Distribution of restricted cash
 9
Nuclear decommissioning trust fund purchases(290) (231)
Nuclear decommissioning trust fund sales284
 229
Cost of removal, net of salvage(36) (22)
Change in construction payables, net65
 51
Prepaid long-term service agreement(37) (64)
Other investing activities4
 (7)
Net cash used for investing activities(1,107) (1,215)
Financing Activities:   
Increase (decrease) in notes payable, net597
 (884)
Proceeds —   
Long-term debt issuances550
 1,251
Interest-bearing refundable deposit
 75
Common stock issuances112
 128
Short-term borrowings280
 
Redemptions —   
Long-term debt(333) (9)
Common stock repurchased(115) (4)
Payment of common stock dividends(478) (451)
Payment of dividends on preferred and preference stock of subsidiaries(17) (17)
Other financing activities
 (46)
Net cash provided from financing activities596
 43
Net Change in Cash and Cash Equivalents402
 (69)
Cash and Cash Equivalents at Beginning of Period710
 659
Cash and Cash Equivalents at End of Period$1,112
 $590
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $32 and $22 capitalized for 2015 and 2014, respectively)$207
 $186
Income taxes, net(289) (7)
Noncash transactions — Accrued property additions at end of period347
 450
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.

12

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets At March 31,
2015
 At December 31,
2014
  (in millions)
Current Assets:    
Cash and cash equivalents $1,112
 $710
Receivables —    
Customer accounts receivable 1,117
 1,090
Unbilled revenues 374
 432
Under recovered regulatory clause revenues 159
 136
Other accounts and notes receivable 241
 307
Accumulated provision for uncollectible accounts (19) (18)
Fossil fuel stock, at average cost 855
 930
Materials and supplies, at average cost 1,050
 1,039
Vacation pay 178
 177
Prepaid expenses 299
 665
Deferred income taxes, current 578
 506
Other regulatory assets, current 363
 346
Other current assets 65
 50
Total current assets 6,372
 6,370
Property, Plant, and Equipment:    
In service 70,279
 70,013
Less accumulated depreciation 24,307
 24,059
Plant in service, net of depreciation 45,972
 45,954
Other utility plant, net 275
 211
Nuclear fuel, at amortized cost 914
 911
Construction work in progress 8,314
 7,792
Total property, plant, and equipment 55,475
 54,868
Other Property and Investments:    
Nuclear decommissioning trusts, at fair value 1,574
 1,546
Leveraged leases 749
 743
Miscellaneous property and investments 204
 203
Total other property and investments 2,527
 2,492
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 1,527
 1,510
Unamortized debt issuance expense 200
 202
Unamortized loss on reacquired debt 239
 243
Other regulatory assets, deferred 4,462
 4,334
Other deferred charges and assets 808
 904
Total deferred charges and other assets 7,236
 7,193
Total Assets $71,610
 $70,923
 For the Three Months
Ended March 31,
 2016 2015
 (in millions)
Operating Activities:   
Consolidated net income$497
 $525
Adjustments to reconcile consolidated net income to net cash provided from operating activities —   
Depreciation and amortization, total639
 578
Deferred income taxes(4) 113
Allowance for equity funds used during construction(53) (63)
Stock based compensation expense58
 56
Estimated loss on Kemper IGCC53
 9
Other, net(13) 4
Changes in certain current assets and liabilities —   
-Receivables235
 180
-Fossil fuel stock31
 76
-Materials and supplies(14) 4
-Other current assets(90) (89)
-Accounts payable(72) (426)
-Accrued taxes(60) 197
-Accrued compensation(332) (381)
-Retail fuel cost over recovery - short-term25
 49
-Mirror CWIP
 40
-Other current liabilities(35) 41
Net cash provided from operating activities865
 913
Investing Activities:   
Plant acquisitions(114) (6)
Property additions(1,872) (1,091)
Investment in restricted cash(289) 
Distribution of restricted cash292
 
Nuclear decommissioning trust fund purchases(316) (290)
Nuclear decommissioning trust fund sales311
 284
Cost of removal, net of salvage(52) (36)
Change in construction payables, net(94) 65
Prepaid long-term service agreement(49) (37)
Other investing activities(14) 4
Net cash used for investing activities(2,197) (1,107)
Financing Activities:   
Increase in notes payable, net294
 597
Proceeds —   
Long-term debt issuances1,997
 550
Common stock issuances270
 112
Short-term borrowings
 280
Redemptions and repurchases —   
Long-term debt(888) (333)
Common stock repurchased
 (115)
Short-term borrowings(475) 
Distributions to noncontrolling interests(4) 
Capital contributions from noncontrolling interests131
 
Purchase of membership interests from noncontrolling interests(129) 
Payment of common stock dividends(497) (478)
Other financing activities(17) (17)
Net cash provided from financing activities682
 596
Net Change in Cash and Cash Equivalents(650) 402
Cash and Cash Equivalents at Beginning of Period1,404
 710
Cash and Cash Equivalents at End of Period$754
 $1,112
Supplemental Cash Flow Information:   
Cash paid (received) during the period for --   
Interest (net of $30 and $32 capitalized for 2016 and 2015, respectively)$224
 $207
Income taxes, net(141) (289)
Noncash transactions — Accrued property additions at end of period731
 347
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholders' Equity At March 31,
2015
 At December 31,
2014
  (in millions)
Current Liabilities:    
Securities due within one year $3,306
 $3,333
Interest-bearing refundable deposit 275
 275
Notes payable 1,679
 803
Accounts payable 1,289
 1,593
Customer deposits 395
 390
Accrued taxes —    
Accrued income taxes 198
 151
Other accrued taxes 248
 487
Accrued interest 286
 295
Accrued vacation pay 222
 223
Accrued compensation 186
 576
Mirror CWIP 311
 271
Other current liabilities 790
 570
Total current liabilities 9,185
 8,967
Long-term Debt 21,093
 20,841
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 11,706
 11,568
Deferred credits related to income taxes 185
 192
Accumulated deferred investment tax credits 1,198
 1,208
Employee benefit obligations 2,416
 2,432
Asset retirement obligations 2,151
 2,168
Other cost of removal obligations 1,209
 1,215
Other regulatory liabilities, deferred 439
 398
Other deferred credits and liabilities 619
 594
Total deferred credits and other liabilities 19,923
 19,775
Total Liabilities 50,201
 49,583
Redeemable Preferred Stock of Subsidiaries 375
 375
Redeemable Noncontrolling Interest 40
 39
Stockholders' Equity:    
Common Stockholders' Equity:    
Common stock, par value $5 per share —    
Authorized — 1.5 billion shares    
Issued — March 31, 2015: 912 million shares    
  — December 31, 2014: 909 million shares    
Treasury — March 31, 2015: 3.3 million shares    
 — December 31, 2014: 0.7 million shares    
Par value 4,555
 4,539
Paid-in capital 6,108
 5,955
Treasury, at cost (142) (26)
Retained earnings 9,639
 9,609
Accumulated other comprehensive loss (143) (128)
Total Common Stockholders' Equity 20,017
 19,949
Preferred and Preference Stock of Subsidiaries 756
 756
Noncontrolling Interest 221
 221
Total Stockholders' Equity 20,994
 20,926
Total Liabilities and Stockholders' Equity $71,610
 $70,923
Assets At March 31,
2016
 At December 31,
2015
  (in millions)
Current Assets:    
Cash and cash equivalents $754
 $1,404
Receivables —    
Customer accounts receivable 988
 1,058
Unbilled revenues 380
 397
Under recovered regulatory clause revenues 43
 63
Income taxes receivable, current 
 144
Other accounts and notes receivable 236
 398
Accumulated provision for uncollectible accounts (13) (13)
Fossil fuel stock, at average cost 837
 868
Materials and supplies, at average cost 1,085
 1,061
Vacation pay 181
 178
Prepaid expenses 486
 495
Other regulatory assets, current 394
 402
Other current assets 90
 71
Total current assets 5,461
 6,526
Property, Plant, and Equipment:    
In service 76,553
 75,118
Less accumulated depreciation 24,566
 24,253
Plant in service, net of depreciation 51,987
 50,865
Other utility plant, net 218
 233
Nuclear fuel, at amortized cost 941
 934
Construction work in progress 9,406
 9,082
Total property, plant, and equipment 62,552
 61,114
Other Property and Investments:    
Nuclear decommissioning trusts, at fair value 1,540
 1,512
Leveraged leases 761
 755
Miscellaneous property and investments 488
 485
Total other property and investments 2,789
 2,752
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 1,572
 1,560
Unamortized loss on reacquired debt 220
 227
Other regulatory assets, deferred 4,957
 4,989
Income taxes receivable, non-current 413
 413
Other deferred charges and assets 771
 737
Total deferred charges and other assets 7,933
 7,926
Total Assets $78,735
 $78,318
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders' Equity At March 31,
2016
 At December 31,
2015
  (in millions)
Current Liabilities:    
Securities due within one year $2,392
 $2,674
Notes payable 1,195
 1,376
Accounts payable 1,584
 1,905
Customer deposits 406
 404
Accrued taxes —    
Accrued income taxes 14
 19
Other accrued taxes 240
 484
Accrued interest 255
 249
Accrued vacation pay 228
 228
Accrued compensation 212
 549
Asset retirement obligations, current 237
 217
Liabilities from risk management activities 319
 156
Other regulatory liabilities, current 210
 278
Other current liabilities 564
 590
Total current liabilities 7,856
 9,129
Long-term Debt 26,091
 24,688
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 12,274
 12,322
Deferred credits related to income taxes 185
 187
Accumulated deferred investment tax credits 1,350
 1,219
Employee benefit obligations 2,546
 2,582
Asset retirement obligations, deferred 3,504
 3,542
Unrecognized tax benefits 375
 370
Other cost of removal obligations 1,151
 1,162
Other regulatory liabilities, deferred 303
 254
Other deferred credits and liabilities 754
 720
Total deferred credits and other liabilities 22,442
 22,358
Total Liabilities 56,389
 56,175
Redeemable Preferred Stock of Subsidiaries 118
 118
Redeemable Noncontrolling Interests 44
 43
Stockholders' Equity:    
Common Stockholders' Equity:    
Common stock, par value $5 per share —    
Authorized — 1.5 billion shares    
Issued -- March 31, 2016: 922 million shares    
-- December 31, 2015: 915 million shares    
Treasury -- March 31, 2016: 3.4 million shares    
    -- December 31, 2015: 3.4 million shares    
Par value 4,604
 4,572
Paid-in capital 6,582
 6,282
Treasury, at cost (144) (142)
Retained earnings 9,999
 10,010
Accumulated other comprehensive loss (244) (130)
Total Common Stockholders' Equity 20,797
 20,592
Preferred and Preference Stock of Subsidiaries 609
 609
Noncontrolling Interests 778
 781
Total Stockholders' Equity 22,184
 21,982
Total Liabilities and Stockholders' Equity $78,735
 $78,318
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.

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

FIRST QUARTER 20152016 vs. FIRST QUARTER 20142015



OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional operating companies 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 Power," and " – Other Businesses" in Item 1 of the Form 10-K.
Proposed Merger with AGL Resources
On August 23, 2015, Southern Company entered into the Merger Agreement to acquire AGL Resources. Under the terms of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned, direct subsidiary of Southern Company.
Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue a minimum of $8.0 billion in debt prior to closing the Merger and a minimum of $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, the proposed acquisition of PowerSecure International, Inc. (PowerSecure), and Southern Power and other Southern Company system capital projects. Total capital raised in 2016 may increase due to cash needed at the closing of the Merger, settlement of hedges, and incremental investment opportunities, including additional Southern Power projects in excess of its current capital plans. In addition, subsidiariesSouthern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available.
Through May 5, 2016, the Maryland PSC, the Georgia PSC, the California Public Utilities Commission, and the Virginia State Corporation Commission have approved the Merger. On April 15, 2016, Southern Company, AGL Resources, and Northern Illinois Gas Company (collectively, the Joint Applicants) and the Retail Energy Supply Association filed a settlement agreement with the Illinois Commerce Commission. On April 28, 2016, the Joint Applicants, the Illinois Attorney General's Office, and the Citizens Utility Board filed a settlement agreement with the Illinois Commerce Commission. Collectively, these agreements resolve all remaining contested issues for Illinois Commerce Commission approval of the Merger. On May 5, 2016, Southern Company, AGL Resources, Merger Sub, Pivotal Utility Holdings, Inc. d/b/a Elizabethtown Gas, the Division of Rate Counsel, the Staff of the New Jersey Board of Public Utilities, and New Jersey Large Energy Users Coalition entered into a comprehensive settlement agreement relating to the New Jersey Board of Public Utilities review of the Merger. Additionally, the Federal Communications Commission (FCC) has approved the transfer of control over the FCC licenses of certain AGL Resources subsidiaries. Consummation of the Merger remains subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the approval of the Illinois Commerce Commission and the New Jersey Board of Public Utilities and other approvals required under applicable state laws, (ii) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement.

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Prior to the Merger, Southern Company and AGL Resources will continue to operate as separate companies. Accordingly, except for specific references to the pending Merger, the descriptions of strategy and outlook and the risks and challenges Southern Company faces, and the discussion and analysis of results of operations and financial condition set forth herein relate solely to Southern Company. See Note (I) to the Condensed Financial Statements under "Southern Company – Proposed Merger with AGL Resources" herein for additional information regarding the Merger.
During the first quarter 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the proposed Merger of approximately $20 million, of which $6 million is included in operating expenses and $14 million is included in other income and (expense).
The ultimate outcome of these matters cannot be determined at this time. See RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Proposed Merger with AGL Resources" of Southern Company are constructingin Item 7 of the Form 10-K for additional information related to the proposed Merger and the various risks related thereto.
Construction Program
Construction continues on Plant Vogtle Units 3 and 4 and the Kemper IGCC.(45.7% ownership interest by Georgia Power has a 45.7% ownership interest in Plant Vogtle Units 3 and 4,the two units, each with approximately 1,100 MWs,MWs) and Mississippi Power is ultimately expected to hold an 85% ownership interest in thePower's 582-MW Kemper 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 under "Southern Power" herein.
Key Performance Indicators
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.
RESULTS OF OPERATIONS
Net Income
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$157 44.7
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(23) (4.5)
Consolidated net income attributable to Southern Company'sCompany was $485 million ($0.53 per share) for the first quarter 2015 net income after dividends on preferred and preference stock of subsidiaries was2016 compared to $508 million ($0.56 per share) compared to $351 million ($0.39 per share) for the first quarter 2014.2015. The increasedecrease was primarily the result of a lower pre-tax charge of $9 million ($6 million after tax) recordedretail revenues due to milder weather in the first quarter 20152016 as compared to a pre-tax chargethe corresponding period in 2015, higher depreciation and amortization, higher charges related to revisions of $380 million ($235 million after tax) recorded in the first quarter 2014 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, as well as an increase in retail base rates.and lower wholesale capacity revenues. The increase in net income wasdecreases were partially offset by increases in revenues due to increases in non-fuel operationsretail rates and maintenance expensessales growth and a decrease in revenues due to milder weather in the first quarter 2015 as comparedincome taxes primarily from income tax benefits at Southern Power.
See Note 3 to the corresponding periodfinancial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in 2014.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.

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

Retail Revenues
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(316) (8.2)
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(165) (4.7)
In the first quarter 2015,2016, retail revenues were $3.5$3.4 billion compared to $3.9$3.5 billion for the corresponding period in 2014.2015.
Details of the changes in retail revenues were as follows:
 
First
 Quarter 2015
 First Quarter 2016
 (in millions) (% change) (in millions) (% change)
Retail – prior year $3,858
   $3,542
  
Estimated change resulting from –        
Rates and pricing 77
 2.0
 110
 3.1
Sales growth 18
 0.5
 22
 0.6
Weather (38) (1.0) (85) (2.4)
Fuel and other cost recovery (373) (9.7) (212) (6.0)
Retail – current year $3,542
 (8.2)% $3,377
 (4.7)%
Revenues associated with changes in rates and pricing increased in the first quarter 20152016 when compared to the corresponding period in 20142015 primarily due to increased revenues at Alabama Power associated with an increase in rates under rate stabilization and equalization (Rate RSE)Rate CNP Compliance and at Georgia Power related to increases in base tariff increases approvedtariffs under 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, all effective January 1, 2015.2016. The increase in rates and pricing was partially offset by lower contributions from market-drivenalso due to the implementation of rates from commercial and industrial customersfor certain Kemper IGCC in-service assets at GeorgiaMississippi Power.
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" and " – Nuclear Construction," and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales increased in the first quarter 2015 as2016 when compared to the corresponding period in 2014. Industrial2015. Weather-adjusted residential KWH sales increased 2.0%1.4% in the first quarter 20152016 due to customer growth and increased customer usage. Weather-adjusted commercial KWH sales increased 0.8% in the first quarter 2016 primarily due to increasedcustomer growth. Industrial KWH sales decreased 1.0% in the first quarter 2016 primarily due to decreased sales in the paper,chemicals, primary metals, non-manufacturing, stone, clay, and glass, transportation, textiles, and pipeline sectors, partially offset by decreasedincreased sales in the primary metalspaper and chemicalsstone, clay, and glass sectors. Weather-adjusted commercial KWH sales increased 0.7%A strong dollar, low oil prices, and weak global growth conditions have constrained growth in the first quarter 2015 primarily due to customer growth. Weather-adjusted residential KWH sales increased 0.2% in the first quarter 2015 as a result of customer growth, partially offset by decreased customer usage.industrial sector.
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 first quarter 20142015 KWH sales among customer classes that is consistent with the actual allocation in 2015.2016. Without this adjustment, first quarter 2015 industrial KWH2016 weather-adjusted residential sales increased 1.9%1.6%, weather-adjusted commercial sales increased 0.3%1.1%, and weather-adjusted residentialindustrial KWH sales decreased 0.1%0.8% as compared to the corresponding period in 2014.2015.
Fuel and other cost recovery revenues decreased $373$212 million in the first quarter 20152016, respectively, when compared to the corresponding period in 20142015 primarily due to a decrease in fuel prices and decreased energy sales as a result of milder weather in the first quarter 2015 as compared to the corresponding period in 2014.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

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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
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(137) (22.7)
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(71) (15.2)
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 and wind 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 first quarter 2015,2016, wholesale revenues were $467$396 million compared to $604$467 million for the corresponding period in 2014 primarily2015 related to a $118$43 million decrease in capacity revenues and a $28 million decrease in energy revenues and a $19 millionrevenues. The decrease in capacity revenues.revenues was primarily due to a PPA remarketing from non-affiliate to affiliate at Southern Power, unit retirements at Georgia Power, milder weather and decreased usage at Mississippi Power, and the expiration of a Plant Scherer Unit 3 power sales agreement at Gulf Power. The decrease in energy revenues was primarily related to decreased demand resulting from milder weather inlower fuel costs.
See FUTURE EARNINGS POTENTIAL – "Other Matters" herein for additional information regarding the expiration of long-term sales agreements at Gulf Power for Plant Scherer Unit 3, which will impact future wholesale earnings.
Other Electric Revenues
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$18 11.0
In the first quarter 2015 as2016, other electric revenues were $181 million compared to $163 million for the corresponding period in 2014 and lower natural gas prices, as well as contract expirations at Southern Power.2015. The decrease in energy revenues was partially offset by new solar PPAs at Southern Power. The decrease in capacity revenuesincrease was primarily a result of the expiration of wholesale contracts in December 2014due to an adjustment for customer temporary facilities service revenues at Georgia Power and contract expirations at Southern Power.
Fuel and Purchased Power Expenses
 First Quarter 2015
vs.
First Quarter 2014
 First Quarter 2016
vs.
First Quarter 2015
 (change in millions) (% change) (change in millions) (% change)
Fuel $(435) (26.4) $(301) (24.8)
Purchased power (43) (23.0) 21
 14.6
Total fuel and purchased power expenses $(478)  $(280) 
In the first quarter 2015,2016, total fuel and purchased power expenses were $1.4$1.1 billion compared to $1.8$1.4 billion for the corresponding period in 2014.2015. The decrease was primarily the result of a $443$223 million decrease in the average cost

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of fuel and purchased power primarily due to lower coalnatural gas and natural gascoal prices and a $35$145 million decrease in the volume of KWHs generated, and purchased primarily due to decreased demand resulting from milder weatherpartially offset by an $88 million increase in the first quarter 2015 as compared to the corresponding period in 2014.volume of KWHs 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 – "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.

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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:
 First Quarter
2015
 First Quarter
2014
 First Quarter
2016
 First Quarter
2015
Total generation (billions of KWHs)
 46 47 44 46
Total purchased power (billions of KWHs)
 3 3 4 3
Sources of generation (percent)
  
Coal 33 47 27 33
Nuclear 16 16 17 16
Gas 47 33 47 47
Hydro 4 4 7 3
Other Renewables 2 1
Cost of fuel, generated (cents per net KWH)
  
Coal 3.70 4.19 3.24 3.70
Nuclear 0.67 0.89 0.82 0.67
Gas 2.71 4.19 2.16 2.71
Average cost of fuel, generated (cents per net KWH)
 2.71 3.63 2.23 2.71
Average cost of purchased power (cents per net KWH)(a)
 7.18 8.89
Average cost of purchased power (cents per net KWH)(*)
 5.27 7.18
(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 first quarter 2015,2016, fuel expense was $1.2 billion$911 million compared to $1.6$1.2 billion for the corresponding period in 2014.2015. The decrease was primarily due to a 25.3% decrease in the average cost of fuel per KWH generated and a 31.0%21.9% decrease in the volume of KWHs generated by coal, partially offset by a 45.5%20.3% decrease in the average cost of natural gas per KWH generated, a 12.4% decrease in the average cost of coal per KWH generated, and an 83.1% increase in the volume of KWHs generated by natural gas.hydro facilities resulting from more rainfall.
Purchased Power
In the first quarter 2015,2016, purchased power expense was $144$165 million compared to $187$144 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 19.2%50.8% increase in the volume of KWHs purchased, partially offset by a 26.6% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices and a 10.2% decrease in the volume of KWHs purchased primarily as a result of decreased demand from milder weather in the first quarter 2015 as compared to the corresponding period in 2014.coal prices.
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.
Other Operations and Maintenance Expenses
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$136 13.8
In the first quarter 2015, other operations and maintenance expenses were $1.1 billion compared to $986 million for the corresponding period in 2014. The increase was primarily due to a $35 million increase in employee compensation and benefits including pension costs, a $28 million increase in scheduled outage and maintenance costs at generation facilities, a $16 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, a $9 million increase in transmission and

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distributionOther Operations and Maintenance Expenses
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(16) (1.4)
In the first quarter 2016, other operations and maintenance expenses were $1.11 billion compared to $1.12 billion for the corresponding period in 2015. The decrease was primarily due to a decrease in scheduled outage and maintenance costs at generation facilities and a decrease in employee compensation and benefits including pension costs.
Depreciation and Amortization
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$54 11.1
In the first quarter 2016, depreciation and amortization was $541 million compared to $487 million for the corresponding period in 2015. The increase was primarily due to a $43 million increase related to overhead line maintenance,additional plant in service at the traditional operating companies and an $8Southern Power. Also contributing to the increase, Gulf Power recorded $14 million increaseless of a reduction in other generation expenses. In addition, Alabama Power deferred approximately $25 million of certain non-nuclear outage expenditures under an accounting orderdepreciation in the first quarter 2014. three months of 2016 compared to the corresponding period in 2015, as authorized by the Florida PSC in a settlement agreement.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – AlabamaGulf Power – Non-Nuclear Outage Accounting Order"Retail Base Rate Case" in Item 8 of the Form 10-K for additional information related to non-nuclear outage expenditures. Also seeand Note (F)(B) to the Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" herein for additional information related to pension costs.
Depreciation and Amortization
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(10) (2.0)
In the first quarter 2015, depreciation and amortization was $487 million compared to $497 million for the corresponding period in 2014. The decrease was primarily due to a $26 million reduction in depreciation rates at Alabama Power and a $13 million reduction in depreciation at Gulf Power, as approved by the Florida PSC, partially offset by an increase of $28 million as a result of additional plant in service at the traditional operating companies and Southern Power.information.
Estimated Loss on Kemper IGCC
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(371) (97.6)
First Quarter 2016 vs. First Quarter 2015
(change in millions)(% change)
$44N/M
N/M – Not meaningful
In the first quarter 20152016 and 2014,2015, estimated probable losses on the Kemper IGCC of $9$53 million and $380$9 million, 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(Initial 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
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$6 10.5
In the first quarter 2015, AFUDC equity was $63 million compared to $57 million for the corresponding period in 2014. The increase was primarily related to $17 million of additional capital expenditures for environmental and transmission projects at the traditional operating companies, partially offset by an $11 million decrease related to placing the combined cycle and the associated common facilities portion of Mississippi Power's Kemper IGCC in service in August 2014. 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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Income TaxesAllowance for Equity Funds Used During Construction
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$98 55.7
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(10) (15.9)
In the first quarter 2015, income taxes were $2742016, AFUDC equity was $53 million compared to $176$63 million for the corresponding period in 2014.2015. The decrease was primarily due to environmental and generation projects placed in service at Alabama Power and Gulf Power.
Interest Expense, Net of Amounts Capitalized
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$33 15.5
In the first quarter 2016, interest expense, net of amounts capitalized was $246 million compared to $213 million in the corresponding period in 2015. The increase was primarily reflectsdue to an increase in outstanding long-term debt, partially offset by a reductiondecrease related to interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015.
See Note (E) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
First Quarter 2016 vs. First Quarter 2015
(change in millions)(% change)
$(13)N/M
N/M – Not meaningful
In the first quarter 2016, other income (expense), net was $(21) million compared to $(8) million for the corresponding period in 2015. The change was primarily due to Bridge Agreement-related expenses associated with the proposed Merger.
See Note (I) to the Condensed Financial Statements under "Southern Company – Proposed Merger with AGL Resources" herein for additional information.
Income Taxes
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(52) (19.0)
In the first quarter 2016, income taxes were $222 million compared to $274 million for the corresponding period in 2015. The decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power and an increase in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recorded in 2014, partially offset by otherwise lower pre-tax earnings in 2015.IGCC.
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 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

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factors include the traditional operating companies' ability to maintain a constructive regulatory environment that continues to allowallows for the timely recovery of prudently-incurred costs during a time of increasing costs and the completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Other major factors include the profitability of theSouthern Power's competitive wholesale business and successfully expandingsuccessful additional investments in renewable and other energy projects. Future earnings for the electricity business in the near term will depend, in part, upon maintaining and growing sales which are 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 regulatory matters, creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, including the impact of ITCs,tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. ChangesDemand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by 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 andwhich may impact future earnings.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, the proposed Merger will result in a combined company that is subject to various risks that do not currently impact Southern Company.
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 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.modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. 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.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations" "Retail Regulatory Matters Alabama Power Environmental Accounting Order," and "Retail Regulatory Matters Georgia Power Integrated Resource Plans"Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule and Note 3regional haze regulations.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the financial statementsEPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all units within the Southern Company under "Other Matterssystem that are subject to

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Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information on planned unit retirements and fuel conversions at Alabama Power, Georgia Power, and Mississippi Power.
Coal Combustion ResidualsMATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
OnAlso on April 17, 2015,25, 2016, the EPA publishedissued proposed revisions to the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule.regional haze regulations. The ultimate impact of the CCR Ruleproposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this timetime.and 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 expects to record incremental asset retirement obligations of approximately $525 million to $575 million related to the CCR Rule in the second quarter 2015.
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 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 has directed the traditional operating companies and Southern Power, within 60 days, 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 are evaluating the order. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Retail Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Retail Regulatory Matters Retail Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate ECR" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding 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.balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
On April 14, 2016, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 15% effective June 1, 2016, which is expected to reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017. The ultimate outcome of this matter cannot be determined at this time.
Renewables
See Note 3 to the financial statementsMANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Retail Regulatory Matters Renewables" of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate ECR" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 87 of the Form 10-K for additional information.information regarding the Southern Company system's renewables activity.
As part of the Georgia Power Advanced Solar Initiative, four PPAs totaling 149 MWs of Georgia Power's solar contracted capacity from Southern Power began in the first quarter 2016.
In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs, two of which were finalized as of December 31, 2015 and one of which was finalized as of March 2, 2016. The projects are expected to be in service by the end of 2016 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism.
The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.
Alabama Power
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 primarily through its Rate RSE, Rate CNP Compliance, 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 Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power" in

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Item 8 of the Form 10-K for additional information regarding Alabama Power's rate 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.

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Rate CNP
In March 2015, the Emerging Issues Task Force unanimously recommended to allow the normal purchases and normal sales exception for physical forward transactions in nodal energy markets. The Financial Accounting Standards Board (FASB) proposed new accounting guidance reflecting the recommendation on April 23, 2015. This guidance is subject to a public comment period before the FASB issues a final accounting standard. The ultimate outcome of this matter cannot be determined at this time.
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. Alabama Power is continuing to evaluate its plans for Plant Barry Unit 3 (225 MWs), which is currently unavailable for generation.
In accordance with an accounting order from the Alabama PSC, Alabama Power will transfer 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.
Rate CNP Compliance(Formerly Known As Rate CNP Environmental)
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.
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 $14 million of non-environmental compliance costs during the first quarter 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 the year.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to the construction of Plant 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 (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's fuel cost recovery and the NCCR tariff, respectively.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) will retain the merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, net merger savings will be shared on a 60/40 basis between customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power" in Item 8 of the Form 10-K for additional information.
Renewables Development
As part ofinformation regarding the Georgia Power Advanced Solar Initiative program, Georgia Power executed ten PPAs that were approved by2013 ARP and Note (I) to the Georgia PSC in 2014 and provideCondensed Financial Statements under "Southern Company – Proposed Merger with AGL Resources" herein for additional information regarding 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

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a result of certain acquisitions by Southern Power, Georgia Power expects that 229 MWs of the 515 MWs will be purchased from solar facilities owned or under development by Southern Power.
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 Unit 7 and is underway at Plant Yates Unit 6. Plant Yates Unit 7 was returned to service on May 4, 2015 and Plant Yates Unit 6 is expected to return to service in mid-2015.
Gulf Power
Renewables
The Florida PSC preliminarily approved on April 16, 2015, three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. These contracts are expected to begin in 2016 with a term of 25 years each. The Florida PSC preliminarily approved on May 5, 2015, an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma. The agreement is expected to begin by the end of 2015 with a term of 20 years. Purchases under these agreements will be for energy only and are expected to be recovered through Gulf Power's fuel cost recovery mechanism. The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
Renewables
Subsequent to March 31, 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, the projects are expected to be in service by the end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of this matter cannot be determined at this time.Merger.
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 approval 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 and the Kemper IGCC.(45.7% ownership interest by Georgia Power has a 45.7% ownership interest in Plant Vogtle Units 3 and 4,the two units, each with approximately 1,100 MWs,MWs) and Mississippi Power is ultimately expected to hold an 85% ownership interest in thePower's 582-MW Kemper IGCC. 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 additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power – Construction Projects" herein.
From 2013 through March 31, 2015,Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company recorded pre-tax charges totaling $2.06 billion ($1.27 billion after tax)Company's capital requirements for revisions of estimated costs expected to be incurred on Mississippi Power'sits subsidiaries' construction programs.

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ofIntegrated Coal Gasification Combined Cycle
Mississippi Power's current cost estimate for the Kemper IGCC abovein total is approximately $6.58 billion, which includes approximately $5.35 billion of costs subject to the construction cost cap and is net of $137 million in additional DOE grants Mississippi Power received for the Kemper IGCC on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. In the aggregate, Southern Company has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2016. Mississippi Power's current cost estimate includes costs through September 30, 2016. 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 Initial 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 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 eventsmatters cannot be determined at this time.
See FINANCIAL CONDITION AND LIQUIDITY – "Capital RequirementsCivil Lawsuit
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and Contractual Obligations" for additional information.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Income Tax Matters"John Carlton Dean. The plaintiffs allege that Mississippi Power violated the Mississippi Unfair Trade Practices Act and concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule 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 expenditures related to the Kemper IGCC and that Mississippi Power's alleged breaches interfered with and destroyed economically advantageous relationships between the plaintiffs and their current and prospective business associates. The plaintiffs seek unspecified actual damages and punitive damages as well as attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in its federal income tax calculations for 2013this proceeding could have an impact on Southern Company's results of operations, financial condition, and 2014. Due toliquidity. Mississippi Power will vigorously defend the uncertainty related to this tax position, Southern Company had unrecognized tax benefits totaling approximately $211 million at March 31, 2015. See Note 5 tomatter, and 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 Benefits," respectively, herein for additional information. The ultimatefinal 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

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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 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 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 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.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

information on the Kemper IGCC estimated construction costs and expected in-service date. Southern Company and Mississippi Power are cooperating fully with the SEC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.
Through 2015, capacity revenues from long-term non-affiliate sales out of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) represented the majority of Gulf Power's wholesale earnings. The capacity revenues associated with these contracts covering 100% of Gulf Power's ownership represented 82% of Gulf Power's wholesale capacity revenues in 2015. Due to the expiration of a wholesale contract at the end of 2015 and another wholesale contract at the end of May 2016, Gulf Power's remaining contracted sales from the unit from June 2016 through 2019 will cover approximately 24% of the unit. The expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts are not expected to have a material impact on Southern Company's earnings. The alternatives Gulf Power is actively evaluating include, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as the contracts expire. The ultimate outcome of this matter cannot be determined at this time.
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, ContingentAsset Retirement Obligations, and Pension and Other Postretirement Benefits.Benefits, and Contingent Obligations.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2015,2016, 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 Initial 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 to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial 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 $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $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, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.06$2.47 billion ($1.271.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2015.2016.
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 Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

26

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

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

25

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

construction operating 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, but not limited to, 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,September 30, 2016. Any further extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $30$35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any further extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 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$14 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 totalof approximately $6$2 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.
Recently Issued Accounting Standards
In May 2014,On February 25, 2016, the FASB issued ASC 606,ASU No. 2016-02, Revenue from ContractsLeases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with Customers. ASC 606 revisesleases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Southern Company 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. Theexisting leveraged leases. 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 and2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company currently reflects unamortized debt issuance costsrecognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in unamortized debt issuance expense onadditional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its balance sheet. Upon adoption, the reclassification will not have a material impact on the resultsultimate impact.

27

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

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. Southern Company's financial condition remained stable at March 31, 2015.2016. Through March 31, 2015,2016, Southern Company has incurred non-recoverable cash expenditures of $1.49$2.11 billion and is expected to incur approximately $567 million$0.36 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 bank credit agreements 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 $913 million$0.9 billion for the first three months of 2015, a decrease of $190 million from2016 and the corresponding period in 2014. The decrease in net cash provided from operating activities was primarily due to a decrease in KWH generation from coal and the timing of fuel purchases.2015. Net cash used for investing activities totaled $1.1$2.2 billion for the first three months of 20152016 primarily due to gross property additions for construction of generation, transmission, and distribution facilities and installation of equipment to comply with environmental standards, construction of generation, transmission, and

26

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

distribution facilities, acquisitions of solar facilities, and purchases of nuclear fuel.standards. Net cash provided from financing activities totaled $596 million$0.7 billion for the first three months of 2015. This was2016 primarily due to issuances of long-term debt, partially offset by redemptions of short-term and long-term debt and common stock and an increase in short-term debt outstanding, partially offset by common stock dividend payments, redemptions of long-term debt, and the repurchase of common stock.payments. 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 three months of 20152016 include an increase of $607 million$1.4 billion in total property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other significant changes include an $876 millionfacilities; a $0.7 billion decrease in cash and cash equivalents due to the funding of acquisitions and construction of renewable energy projects; a $1.1 billion increase in notesshort-term and long-term debt to fund the subsidiaries' continuous construction programs and for other general corporate purposes; a $0.3 billion decrease in accounts payable due to the timing of vendor payments; and a $390 million$0.3 billion decrease in accrued compensation.compensation due to the timing of payments.
At the end of the first quarter 2015,2016, the market price of Southern Company's common stock was $44.28$51.73 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.04$22.65 per share, representing a market-to-book ratio of 201%228%, compared to $49.11, $21.98,$46.79, $22.59, and 223%207%, respectively, at the end of 2014.2015. Southern Company's common stock dividend for the first quarter 20152016 was $0.5250$0.5425 per share compared to $0.5075$0.5250 per share in the first quarter 2014. In April 2015, the quarterly dividend payable in June 2015 was increased to $0.5425 per share.2015.
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 $3.7$2.5 billion will be required through March 31, 20162017 to fund maturities of long-term debt and announced redemptions of preferred and preference stock of Alabama Power.long-term debt. See "Sources of Capital" herein for additional information.
In addition to the cash consideration for the Merger to be paid by Southern Company at the effective time of the Merger, Southern Company will also assume AGL Resources' outstanding indebtedness (approximately $4.3 billion at March 31, 2016). See OVERVIEW herein for additional information regarding the Merger as well as Note (I) to the Condensed Financial Statements herein.
The Southern Company system's construction program is currently estimated to total $7.3 billion for 2016, $5.2 billion for 2017, and $5.5 billion for 2018. These amounts include expenditures of approximately $0.7 billion

28

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

related to the construction and start-up of the Kemper IGCC in 2016; $0.6 billion, $0.7 billion, and $0.4 billion to continue construction on Plant Vogtle Units 3 and 4 in 2016, 2017, and 2018, respectively; and $2.2 billion, $0.9 billion, and $1.4 billion for Southern Power's acquisitions and/or construction of new generating facilities in 2016, 2017, and 2018, respectively.
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 due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. 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 operating 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 additional equity capital to be raisedand debt issuances in 2015,2016, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements.

27

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

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.
In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which may be used to reimburse Georgia Power for eligible costsEligible 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 costs)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. 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 costsProject Costs incurred through March 31, 20152016 would allow for borrowings of up to $2.1 billion under the FFB Credit Facility. Through March 31, 2015, Georgia Power has borrowed $1.2$2.5 billion under the FFB Credit Facility, leaving $0.9 billion of available borrowing ability.which Georgia Power has borrowed $2.2 billion.
Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE Grants is expected to be received for commercial operation of the Kemper IGCC. On April 8, 2016, Mississippi Power received approximately $137 million in

29

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

Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. In addition, see Note (B)3 to the Condensed Financial Statementsfinancial statements of Southern Company 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.
As of March 31, 2015,2016, Southern Company's current liabilities exceeded current assets by $2.8$2.4 billion, primarily due to long-term debt that is due within one year, of $3.3including approximately $0.9 billion including approximatelyat the parent company, $0.2 billion at Alabama Power, $0.5 billion at Georgia Power, $0.1 billion at Gulf Power, $0.3 billion at Mississippi Power, and $0.4 billion at Southern Company, $0.7 billion at Alabama Power, $1.6 billion at Georgia Power, and $0.5 billion at Southern Power. In addition, Mississippi Power has $0.9 billion in bank term loans that 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 and financial institutions. Southern Company, the traditional operating companies, and Southern Power intend to utilize operating cash flows, as well as commercial paper, lines 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, in 2015,for the remainder of 2016, Georgia Power expects to utilize borrowings through the FFB Credit Facility as its primaryan additional source of long-term borrowed funds.

28

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

At March 31, 2015,2016, Southern Company and its subsidiaries had approximately $1.1$0.8 billion of cash and cash equivalents. Committed credit arrangements with banks at March 31, 20152016 were as follows:
 Expires   
Executable Term
Loans
 
Due Within One
Year
Expires   
Executable Term
Loans
 
Due Within One
Year
Company 2015 2016 2017 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
2016201720182020 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)
Southern Company(a) $
 $
 $
 $1,000
 $1,000
 $1,000
 $
 $
 $
 $
$
$
$1,000
$1,250
 $2,250
 $2,250
 $
 $
 $
 $
Alabama Power 228
 50
 
 1,030
 1,308
 1,308
 58
 
 58
 170
40

500
800
 1,340
 1,340
 
 
 
 40
Georgia Power 
 150
 
 1,600
 1,750
 1,736
 
 
 
 150



1,750
 1,750
 1,732
 
 
 
 
Gulf Power 45
 200
 30
 
 275
 275
 50
 
 50
 195
75
40
165

 280
 280
 45
 
 45
 40
Mississippi Power 135
 165
 
 
 300
 270
 25
 40
 65
 235
205



 205
 180
 30
 15
 45
 160
Southern Power 
 
 
 500
 500
 488
 
 
 
 
Southern Power Company (b)



600
 600
 560
 
 
 
 
Other 70
 
 
 
 70
 70
 20
 
 20
 50
70



 70
 70
 20
 
 20
 50
Total $478
 $565
 $30
 $4,130
 $5,203
 $5,147
 $153
 $40
 $193
 $800
$390
$40
$1,665
$4,400
 $6,495
 $6,412
 $95
 $15
 $110
 $290
(a)Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.
(b)Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which are non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to such solar facilities currently under construction. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.
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 March 31, 2015 was approximately $1.8 billion. In addition, at March 31, 2015, the traditional operating companies had $396 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2015, $145 million of these fixed rate pollution control revenue bonds were purchased and are being held by the applicable traditional operating company and currently are not required to be remarketed within the next 12 months.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements, as needed, prior to expiration.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Mississippi Power, and Southern Power, contain covenants that limit debt levels and contain cross acceleration or 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. Such cross acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. Southern Company, the traditional operating companies, and Southern Power Company are currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

30

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

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.
A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies' pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2016 was approximately $1.8 billion. In addition, at March 31, 2016, the traditional operating companies had approximately $269 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue a minimum of $8.0 billion in debt prior to closing the Merger and a minimum of $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, the proposed acquisition of PowerSecure, and Southern Power and other Southern Company system capital projects. Total capital raised in 2016 may increase due to cash needed at the closing of the Merger, settlement of hedges, and incremental investment opportunities, including additional Southern Power projects in excess of its current capital plans. Southern Company expects to issue the debt to fund the cash consideration for the Merger in several tranches including long-dated maturities. The amount of debt issued at each maturity will depend on prevailing market conditions at the time of the offering and other factors. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. See MANAGEMENT'S DISCUSSION AND ANALYSIS FINANCIAL CONDITION AND LIQUIDITY "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
Southern Company, 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.above, excluding the Bridge Agreement. 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 loansShort-term borrowings are included in notes payable in the balance sheets.

29

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
March 31, 2015
 
Short-term Debt During the Period(*)
 
Short-term Debt at
March 31, 2016
 
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
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 (in millions)   (in millions)   (in millions) (in millions)   (in millions)   (in millions)
Commercial paper $1,399
 0.3% $883
 0.3% $1,487
 $757
 0.8% $853
 0.8% $1,233
Short-term bank debt 280
 0.8% 10
 1.1% 280
 25
 2.1% 375
 1.9% 500
Total $1,679
 0.4% $893
 0.3%   $782
 0.9% $1,228
 1.0%  
(*)    
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2016.
In addition to the short-term borrowings in the table above, the Project Credit Facilities had total amounts outstanding as of March 31, 2016 of $413 million at a weighted average interest rate of 1.99%. For the three months ended March 31, 2015.2016, these credit agreements had a maximum amount outstanding of $413 million, and an average amount outstanding of $260 million at a weighted average interest rate of 1.99%.
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank notes, and operating cash flows.

31

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

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 Baa3Baa2 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate derivatives,management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at March 31, 20152016 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and Baa2$9
At BBB and/or Baa2$12
At BBB- and/or Baa3385
$511
Below BBB- and/or Baa32,454
$2,335
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, anya credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, particularlyand would be likely to impact the short-term debt market and the variable rate pollution control revenue bond market.cost at which they do so.
Financing Activities
During the first three months of 2015,2016, Southern Company issued approximately 3.16.6 million shares of common stock primarily through the employee equity compensation plan and received proceeds of approximately $112$270 million. Southern Company is not currently issuingmay satisfy its obligations with respect to the plans in several ways, including through using newly issued 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 withtreasury shares acquiredor acquiring shares on the open market bythrough independent plan administrators.
On March 2, 2015,The following table outlines the long-term debt financing activities for Southern Company announced a program to repurchase up to 20 million sharesand its subsidiaries for the first three months 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 March 31, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market2016:

30
Company(a)
Senior
Note Issuances
 
Senior
Note Maturities and Redemptions
 
Revenue
Bond
Maturities, Redemptions, and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt Redemptions
and
Maturities(b)
 (in millions)
Alabama Power$400
 $200
 $
 $45
 $
Georgia Power650
 250
 4
 
 1
Mississippi Power
 
 
 1,100
 426
Southern Power
 
 
 2
 3
Other
 
 
 
 4
Elimination(c)

 
 
 (200) 
Total$1,050
 $450
 $4
 $947
 $434
(a)Southern Company and Gulf Power did not issue or redeem any long-term debt during the first three months of 2016.    
(b)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
(c)Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

32

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

purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.
The following table outlines the long-term debt financing activities forIn February 2016, Southern Company and itsentered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swaps totaled $700 million.
Except as described herein, Southern Company's subsidiaries for the first three months of 2015:
Company(a)
Senior
Note Issuances
 
Senior
Note Redemptions
 
Other
Long-Term
Debt Redemptions
and Maturities(b)
 (in millions)
Alabama Power$550
 $250
 $
Georgia Power
 
 3
Mississippi Power
 
 76
Other
 
 4
Total$550
 $250
 $83
(a)Southern Company, Gulf Power, and Southern Power did not issue or redeem any long-term debt during the first three months of 2015.
(b)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
Alabama Power used the proceeds of the debt issuanceissuances shown in the table above for its redemptiontheir redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including itstheir continuous construction program.programs and, for Southern Power, its growth strategy.
InOn March 2015, Georgia8, 2016, Mississippi Power entered into a three-month floating ratean unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan bearingpursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. This short-term loan was for $250
During the three months ended March 31, 2016, Southern Power's subsidiaries borrowed $276 million aggregate principal amount andpursuant to the proceeds were used for working capital and other general corporate purposes.Project Credit Facilities at a weighted average interest rate of 1.99%.
Subsequent to March 31 2015, Alabama Power purchased and held $80, 2016, Southern Power's subsidiaries borrowed $187 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 may reoffer these bondspursuant to the publicProject Credit Facilities at a later date.weighted average interest rate of 1.93%.
Also subsequent to March 31, 2015, Alabama2016, Gulf 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 will be used for the announced redemption on May 15, 2015 of 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)in May 2016 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 will be used for general corporate purposes, including Alabama Power's continuous construction program.
Also subsequent to March 31, 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 may reoffer these bonds to the public at a later date.
Also subsequent to March 31, 2015, Georgia Power redeemed $125 million aggregate principal amount of its Series Y 5.80%2011A 5.75% Senior Notes due April 15, 2035; as a result, Georgia Power reclassified the outstanding principal balance to securities due within one year at March 31, 2015.
Also subsequent to March 31, 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of AprilJune 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

31

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

$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, 2016.2051.
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.

3233



PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the three months ended March 31, 2015,2016, 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,Quarterly Report on Form 10-Q, 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)1934, as amended). 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.controls over financial reporting.
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)1934, as amended) during the first quarter 20152016 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.

3334



ALABAMA POWER COMPANY

3435



ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Operating Revenues:      
Retail revenues$1,268
 $1,297
$1,193
 $1,268
Wholesale revenues, non-affiliates65
 85
63
 65
Wholesale revenues, affiliates15
 69
22
 15
Other revenues53
 57
53
 53
Total operating revenues1,401
 1,508
1,331
 1,401
Operating Expenses:      
Fuel310
 432
268
 310
Purchased power, non-affiliates41
 57
36
 41
Purchased power, affiliates53
 49
33
 53
Other operations and maintenance399
 325
392
 399
Depreciation and amortization158
 175
172
 158
Taxes other than income taxes94
 89
97
 94
Total operating expenses1,055
 1,127
998
 1,055
Operating Income346
 381
333
 346
Other Income and (Expense):      
Allowance for equity funds used during construction15
 10
10
 15
Interest expense, net of amounts capitalized(65) (62)(73) (65)
Other income (expense), net(4) (5)(8) (4)
Total other income and (expense)(54) (57)(71) (54)
Earnings Before Income Taxes292
 324
262
 292
Income taxes113
 127
103
 113
Net Income179
 197
159
 179
Dividends on Preferred and Preference Stock10
 10
4
 10
Net Income After Dividends on Preferred and Preference Stock$169
 $187
$155
 $169

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 For the Three Months
Ended March 31,
 2015 2014
 (in millions)
Net Income$179
 $197
Other comprehensive income (loss):   
Qualifying hedges:   
Changes in fair value, net of tax of $(2) and $-, respectively(4) 
Total other comprehensive income (loss)(4) 
Comprehensive Income$175
 $197
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

35



ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Three Months
Ended March 31,
 2015 2014
 (in millions)
Operating Activities:   
Net income$179
 $197
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total196
 210
Deferred income taxes16
 25
Allowance for equity funds used during construction(15) (10)
Other, net2
 (22)
Changes in certain current assets and liabilities —   
-Receivables(3) (17)
-Fossil fuel stock
 99
-Materials and supplies12
 3
-Other current assets(80) (81)
-Accounts payable(229) (139)
-Accrued taxes246
 147
-Accrued compensation(89) (37)
-Retail fuel cost over recovery34
 (20)
-Other current liabilities21
 (3)
Net cash provided from operating activities290
 352
Investing Activities:   
Property additions(325) (287)
Nuclear decommissioning trust fund purchases(129) (56)
Nuclear decommissioning trust fund sales129
 56
Cost of removal, net of salvage(13) (12)
Change in construction payables34
 49
Other investing activities(9) (5)
Net cash used for investing activities(313) (255)
Financing Activities:   
Proceeds —   
Senior note issuances550
 
Capital contributions from parent company6
 7
Redemptions — Senior notes(250) 
Payment of preferred and preference stock dividends(10) (10)
Payment of common stock dividends(143) (137)
Other financing activities(8) 
Net cash provided from (used for) financing activities145
 (140)
Net Change in Cash and Cash Equivalents122
 (43)
Cash and Cash Equivalents at Beginning of Period273
 295
Cash and Cash Equivalents at End of Period$395
 $252
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $5 and $4 capitalized for 2015 and 2014, respectively)$68
 $61
Income taxes, net(136) (28)
Noncash transactions — Accrued property additions at end of period41
 66
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

36



ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At March 31,
2015
 At December 31,
2014
  (in millions)
Current Assets:    
Cash and cash equivalents $395
 $273
Receivables —    
Customer accounts receivable 374
 345
Unbilled revenues 115
 138
Under recovered regulatory clause revenues 16
 74
Other accounts and notes receivable 24
 23
Affiliated companies 36
 37
Accumulated provision for uncollectible accounts (10) (9)
Fossil fuel stock, at average cost 268
 268
Materials and supplies, at average cost 410
 406
Vacation pay 66
 65
Prepaid expenses 134
 244
Other regulatory assets, current 91
 84
Other current assets 4
 5
Total current assets 1,923
 1,953
Property, Plant, and Equipment:    
In service 23,254
 23,080
Less accumulated provision for depreciation 8,627
 8,522
Plant in service, net of depreciation 14,627
 14,558
Nuclear fuel, at amortized cost 359
 348
Construction work in progress 1,089
 1,006
Total property, plant, and equipment 16,075
 15,912
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 67
 66
Nuclear decommissioning trusts, at fair value 770
 756
Miscellaneous property and investments 85
 84
Total other property and investments 922
 906
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 523
 525
Deferred under recovered regulatory clause revenues 87
 31
Other regulatory assets, deferred 1,065
 1,063
Other deferred charges and assets 161
 162
Total deferred charges and other assets 1,836
 1,781
Total Assets $20,756
 $20,552
 For the Three Months
Ended March 31,
 2016 2015
 (in millions)
Net Income$159
 $179
Other comprehensive income (loss):   
Qualifying hedges:   
Changes in fair value, net of tax of $(1) and $(2), respectively(2) (4)
Reclassification adjustment for amounts included in net income,
net of tax of $1 and $-, respectively
1
 
Total other comprehensive income (loss)(1) (4)
Comprehensive Income$158
 $175
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.


3736



ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
 
Liabilities and Stockholder's Equity At March 31,
2015
 At December 31,
2014
  (in millions)
Current Liabilities:    
Securities due within one year $734
 $454
Accounts payable —    
Affiliated 225
 248
Other 273
 443
Customer deposits 88
 87
Accrued taxes —    
Accrued income taxes 37
 2
Other accrued taxes 59
 37
Accrued interest 59
 66
Accrued vacation pay 54
 54
Accrued compensation 44
 131
Other regulatory liabilities, current 2
 2
Other current liabilities 114
 80
Total current liabilities 1,689
 1,604
Long-term Debt 6,193
 6,176
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 3,890
 3,874
Deferred credits related to income taxes 71
 72
Accumulated deferred investment tax credits 123
 125
Employee benefit obligations 322
 326
Asset retirement obligations 840
 829
Other cost of removal obligations 743
 744
Other regulatory liabilities, deferred 242
 239
Deferred over recovered regulatory clause revenues 81
 47
Other deferred credits and liabilities 88
 79
Total deferred credits and other liabilities 6,400
 6,335
Total Liabilities 14,282
 14,115
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 2,318
 2,304
Retained earnings 2,281
 2,255
Accumulated other comprehensive loss (32) (29)
Total common stockholder's equity 5,789
 5,752
Total Liabilities and Stockholder's Equity $20,756
 $20,552
 For the Three Months
Ended March 31,
 2016 2015
 (in millions)
Operating Activities:   
Net income$159
 $179
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total211
 196
Deferred income taxes68
 16
Allowance for equity funds used during construction(10) (15)
Other, net(3) 2
Changes in certain current assets and liabilities —   
-Receivables191
 (3)
-Fossil fuel stock(27) 
-Materials and supplies(8) 12
-Other current assets(79) (80)
-Accounts payable(143) (229)
-Accrued taxes64
 246
-Accrued compensation(75) (89)
-Retail fuel cost over recovery(1) 34
-Other current liabilities(8) 21
Net cash provided from operating activities339
 290
Investing Activities:   
Property additions(313) (325)
Nuclear decommissioning trust fund purchases(105) (129)
Nuclear decommissioning trust fund sales105
 129
Cost of removal, net of salvage(31) (13)
Change in construction payables(15) 34
Other investing activities(9) (9)
Net cash used for investing activities(368) (313)
Financing Activities:   
Proceeds —   
Senior notes issuances400
 550
Capital contributions from parent company236
 6
Other long-term debt issuances45
 
Redemptions — Senior notes(200) (250)
Payment of common stock dividends(191) (143)
Other financing activities(11) (18)
Net cash provided from financing activities279
 145
Net Change in Cash and Cash Equivalents250
 122
Cash and Cash Equivalents at Beginning of Period194
 273
Cash and Cash Equivalents at End of Period$444
 $395
Supplemental Cash Flow Information:   
Cash paid (received) during the period for --   
Interest (net of $4 and $5 capitalized for 2016 and 2015, respectively)$76
 $68
Income taxes, net(162) (136)
Noncash transactions — Accrued property additions at end of period106
 41
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

37



ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At March 31,
2016
 At December 31,
2015
  (in millions)
Current Assets:    
Cash and cash equivalents $444
 $194
Receivables —    
Customer accounts receivable 311
 332
Unbilled revenues 113
 119
Under recovered regulatory clause revenues 22
 43
Income taxes receivable, current 
 142
Other accounts and notes receivable 25
 20
Affiliated companies 38
 50
Accumulated provision for uncollectible accounts (10) (10)
Fossil fuel stock, at average cost 266
 239
Materials and supplies, at average cost 406
 398
Vacation pay 67
 66
Prepaid expenses 129
 83
Other regulatory assets, current 99
 115
Other current assets 10
 10
Total current assets 1,920
 1,801
Property, Plant, and Equipment:    
In service 25,187
 24,750
Less accumulated provision for depreciation 8,791
 8,736
Plant in service, net of depreciation 16,396
 16,014
Nuclear fuel, at amortized cost 359
 363
Construction work in progress 550
 801
Total property, plant, and equipment 17,305
 17,178
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 68
 71
Nuclear decommissioning trusts, at fair value 746
 737
Miscellaneous property and investments 99
 96
Total other property and investments 913
 904
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 520
 522
Deferred under recovered regulatory clause revenues 105
 99
Other regulatory assets, deferred 1,105
 1,114
Other deferred charges and assets 109
 103
Total deferred charges and other assets 1,839
 1,838
Total Assets $21,977
 $21,721
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.


38



ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity At March 31,
2016
 At December 31,
2015
  (in millions)
Current Liabilities:    
Securities due within one year $200
 $200
Accounts payable —    
Affiliated 258
 278
Other 271
 410
Customer deposits 88
 88
Accrued taxes —    
Accrued income taxes 11
 
Other accrued taxes 62
 38
Accrued interest 65
 73
Accrued vacation pay 55
 55
Accrued compensation 47
 119
Liabilities from risk management activities 37
 55
Other regulatory liabilities, current 175
 240
Other current liabilities 39
 39
Total current liabilities 1,308
 1,595
Long-term Debt 6,894
 6,654
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 4,306
 4,241
Deferred credits related to income taxes 69
 70
Accumulated deferred investment tax credits 116
 118
Employee benefit obligations 377
 388
Asset retirement obligations 1,461
 1,448
Other cost of removal obligations 705
 722
Other regulatory liabilities, deferred 119
 136
Deferred over recovered regulatory clause revenues 64
 
Other deferred credits and liabilities 78
 76
Total deferred credits and other liabilities 7,295
 7,199
Total Liabilities 15,497
 15,448
Redeemable Preferred Stock 85
 85
Preference Stock 196
 196
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 2,585
 2,341
Retained earnings 2,425
 2,461
Accumulated other comprehensive loss (33) (32)
Total common stockholder's equity 6,199
 5,992
Total Liabilities and Stockholder's Equity $21,977
 $21,721
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

39

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



FIRST QUARTER 20152016 vs. FIRST QUARTER 2014

2015


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, 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. AppropriatelyAlabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Alabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(18) (9.6)
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(14) (8.3)
Alabama Power's net income after dividends on preferred and preference stock for the first quarter 20152016 was $169$155 million compared to $187$169 million for the corresponding period in 2014.2015. The decrease in net income was primarily related to an increase in non-fuel operations and maintenance expenses, partially offset by an increase in rates under rate stabilization and equalization (Rate RSE) as well as a decrease in depreciation expense. Also contributingrevenue primarily due to the decrease in net income was milder weather in the first quarter 20152016 as compared to the corresponding period in 2014.2015, an increase in interest expense, and a decrease in AFUDC. These decreases were partially offset by an increase in revenues under Rate CNP Compliance and a decrease in dividends on preferred and preference stock.
Retail Revenues
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(29) (2.2)
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(75) (5.9)
In the first quarter 2015,2016, retail revenues were $1.27$1.19 billion compared to $1.30$1.27 billion for the corresponding period in 2014.2015.

3940

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



Details of the changes in retail revenues were as follows:
 
First Quarter
2015
 First Quarter 2016
 (in millions)
(% change) (in millions)
(% change)
Retail – prior year $1,297
   $1,268
  
Estimated change resulting from –        
Rates and pricing 47
 3.6
 33
 2.6
Sales growth 9
 0.7
 8
 0.6
Weather (20) (1.5) (45) (3.5)
Fuel and other cost recovery (65) (5.0) (71) (5.6)
Retail – current year $1,268
 (2.2)% $1,193
 (5.9)%
Revenues associated with changes in rates and pricing increased in the first quarter 20152016 when compared to the corresponding period in 20142015 primarily due to aincreased revenues under Rate RSE increase effective January 1, 2015.CNP Compliance associated with increases in the average net investments. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales growth increased in the first quarter 20152016 when compared to the corresponding period in 2014. Industrial2015. Weather-adjusted residential and commercial KWH energy sales slightly increased 0.3% in2.3% and 0.9%, respectively, for the first quarter 2016 when compared to the corresponding period in 2015 as a result of an increaseincreased customer demand. Industrial KWH energy sales decreased 3.5% for the first quarter 2016 when compared to the corresponding period in 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the pipelines, stone, clay, and glass, and automotive and plastics sectors, offset by a decrease in demand in the primary metals, and forest productschemicals sectors. Weather-adjusted residentialA strong dollar, low oil prices, and commercial KWH energy sales increased 0.8% and 1.6%, respectively,weak global growth conditions have constrained growth in the first quarter 2015 as a result of increased customer usage and customer growth.industrial sector.
Revenues resulting from changes in weather decreased in the first quarter 20152016 due to milder weather experienced in Alabama Power's service territory as compared to the corresponding period in 2014.2015. For the first quarter 2015,2016, the resulting decreases were 2.4%6.6% and 1.7%2.2% for residential and commercial sales revenue, respectively.
Fuel and other cost recovery revenues decreased in the first quarter 20152016 when compared to the corresponding period in 20142015 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
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(20) (23.5)
Wholesale revenues from sales to non-affiliates will vary depending on the market prices of available wholesale energy compared See Note 3 to the costfinancial statements of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availabilityPower under "Retail Regulatory Matters" in Item 8 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.
In the first quarter 2015, wholesale revenues from sales to non-affiliates were $65 million compared to $85 millionForm 10-K for the corresponding period in 2014. The decrease was primarily due to a 9.0% decrease in KWH sales and a 15.9% decrease in the price of energy. In 2014, Alabama Power's fuel diversity led to increased sales to non-affiliates due to higher than normal natural gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation, due to less rainfall, resulted in lower sales of Alabama Power's generation to non-affiliates.additional information.

40

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



Wholesale Revenues Affiliates
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(54) (78.3)
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$7 46.7
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 first quarter 2015,2016, wholesale revenues from sales to affiliates were $15$22 million compared to $69$15 million for the corresponding period in 2014. The decrease was primarily due to a 69.1% decrease in2015. KWH sales and a 30.9% decrease in the price of energy. In 2014, Alabama Power's fuel diversity led to increased sales to affiliates due toincreased 78.5% primarily as a result of higher than normalavailable hydro generation and lower natural gas prices. In 2015, lower natural gas prices and decreased availability

41

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



Fuel and Purchased Power Expenses
 
 First Quarter 2015
vs.
First Quarter 2014
  First Quarter 2016
vs.
First Quarter 2015
 (change in millions)
(% change) (change in millions)
(% change)
Fuel $(122) (28.2) $(42) (13.5)
Purchased power – non-affiliates (16) (28.1) (5) (12.2)
Purchased power – affiliates 4
 8.2 (20) (37.7)
Total fuel and purchased power expenses $(134)  $(67) 
In the first quarter 2015,2016, total fuel and purchased power expenses were $404$337 million compared to $538$404 million for the corresponding period in 2014.2015. The decrease was primarily due to a $69$33 million decrease inrelated to the average costvolume of fuel,KWHs purchased, a $53$23 million decrease related to the volume of KWHs generated, and a $37$19 million decrease in the average cost of purchased power,fuel. These decreases were partially offset by a $25an $8 million increase in the volumeaverage cost of KWHs purchased.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 clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.

41

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



Details of Alabama Power's generation and purchased power were as follows:
 
First Quarter
2015
 First Quarter
2014
 First Quarter 2016 First Quarter 2015
Total generation (billions of KWHs)
 15 16 15 15
Total purchased power (billions of KWHs)
 2 2 1 2
Sources of generation (percent)
  
Coal 47 53 40 47
Nuclear 26 23 27 26
Gas 19 15 19 19
Hydro 8 9 14 8
Cost of fuel, generated (cents per net KWH)
  
Coal 2.89 3.40 2.86 2.89
Nuclear 0.80 0.87 0.77 0.80
Gas 3.03 4.19 2.46 3.03
Average cost of fuel, generated (cents per net KWH)(a)
 2.33 2.89 2.12 2.33
Average cost of purchased power (cents per net KWH)(b)
 4.60 6.41 5.16 4.60
(a)
KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)
Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the first quarter 2015,2016, fuel expense was $310$268 million compared to $432$310 million for the corresponding period in 2014.2015. The decrease was primarily due to a 27.6%18.8% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 20.6%15.0% decrease in the volume of KWHs generated by coal, and a 15.1% decrease in the average cost of coal generation. This was partially offset by a 22.6% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall and a 6.7%6.8% increase in the volume of KWHs generated by natural gas.

42

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



Purchased Power – Non-Affiliates
In the first quarter 2015,2016, purchased power expense from non-affiliates was $41$36 million compared to $57$41 million for the corresponding period in 2014.2015. The decrease was related to a 33.1%10.7% decrease in the average cost per KWH purchased as a result of lower natural gas prices, partially offset by a 7.3% increase in the amount of energy purchased due to decreasedthe availability of hydrolower cost generation as a result of lessmore rainfall in the first quarter of 2015 as compared to the corresponding period during 2014.for hydro generation and 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 first quarter 2015,2016, purchased power expense from affiliates was $53$33 million compared to $49$53 million for the corresponding period in 2014.2015. The increasedecrease was related to a 35.6% increase48.2% decrease in the amount of energy purchased primarily due to milder weather and the availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation as a result of less rainfall. This increasemore rainfall for hydro generation and lower natural gas prices. The decrease was partially offset by a 20.2% decrease20.6% increase in the average cost of purchased power per KWH purchased due to lower natural gas prices.from affiliates.

42

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



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
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$74 22.8
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(7) (1.8)
In the first quarter 2015,2016, other operations and maintenance expenses were $399$392 million compared to $325$399 million for the corresponding period in 2014.2015. The decrease was primarily due to a decrease of $14 million in steam generation costs primarily due to scheduled outage costs. This decrease was partially offset by a $6 million increase in nuclear generation costs primarily due to outage amortization and materials costs.
Depreciation and Amortization
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$14 8.9
In the first quarter 2016, depreciation and amortization was $172 million compared to $158 million for the corresponding period in 2015. The increase was primarily due to the implementationresult of an accounting orderincrease in 2014 allowing the deferraldepreciation of non-nuclear outage costs. Alabama Power deferred approximately $25 million of non-nuclear outage expenditures in the first quarter 2014.compliance related steam equipment. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Cost of Removal Accounting Order"Rate CNP" in Item 8 of the Form 10-K for additional information. In addition, there was an increase of $23 million in steam production primarily due to scheduled outage costs and a $10 million increase in employee benefits including pension costs. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
Depreciation and Amortization
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(17) (9.7)
In the first quarter 2015, depreciation and amortization was $158 million compared to $175 million for the corresponding period in 2014. The decrease was primarily due to a decrease in depreciation rates related to steam, transmission, distribution, and environmental assets effective January 1, 2015, as authorized by the FERC, partially offset by increases in plant in service.
Allowance for Equity Funds Used During Construction
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$5 50.0
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(5) (33.3)
In the first quarter 2015,2016, AFUDC equity was $10 million compared to $15 million for the corresponding period in 2015. The decrease was primarily associated with capital projects being placed in service for environmental and steam generation in 2016.

43

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



Interest Expense, Net of Amounts Capitalized
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$8 12.3
In the first quarter 2016, interest expense, net of amounts capitalized was $73 million compared to $65 million for the corresponding period in 2015. The increase was primarily due to timing of debt issuances, maturities, and redemptions.
Income Taxes
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(10) (8.8)
In the first quarter 2016, income taxes were $103 million compared to $113 million for the corresponding period in 2015. The decrease was primarily due to lower pre-tax earnings.
Dividends on Preferred and Preference Stock
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(6) (60.0)
In the first quarter 2016, dividends on preferred and preference stock were $4 million compared to $10 million for the corresponding period in 2014. The increase was primarily due to additional capital expenditures for steam environmental, steam generation, and nuclear production.
Income Taxes
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(14) (11.0)
In the first quarter 2015, income taxes were $113 million compared to $127 million for the corresponding period in 2014.2015. The decrease was primarily due to lower pre-tax earnings.the redemption in May 2015 of certain series of preferred and preference stock. See Note 6 to the financial statements of Alabama Power under "Redeemable Preferred Stock" in Item 8 of the Form 10-K for additional information.
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,

43

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



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 are 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. ChangesDemand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by 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 andwhich may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to 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.modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are

44

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



recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information. 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.
Environmental Statutes and Regulations
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations" and "Retail Regulatory Matters Environmental Accounting Order" of Alabama Power in Item 7 of the Form 10-K and "Retail Regulatory Matters Environmental Accounting Order" herein for additional information regarding Alabama Power's plan for compliance with environmental statutes and regulations.
Coal Combustion ResidualsAir Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Coal Combustion Residuals"Air Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.final MATS rule and regional haze regulations.
On April 17,25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published the Disposalits supplemental finding regarding consideration of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule)costs in the Federal Register, setting October 14, 2015 as the effective datesupport of the CCR Rule.MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Alabama Power units that are subject to the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the CCR Ruleproposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and 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 expects to record incremental asset retirement obligations of approximately $330 million to $350 million related to the CCR Rule in the second quarter 2015.time.
FERC Matters
See BUSINESS – REGULATION – "Federal Power Act" in Item 1 of the Form 10-K for a discussion of 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 reliancePower's hydroelectric developments on the energy auction as tailored mitigation.Coosa River. On April 27, 2015,21, 2016, the FERC issued an order finding thatgranting in part and denying in part Alabama Power's rehearing request of the traditional operating companies' (includingnew license for Alabama Power's)Power's seven hydroelectric developments on the Coosa River. The order also denied rehearing requests filed by Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, 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

44

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



companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies (including Alabama Power) and Southern Power, within 60 days, 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. Alabama Power is evaluating the order.Atlanta Regional Commission. The ultimate outcome of this matter cannot be determined at this time.
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 primarily through its Rate RSE, Rate CNP Compliance, 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 NoteNotes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and Note 3 under "Retail Regulatory Matters"Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate 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
In March 2015, the Emerging Issues Task Force unanimously recommended to allow the normal purchases and normal sales exception for physical forward transactions in nodal energy markets. The Financial Accounting Standards Board (FASB) proposed new accounting guidance reflecting the recommendation on April 23, 2015. This guidance is subject to a public comment period before the FASB issues a final accounting standard. The ultimate outcome of this matter cannot be determined at this time.
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. Alabama Power is continuing to evaluate its plans for Plant Barry Unit 3 (225 MWs), which is currently unavailable for generation.
In accordance with an accounting order from the Alabama PSC, Alabama Power will transfer 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.
Rate CNP Compliance (Formerly Known As Rate CNP Environmental)
See 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 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism.
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 $14 million of non-environmental compliance costs during the first quarter 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 the year.

45

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



Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as 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.

45

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



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 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.
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, ContingentAsset Retirement Obligations, and Pension and Other Postretirement Benefits.Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In May 2014,On February 25, 2016, the FASB issued ASC 606,ASU No. 2016-02, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Alabama 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):Leases Simplifying the Presentation of Debt Issuance Costs(Topic 842) (ASU 2016-02). The ASU 2016-02 requires that debt issuance costs relatedlessees to a recognized debt liability be presented inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Alabama Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Alabama Power's balance sheet.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Alabama Power currently reflects unamortized debt issuance costsrecognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in other deferred chargesadditional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Alabama Power is currently evaluating the new standard and assets onhas not yet determined 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.ultimate impact.
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 March 31, 2015.2016. 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 $339 million for the first three months of 2016, an increase of

46

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



"Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $290 million for the first three months of 2015, a decrease of $62$49 million as compared to the first three months of 2014.2015. The decreaseincrease in net cash provided from operating activities was primarily due to the timing of fossil fuel stock purchasesvendor payments and payments of accounts payable,deferred income taxes, partially offset by the collection of fuel cost recovery revenues and timing of payments and refunds associated with bonus depreciation.fossil fuel stock purchases. Net cash used for investing activities totaled $313$368 million for the first three months of 20152016 primarily due to gross property additions related to distribution, environmental, transmission,distribution, steam generation, and nuclear fuel.transmission. Net cash provided from financing activities totaled $145$279 million for the first three months of 20152016 primarily due to the issuanceissuances of long-term debt and a capital contribution from Southern Company, partially offset by thea redemption of long-term debt and a payment of common stock dividends.dividend payment. 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 three months of 20152016 include an increaseincreases of $280$250 million in securitiescash and cash equivalents, $244 million in additional paid-in capital due within one year, $163to capital contributions from Southern Company, $240 million in long-term debt primarily due to the issuance of additional senior notes, and $127 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, steam generation,distribution, and nuclear fuel and $122 million in cash and cash equivalents.generation. Other significant changes include decreases of $170$142 million in otherincome taxes receivable following the receipt of a federal income tax refund and $139 million in accounts payable primarily due to property tax payments and $110 million in prepaid expenses associated with an income tax refund.the timing of vendor payments.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, 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 $1.1 billion$200 million will be required through March 31, 20162017 to fund maturities of long-term debt and announced redemptions of preferred and preference stock.debt.
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 frommeet its future capital needs through operating cash flows, short-term debt, term loans, external 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.

47

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



Alabama Power's current liabilities sometimes exceed current assets because of Alabama Power's debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.

47

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



At March 31, 2015,2016, Alabama Power had approximately $395$444 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 20152016 were as follows:
ExpiresExpires     
Executable Term
Loans
 
Due Within One
Year
Expires     
Due Within One
Year
2015 2016 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
20162016 2018 2020 Total Unused 
Term
Out
 
No Term
Out
(in millions)(in millions) (in millions) (in millions) (in millions)(in millions) (in millions) (in millions)
$228
 $50
 $1,030
 $1,308
 $1,308
 $58
 $
 $58
 $170
40
 $500
 $800
 $1,340
 $1,340
 $
 $40
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.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross defaultacceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross defaultacceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, or guarantee obligations over a specified threshold.the payment of which was then accelerated. 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.
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. AsThe amount of March 31, 2015, Alabama Power had $864 million of outstanding variable rate pollution control revenue bonds outstanding requiring liquidity support.support as of March 31, 2016 was approximately $810 million. In addition, at March 31, 2015,2016, Alabama Power had $200$167 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2015, $80 million of these fixed rate pollution control revenue bonds were purchased and are being held by Alabama Power and currently are not required to be remarketedreoffered within the next 12 months.
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. 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
March 31, 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 $
 —% $29
 0.2% $100
  
Short-term Debt During the Period(*)
  
Average
Amount
Outstanding
 
Weighted
Average
Interest Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)
Commercial paper $19
 0.6% $100
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.2016. No short-term debt was outstanding at March 31, 2016.
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, short-term bank notes, and operating cash flows.

48

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



Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, short-term bank notes, and 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-BBB and/or Baa3.Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At March 31, 2015, themanagement, and transmission. The maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3March 31, 2016 were approximately $366 million. as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$1
At BBB- and/or Baa3$2
Below BBB- and/or Baa3$349
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, a credit rating downgrade could impact the ability of Alabama Power to access capital markets, and would be likely to impact the cost at which it does so.
Financing Activities
In March 2015,January 2016, Alabama Power issued $550$400 million aggregate principal amount of Series 2015A 3.750%2016A 4.30% Senior Notes due March 1, 2045.January 2, 2046. The proceeds were used to redeem $250repay at maturity $200 million aggregate principal amount of Alabama Power's Series DD 5.65%FF 5.20% Senior Notes due MarchJanuary 15, 20352016 and for general corporate purposes, including Alabama Power's continuous construction program.program.
Subsequent toIn March 31, 2015,2016, Alabama Power purchased and held $80 millionentered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of Industrial Development Board$45 million, one of the Citywhich bears interest at 2.38% per annum and two of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power may reoffer these bonds to the public at a later date.
Also subsequent to March 31, 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 will be used for the announced redemptionwhich bear interest based on May 15, 2015 of 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 will be used for general corporate purposes, including Alabama Power's continuous construction program.three-month LIBOR.
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.

49



GEORGIA POWER COMPANY

50



GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Operating Revenues:      
Retail revenues$1,814
 $2,050
$1,717
 $1,814
Wholesale revenues, non-affiliates68
 109
41
 68
Wholesale revenues, affiliates8
 21
5
 8
Other revenues88
 89
109
 88
Total operating revenues1,978
 2,269
1,872
 1,978
Operating Expenses:      
Fuel526
 752
376
 526
Purchased power, non-affiliates60
 79
83
 60
Purchased power, affiliates149
 184
139
 149
Other operations and maintenance474
 427
457
 474
Depreciation and amortization216
 208
211
 216
Taxes other than income taxes99
 103
97
 99
Total operating expenses1,524
 1,753
1,363
 1,524
Operating Income454
 516
509
 454
Other Income and (Expense):      
Allowance for equity funds used during construction15
 6
Interest expense, net of amounts capitalized(89) (84)(94) (89)
Other income (expense), net
 (2)17
 15
Total other income and (expense)(74) (80)(77) (74)
Earnings Before Income Taxes380
 436
432
 380
Income taxes140
 166
160
 140
Net Income240
 270
272
 240
Dividends on Preferred and Preference Stock4
 4
4
 4
Net Income After Dividends on Preferred and Preference Stock$236
 $266
$268
 $236
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Net Income$240
 $270
$272
 $240
Other comprehensive income (loss):      
Qualifying hedges:      
Changes in fair value, net of tax of $(9) and $-, respectively(14) 
Changes in fair value, net of tax of $- and $(9), respectively
 (14)
Reclassification adjustment for amounts included in net
income, net of tax of $- and $-, respectively
1
 
Total other comprehensive income (loss)(14) 
1
 (14)
Comprehensive Income$226
 $270
$273
 $226
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

51



GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Operating Activities:      
Net income$240
 $270
$272
 $240
Adjustments to reconcile net income to net cash provided from operating activities —      
Depreciation and amortization, total256
 250
261
 256
Deferred income taxes(7) 96
55
 (7)
Allowance for equity funds used during construction(15) (6)(14) (15)
Retail fuel cost over recovery — long-term
 (44)
Deferred expenses33
 33
38
 33
Pension, postretirement, and other employee benefits6
 (4)
Other, net(2) (10)(9) 4
Changes in certain current assets and liabilities —      
-Receivables166
 (83)155
 166
-Fossil fuel stock67
 257
36
 67
-Prepaid income taxes170
 (11)38
 170
-Other current assets(13) (12)12
 (13)
-Accounts payable(261) (28)4
 (261)
-Accrued taxes(217) (166)(235) (217)
-Accrued compensation(81) (38)(66) (81)
-Retail fuel cost over recovery — short-term
 (14)
-Other current liabilities21
 9
16
 21
Net cash provided from operating activities363
 499
563
 363
Investing Activities:      
Property additions(422) (460)(553) (422)
Nuclear decommissioning trust fund purchases(161) (175)(211) (161)
Nuclear decommissioning trust fund sales155
 173
206
 155
Cost of removal, net of salvage(15) (16)
Change in construction payables, net of joint owner portion37
 28
(101) 37
Prepaid long-term service agreements(9) (44)(11) (9)
Other investing activities(5) (2)(4) 11
Net cash used for investing activities(405) (480)(689) (405)
Financing Activities:      
Increase (decrease) in notes payable, net434
 (749)(158) 434
Proceeds —      
Capital contributions from parent company11
 12
218
 11
FFB loan
 1,000
Senior notes issuances650
 
Short-term borrowings250
 

 250
Payment of preferred and preference stock dividends(4) (4)
Redemptions and repurchases —   
Pollution control revenue bonds(4) 
Senior notes(250) 
Payment of common stock dividends(259) (238)(326) (259)
FFB loan issuance costs
 (49)
Other financing activities(1) (3)(11) (5)
Net cash provided from (used for) financing activities431
 (31)
Net cash provided from financing activities119
 431
Net Change in Cash and Cash Equivalents389
 (12)(7) 389
Cash and Cash Equivalents at Beginning of Period24
 30
67
 24
Cash and Cash Equivalents at End of Period$413
 $18
$60
 $413
Supplemental Cash Flow Information:      
Cash paid during the period for —   
Interest (net of $6 and $3 capitalized for 2015 and 2014, respectively)$79
 $71
Cash paid (received) during the period for —   
Interest (net of $5 and $6 capitalized for 2016 and 2015, respectively)$86
 $79
Income taxes, net(34) 11
(88) (34)
Noncash transactions — Accrued property additions at end of period177
 229
290
 177

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

52



GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At March 31,
2015
 At December 31,
2014
 At March 31,
2016
 At December 31,
2015
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $413
 $24
 $60
 $67
Receivables —        
Customer accounts receivable 642
 553
 509
 541
Unbilled revenues 174
 201
 182
 188
Joint owner accounts receivable 47
 121
 73
 227
Income taxes receivable, current 
 114
Other accounts and notes receivable 70
 61
 37
 57
Affiliated companies 16
 18
 16
 18
Accumulated provision for uncollectible accounts (7) (6) (2) (2)
Fossil fuel stock, at average cost 372
 439
 366
 402
Materials and supplies, at average cost 443
 438
 463
 449
Vacation pay 91
 91
 92
 91
Prepaid income taxes 86
 278
 118
 156
Other regulatory assets, current 142
 136
 126
 123
Other current assets 85
 74
 61
 92
Total current assets 2,574
 2,428
 2,101
 2,523
Property, Plant, and Equipment:        
In service 31,425
 31,083
 32,318
 31,841
Less accumulated provision for depreciation 11,326
 11,222
 11,045
 10,903
Plant in service, net of depreciation 20,099
 19,861
 21,273
 20,938
Other utility plant, net 197
 211
 158
 171
Nuclear fuel, at amortized cost 555
 563
 582
 572
Construction work in progress 4,193
 4,031
 4,817
 4,775
Total property, plant, and equipment 25,044
 24,666
 26,830
 26,456
Other Property and Investments:        
Equity investments in unconsolidated subsidiaries 60
 58
 60
 64
Nuclear decommissioning trusts, at fair value 804
 789
 793
 775
Miscellaneous property and investments 37
 38
 43
 43
Total other property and investments 901
 885
 896
 882
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 696
 698
 680
 679
Deferred under recovered regulatory clause revenues 62
 197
Other regulatory assets, deferred 1,796
 1,753
 2,138
 2,152
Other deferred charges and assets 443
 403
 157
 173
Total deferred charges and other assets 2,997
 3,051
 2,975
 3,004
Total Assets $31,516
 $31,030
 $32,802
 $32,865
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.


53



GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity At March 31,
2015
 At December 31,
2014
 At March 31,
2016
 At December 31,
2015
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $1,600
 $1,154
 $458
 $712
Notes payable 840
 156
 
 158
Accounts payable —        
Affiliated 364
 451
 370
 411
Other 469
 555
 549
 750
Customer deposits 256
 253
 266
 264
Accrued taxes —    
Accrued income taxes 
 12
Other accrued taxes 116
 332
 101
 325
Accrued interest 100
 96
 102
 99
Accrued vacation pay 62
 63
 62
 62
Accrued compensation 54
 153
 60
 142
Liabilities from risk management activities 52
 32
Asset retirement obligations, current 184
 179
Other current liabilities 388
 225
 211
 181
Total current liabilities 4,301
 3,470
 2,363
 3,295
Long-term Debt 8,393
 8,683
 10,268
 9,616
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 5,471
 5,507
 5,686
 5,627
Deferred credits related to income taxes 104
 106
 105
 105
Accumulated deferred investment tax credits 193
 196
 201
 204
Employee benefit obligations 891
 903
 930
 949
Asset retirement obligations 1,223
 1,223
Asset retirement obligations, deferred 1,699
 1,737
Other deferred credits and liabilities 268
 255
 395
 347
Total deferred credits and other liabilities 8,150
 8,190
 9,016
 8,969
Total Liabilities 20,844
 20,343
 21,647
 21,880
Preferred Stock 45
 45
 45
 45
Preference Stock 221
 221
 221
 221
Common Stockholder's Equity:        
Common stock, without par value —        
Authorized — 20,000,000 shares        
Outstanding — 9,261,500 shares 398
 398
 398
 398
Paid-in capital 6,218
 6,196
 6,504
 6,275
Retained earnings 3,812
 3,835
 4,002
 4,061
Accumulated other comprehensive loss (22) (8) (15) (15)
Total common stockholder's equity 10,406
 10,421
 10,889
 10,719
Total Liabilities and Stockholder's Equity $31,516
 $31,030
 $32,802
 $32,865
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

54

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


FIRST QUARTER 20152016 vs. FIRST QUARTER 2014

2015


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, 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 and4. Georgia Power will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. AppropriatelyGeorgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
Georgia Power continues to focus on several key performance indicators. These indicators include, but are not limited to, 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
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(30) (11.3)
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$32 13.6
Georgia Power's net income after dividends on preferred and preference stock for the first quarter 20152016 was $236$268 million compared to $266$236 million for the corresponding period in 2014.2015. The decreaseincrease in the first quarter 2016 was primarily due to higher non-fuel operations and maintenance expenses and milder weather in the first quarter 2015 as compared to the corresponding period in 2014, partially offset by an increase in retail base revenues effective January 1, 20152016, as authorized underby the 2013 ARP.Georgia PSC, and lower non-fuel operating expenses, partially offset by lower retail revenues due to milder weather in the first quarter 2016 as compared to the corresponding period in 2015.
Retail Revenues
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(236) (11.5)
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(97) (5.3)
In the first quarter 2015,2016, retail revenues were $1.81$1.72 billion compared to $2.05$1.81 billion for the corresponding period in 2014.2015.

55

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


Details of the changes in retail revenues were as follows:
 First Quarter
2015
 First Quarter 2016
 (in millions)
(% change) (in millions)
(% change)
Retail – prior year $2,050
   $1,814
  
Estimated change resulting from –        
Rates and pricing 29
 1.4
 43
 2.4
Sales growth 16
 0.8
 8
 0.4
Weather (16) (0.8) (32) (1.8)
Fuel cost recovery (265) (12.9) (116) (6.4)
Retail – current year $1,814
 (11.5)% $1,717
 (5.4)%
Revenues associated with changes in rates and pricing increased in the first quarter 20152016 when compared to the corresponding period in 20142015 primarily due to increases in base tariff increasestariffs approved under 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, which were bothall effective January 1, 2015, partially offset by lower contributions from market-driven rates from commercial and industrial customers.2016. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales increased in the first quarter 20152016 when compared to the corresponding period in 2014.2015. Weather-adjusted residential KWH sales increased 1.0%0.5%, weather-adjusted commercial KWH sales increased 0.9%0.8%, and weather-adjusted industrial KWH sales increased 4.2%1.4% in the first quarter 2016 when compared to the corresponding period in 2015. An increaseIncreases of approximately 26,00024,000 residential customers and approximately 3,000 commercial customers since March 31, 20142015 contributed to the increaseincreases in weather-adjusted residential KWH sales. Increased customer usagesales and an increase of approximately 2,700 customers since March 31, 2014 contributed to the increase in weather-adjusted commercial sales.KWH sales, respectively. Increased demand in the paper, textile,rubber, and stone, clay, and glassnon-manufacturing sectors was the main contributor to the increase in weather-adjusted industrial KWH sales, partially offset by a decreasedecreased demand in the chemicals sector.pipeline, military, and textiles sectors.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $265$116 million in the first quarter 20152016 when compared to the corresponding period in 20142015 primarily due to lower coal and natural gas coal, and nuclear fuel costsprices, more available hydro generation, and lower energy sales resulting from milder weather in the first quarter 20152016 as compared to the corresponding period in 2014.2015. 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 – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.
Wholesale RevenuesNon-Affiliates
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(41) (37.6)
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(27) (39.7)
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. Wholesale capacity revenues from PPAs are 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 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

56

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


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 ofto produce the energy.
In the first quarter 2015,2016, wholesale revenues from sales to non-affiliates were $68$41 million compared to $109$68 million for the corresponding period in 2014 primarily2015 related to a $33$14 million decrease in energy revenues and an $8a $13 million decrease in capacity revenues. The decrease in energy revenues was primarily due to decreased demand resulting from milder weather in the first quarter 2015 as compared to the corresponding period in 2014.lower fuel prices, including higher hydro generation availability. The decrease in capacity revenues reflects the expirationretirement of wholesale contracts in December 2014.14 coal-fired generating units after March 31, 2015 as a result of Georgia Power's environmental compliance strategy.
Wholesale RevenuesAffiliates
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(13) (61.9)
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(3) (37.5)
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 the energy is generally sold at marginal cost.
In the first quarter 2015,2016, wholesale revenues from sales to affiliates were $8$5 million compared to $21$8 million for the corresponding period in 2014.2015. The decrease was due to lower demand resulting from milder weatherfuel prices and a 44.4% decrease in KWH sales in the first quarter 20152016, primarily due to the higher cost of Georgia Power-owned generation as compared to the market cost of available energy.
Other Revenues
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$21 23.9
In the first quarter 2016, other revenues were $109 million compared to $88 million for the corresponding period in 2014.2015. The increase was primarily due to a $14 million increase related to an adjustment for customer temporary facilities service revenues and a $3 million increase in outdoor lighting revenues.
Fuel and Purchased Power Expenses
  First Quarter 2015
vs.
First Quarter 2014
  First Quarter 2016
vs.
First Quarter 2015
 (change in millions)
(% change) (change in millions)
(% change)
Fuel $(226) (30.1) $(150) (28.5)
Purchased power – non-affiliates (19) (24.1) 23
 38.3
Purchased power – affiliates (35) (19.0) (10) (6.7)
Total fuel and purchased power expenses $(280)   $(137)  
In the first quarter 2015,2016, total fuel and purchased power expenses were $735$598 million compared to $1.02 billion$735 million in the corresponding period in 2014.2015. The decrease in the first quarter 20152016 was primarily due to a $237decrease of $89 million decrease in the average cost of fuel and purchased power related to lower natural gas, coal and nuclear fuel prices and the average cost of purchased power due to lower natural gas prices and an $82more rainfall for hydro generation and a net decrease of $48 million decrease in the volume of KWHs generated and purchased due to milder weather as compared to the corresponding period in 20142015 resulting in lower customer demand, partially offset by a $39 million increase in the volume of KWHs purchased due to lower natural gas prices.demand.
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 – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

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FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.
Details of Georgia Power's generation and purchased power were as follows:
 First Quarter
2015
 First Quarter
2014
 First Quarter 2016 First Quarter 2015
Total generation (billions of KWHs)
 17 18 16 17
Total purchased power (billions of KWHs)
 6 5 6 6
Sources of generation (percent)
  
Coal 34 48 30 34
Nuclear 22 20 23 22
Gas 42 29 42 42
Hydro 2 3 5 2
Cost of fuel, generated (cents per net KWH)
  
Coal 4.71 5.03 3.56 4.71
Nuclear 0.54 0.91 0.86 0.54
Gas 2.63 4.39 2.01 2.63
Average cost of fuel, generated (cents per net KWH)
 2.86 3.99 2.22 2.86
Average cost of purchased power (cents per net KWH)(*)
 4.39 5.75 4.32 4.39
(*) 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 first quarter 2015,2016, fuel expense was $526$376 million compared to $752$526 million in the corresponding period in 2014.2015. The decrease was primarily due to a 28.3%22.4% decrease in the average cost of fuel per KWH generated and a 35.5%15.5% decrease in the volume of KWHs generated by coal, partially offset by a 30.9% increase in the volume of KWHs generated by natural gas.coal.
Purchased Power – Non-Affiliates
In the first quarter 2015,2016, purchased power expense from non-affiliates was $60$83 million compared to $79$60 million in the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 21.5%75.3% increase in the volume of KWHs purchased, partially offset by a 28.1% decrease in the average cost per KWH purchased primarily resulting from 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 first quarter 2015,2016, purchased power expense from affiliates was $149$139 million compared to $184$149 million in the corresponding period in 2014.2015. The decrease was due to a 22.8%the result of an 8.8% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices, partially offset by a 14.3% increase in the volume of KWHs purchased in the first quarter 2016 as Georgia Power's units generally dispatched at a higherlower cost than other Southern Company system resources.
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.

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Other Operations and Maintenance Expenses
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$47 11.0
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(17) (3.6)
In the first quarter 2015,2016, other operations and maintenance expenses were $474$457 million compared to $427$474 million in the corresponding period in 2014.2015. The increasedecrease was primarily due to increasesdecreases of $19$17 million in scheduled outage and maintenance costs at generation facilities and $7 million in employee compensation and benefits including pension costs, $10partially offset by an increase of $3 million in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management costs, $7 million infor integrated transmission and distribution costs primarily related to overhead line maintenance, and $6 million in scheduled outage-related costs.system billings. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
Allowance for Equity Funds Used During ConstructionIncome Taxes
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$9 150.0
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$20 14.3
In the first quarter 2015, AFUDC equity was $152016, income taxes were $160 million compared to $6$140 million in the corresponding period in 2014.2015. The increase was primarily due to an increase in construction related to ongoing environmental and transmission projects.
Income Taxes
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(26) (15.7)
In the first quarter 2015, income taxes were $140 million compared to $166 million for the corresponding period in 2014. The decrease in income taxes was primarily due to lowerhigher pre-tax earnings and an increase in non-taxable AFUDC equity.earnings.
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 are 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. ChangesDemand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by 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 andwhich 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.modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. 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.

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Environmental Statutes and Regulations
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Retail Regulatory Matters Integrated Resource Plans" of Georgia Power in Item 7 of the Form 10-K and "Retail Regulatory Matters Integrated Resource Plan" herein for additional information on planned unit retirements and fuel conversions at Georgia Power.
Coal Combustion ResidualsAir Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Coal Combustion Residuals"Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.final MATS rule and regional haze regulations.
On April 17,25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published the Disposalits supplemental finding regarding consideration of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule)costs in the Federal Register, setting October 14, 2015 as the effective datesupport of the CCR Rule.MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Georgia Power units that are subject to the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the CCR Ruleproposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this timetime.and 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 expects to record incremental asset retirement obligations of approximately $10 million to $20 million related to the CCR Rule in the second quarter 2015.
FERC Matters
Georgia 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 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 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 has directed the traditional operating companies (including Georgia Power) and Southern Power, within 60 days, 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. Georgia Power is evaluating the order. 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 currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, ECCR

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tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Fuel Cost Recovery" below and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery and the NCCR tariff, respectively.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) will retain the merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, net merger savings will be shared on a 60/40 basis between customers and the Utilities; thereafter, all merger savings will be retained by customers. 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.information regarding the 2013 ARP.
Renewables Development
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" of Georgia Power in Item 7 of the Form 10-K for information regarding renewable energy projects.
As part of the Georgia Power Advanced Solar Initiative, program, Georgia Power executed tenfour PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515totaling 149 MWs of solar capacity. These PPAs are expected to commence in December 2015 and 2016 and have terms rangingcontracted capacity from 20 to 30 years. As a result of certain acquisitions by Southern Power Georgia Power expects that 229 MWs ofbegan in the 515 MWs will be purchased from solar facilities owned or under development by Southern Power.first quarter 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 Unit 7 and is underway at Plant Yates Unit 6. Plant Yates Unit 7 was returned to service on May 4, 2015 and Plant Yates Unit 6 is expected to return to service in mid-2015.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. On January 20, 2015, the Georgia PSC approved the deferral of Georgia Power's next fuel case filing until at least June 30, 2015.
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.
Nuclear Construction
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction"Fuel Cost Recovery" of Georgia Power in Item 7 andof the Form 10-K for information regarding fuel cost recovery.
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On April 14, 2016, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 15% effective June 1, 2016, which is expected to reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017. The ultimate outcome of this matter cannot be determined at this time.

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Nuclear Construction
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 additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and pending litigation.the Contractor Settlement Agreement (as defined below).
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. 4 (Vogtle 3 and 4 Agreement).
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 isguarantees, 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

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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%.
On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.)WECTEC under the Vogtle 3 and 4 Agreement arewere originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (a(which is now a subsidiary of Chicago Bridge & Iron Company, N.V.)CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. 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. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.
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 workGeorgia PSC voted to begin oncertify construction of 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). 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 has subsequently asserted related minimum damages (based on Georgia Power's ownership interest) of $113 million. 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.
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% above the certified cost 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. In February 2013, Georgia Power's eighth VCM report filed in 2013Power 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 (from April 2016) and the fourth

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quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into bybetween Georgia Power and the Georgia PSC staffStaff (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
On April 15, 2015, 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 does not believe that the Contractor's revised forecast reflects all efforts that may be possible to mitigate the Contractor's delay. In addition, 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. Consistentissued a procedural order in connection 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

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Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated owner'sVogtle 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 Pursuant 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 aPSC's 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 and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.
On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $241 million had been paid as of March 31, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.
On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. The Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.
The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate

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for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.
The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.7 billion as of March 31, 2016.
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 may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the DCDWestinghouse Design Control Document and the COLs,combined construction and operating licenses, 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 tomay 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.

63

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


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.
AdditionalFuture claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely tocould arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement but alsoand, under the enhanced dispute resolution procedures, may be resolved through litigation.litigation after the completion of nuclear fuel load for both units.
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 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 Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein

63

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


or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia 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.
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, ContingentAsset Retirement Obligations, and Pension and Other Postretirement Benefits.Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015,February 25, 2016, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Georgia Power continuesASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

64

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


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 inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Georgia Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Georgia Power's balance sheet.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Georgia Power currently reflects unamortized debt issuance costsrecognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in other deferred chargesadditional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Georgia Power is currently evaluating the new standard and assets onhas not yet determined 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.ultimate impact.
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 March 31, 2015.2016. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements 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 $363$563 million for the first three months of 20152016 compared to $499$363 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to lower operating revenues, partially offset by increased fuel cost recovery.the timing of vendor payments. Net cash used for investing activities totaled $405$689 million for the first three months of 20152016 compared to $480

64

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


$405 million for the corresponding period in 20142015 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, and purchases of nuclear fuel.facilities. Net cash provided from financing activities totaled $431$119 million for the first three months of 20152016 compared to $31$431 million used for financing activities in the corresponding period in 2014.2015. The increasedecrease in cash provided from financing activities is primarily due to a maturity of senior notes and a reduction in short-term debt, partially offset by senior note issuances and an increase in short-term debt borrowings.capital contributions received from 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 three months of 20152016 include increasesan increase in long-term debt of $378$398 million primarily related to issuances of senior notes, an increase of $374 million in property, plant, and equipment $684to comply with environmental standards and construction of generation, transmission, and distribution facilities, and an increase of $229 million in short-term debt, and $389 million in cash and cash equivalents.paid-in capital primarily due to capital contributions received from Southern Company.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, 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 $1.6 billion$458 million will be required through March 31, 20162017 to fund maturities of long-term debt. See "Sources of Capital" 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; 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; 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

65

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


"Retail "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, external security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which may be used to reimburse Georgia Power for eligible costsEligible 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 costs)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. Eligible Project Costs incurred through March 31, 2016 would allow for borrowings

65

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


of up to $2.5 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.2 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 March 31, 2015 would allow for borrowings of up to $2.1 billion under the FFB Credit Facility. Through March 31, 2015, Georgia Power has borrowed $1.2 billion under the FFB Credit Facility, leaving $0.9 billion of available borrowing ability.
As of March 31, 2015,2016, Georgia Power's current liabilities exceeded current assets by $1.7 billion$262 million primarily due to approximately $2.4 billion of long-term debt due within one year and notes payable. In 2015,year. 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 FFB borrowings, commercial paper, lines of credit, bank notes, and external securities issuances, as market conditions permit, and equity contributions from Southern Company to 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 March 31, 2015,2016, Georgia Power had approximately $413$60 million of cash and cash equivalents. CommittedGeorgia Power's committed credit arrangementsarrangement with banks at March 31, 2015 were2016 was $1.75 billion of which $1.73 billion was unused. This credit arrangement expires in 2020.
This bank credit arrangement contains a covenant that limits debt levels and contains a cross acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. Georgia Power is currently in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as follows:
Expires   Due Within One Year
2016 2018 Total Unused Term Out 
No Term
Out
(in millions) (in millions) (in millions)
$150
 $1,600
 $1,750
 $1,736
 $
 $150
needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
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.
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 program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 20152016 was approximately $865$868 million. In addition, at March 31, 2015,2016, Georgia Power had $118$69 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketedreoffered within the next 12 months. Subsequent to March 31, 2015, $65

66

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


million of these fixed rate pollution control revenue bonds were purchased and are being held by Georgia Power and currently are not required to be remarketed within the next 12 months.
Georgia Power's 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 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.
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
March 31, 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 $590
 0.3% $272
 0.3% $678
Short-term bank debt 250
 0.8% 3
 0.8% 250
Total $840
 0.4% $275
 0.3%  
  
Short-term Debt During the Period(*)
  
Average
Amount
Outstanding
 
Weighted
Average
Interest Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)
Commercial paper $29
 0.7% $158
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.2016. No short-term debt was outstanding at March 31, 2016.
Georgia Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, short-term bank notes, and operating cash flows.

66

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


Credit Rating Risk
Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, interest rate derivatives,transmission, and construction of new generation. generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at March 31, 20152016 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB- and/or Baa3$24
$93
Below BBB- and/or Baa31,424
$1,247
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.

67

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


Additionally, a credit rating downgrade could impact the ability of Georgia Power'sPower to access capital markets and would be likely to impact the short-term debt market and the variable rate pollution control revenue bond market.cost at which it does so.
Financing Activities
In January 2016, $4.085 million aggregate principal amount of Savannah Economic Development Authority Pollution Control Revenue Bonds (Savannah Electric and Power Company Project), First Series 1993 matured.
In March 2015,2016, Georgia Power entered into a three-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was forissued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes.
Subsequent to March 31, 2015,of 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), SecondPower's Series 2008. Georgia Power may reoffer these bonds to the public at a later date.
Also subsequent to March 31, 2015, Georgia Power redeemed $125 million aggregate principal amount of its Series Y 5.80%2013B Floating Rate Senior Notes due AprilMarch 15, 2035; as2016, to repay a result,portion of Georgia Power reclassified the outstanding principal balance to securities due within one year at March 31, 2015.Power's short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

6867



GULF POWER COMPANY

6968



GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015
20142016 2015
(in millions)(in millions)
Operating Revenues:      
Retail revenues$293
 $303
$283
 $293
Wholesale revenues, non-affiliates25
 36
16
 25
Wholesale revenues, affiliates22
 53
21
 22
Other revenues17
 15
15
 17
Total operating revenues357
 407
335
 357
Operating Expenses:      
Fuel110
 168
94
 110
Purchased power, non-affiliates25
 15
30
 25
Purchased power, affiliates9
 7
2
 9
Other operations and maintenance93
 84
77
 93
Depreciation and amortization20
 32
38
 20
Taxes other than income taxes28
 27
29
 28
Total operating expenses285
 333
270
 285
Operating Income72
 74
65
 72
Other Income and (Expense):      
Allowance for equity funds used during construction4
 2

 4
Interest expense, net of amounts capitalized(13) (13)(13) (13)
Other income (expense), net(1) (1)(1) (1)
Total other income and (expense)(10) (12)(14) (10)
Earnings Before Income Taxes62
 62
51
 62
Income taxes23
 23
20
 23
Net Income39
 39
31
 39
Dividends on Preference Stock2
 2
2
 2
Net Income After Dividends on Preference Stock$37
 $37
$29
 $37
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 For the Three Months
Ended March 31,
 2015 2014
 (in millions)
Net Income$39
 $39
Other comprehensive income (loss)
 
Comprehensive Income$39
 $39
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

70



GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Three Months
Ended March 31,
 2015 2014
 (in millions)
Operating Activities:   
Net income$39
 $39
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total22
 34
Deferred income taxes27
 14
Allowance for equity funds used during construction(4) (2)
Other, net11
 2
Changes in certain current assets and liabilities —   
-Receivables12
 (25)
-Fossil fuel stock(2) 46
-Prepaid income taxes3
 10
-Other current assets2
 1
-Accounts payable(28) 6
-Accrued taxes5
 9
-Accrued compensation(16) (5)
-Other current liabilities10
 13
Net cash provided from operating activities81
 142
Investing Activities:   
Property additions(84) (79)
Cost of removal, net of salvage(5) (3)
Other investing activities(3) (1)
Net cash used for investing activities(92) (83)
Financing Activities:   
Increase (decrease) in notes payable, net40
 (75)
Proceeds — Common stock issued to parent20
 50
Payment of preference stock dividends(2) (2)
Payment of common stock dividends(33) (31)
Other financing activities2
 
Net cash provided from (used for) financing activities27
 (58)
Net Change in Cash and Cash Equivalents16
 1
Cash and Cash Equivalents at Beginning of Period39
 22
Cash and Cash Equivalents at End of Period$55
 $23
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $2 and $1 capitalized for 2015 and 2014, respectively)$3
 $5
Income taxes, net(8) (6)
Noncash transactions — Accrued property additions at end of period41
 33
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

71



GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At March 31,
2015
 At December 31,
2014
  (in millions)
Current Assets:    
Cash and cash equivalents $55
 $39
Receivables —    
Customer accounts receivable 79
 73
Unbilled revenues 52
 58
Under recovered regulatory clause revenues 53
 57
Other accounts and notes receivable 9
 8
Affiliated companies 1
 10
Accumulated provision for uncollectible accounts (2) (2)
Fossil fuel stock, at average cost 104
 101
Materials and supplies, at average cost 54
 56
Other regulatory assets, current 77
 74
Prepaid expenses 38
 40
Other current assets 2
 2
Total current assets 522
 516
Property, Plant, and Equipment:    
In service 4,405
 4,495
Less accumulated provision for depreciation 1,236
 1,296
Plant in service, net of depreciation 3,169
 3,199
Other utility plant, net 79
 
Construction work in progress 474
 465
Total property, plant, and equipment 3,722
 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 423
 416
Other deferred charges and assets 37
 41
Total deferred charges and other assets 519
 513
Total Assets $4,778
 $4,708
 For the Three Months
Ended March 31,
 2016 2015
 (in millions)
Net Income$31
 $39
Other comprehensive income (loss):   
Qualifying hedges:   
Changes in fair value, net of tax of $(2) and $-, respectively(3) 
Total other comprehensive income (loss)(3) 
Comprehensive Income$28
 $39
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.


7269



GULF POWER COMPANY
CONDENSED BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
 
Liabilities and Stockholder's Equity At March 31,
2015
 At December 31,
2014
  (in millions)
Current Liabilities:    
Securities due within one year $23
 $
Notes payable 150
 110
Accounts payable —    
Affiliated 68
 87
Other 49
 56
Customer deposits 35
 35
Other accrued taxes 14
 9
Accrued interest 21
 11
Accrued compensation 7
 23
Deferred capacity expense, current 22
 22
Liabilities from risk management activities 37
 37
Other current liabilities 24
 23
Total current liabilities 450
 413
Long-term Debt 1,347
 1,370
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 836
 800
Employee benefit obligations 120
 121
Other cost of removal obligations 218
 235
Other regulatory liabilities, deferred 45
 49
Deferred capacity expense 158
 163
Other deferred credits and liabilities 120
 101
Total deferred credits and other liabilities 1,497
 1,469
Total Liabilities 3,294
 3,252
Preference Stock 147
 147
Common Stockholder's Equity:    
Common stock, without par value —    
Authorized — 20,000,000 shares    
Outstanding — March 31, 2015: 5,642,717 shares    
                — December 31, 2014: 5,442,717 shares 503
 483
Paid-in capital 563
 560
Retained earnings 272
 267
Accumulated other comprehensive loss (1) (1)
Total common stockholder's equity 1,337
 1,309
Total Liabilities and Stockholder's Equity $4,778
 $4,708
 For the Three Months
Ended March 31,
 2016 2015
 (in millions)
Operating Activities:   
Net income$31
 $39
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total40
 22
Deferred income taxes9
 27
Allowance for equity funds used during construction
 (4)
Other, net(2) 11
Changes in certain current assets and liabilities —   
-Receivables35
 12
-Fossil fuel stock15
 (2)
-Other current assets2
 5
-Accounts payable(6) (28)
-Accrued taxes13
 5
-Accrued compensation(18) (16)
-Other current liabilities13
 10
Net cash provided from operating activities132
 81
Investing Activities:   
Property additions(32) (84)
Cost of removal, net of salvage(2) (5)
Change in construction payables(6) (1)
Other investing activities(2) (2)
Net cash used for investing activities(42) (92)
Financing Activities:   
Increase (decrease) in notes payable, net(85) 40
Proceeds — Common stock issued to parent
 20
Payment of common stock dividends(30) (33)
Other financing activities(1) 
Net cash provided from (used for) financing activities(116) 27
Net Change in Cash and Cash Equivalents(26) 16
Cash and Cash Equivalents at Beginning of Period74
 39
Cash and Cash Equivalents at End of Period$48
 $55
Supplemental Cash Flow Information:   
Cash paid (received) during the period for --   
Interest (net of $- and $2 capitalized for 2016 and 2015, respectively)$3
 $3
Income taxes, net(25) (8)
Noncash transactions — Accrued property additions at end of period15
 41
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

7370



GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At March 31,
2016
 At December 31,
2015
  (in millions)
Current Assets:    
Cash and cash equivalents $48
 $74
Receivables —    
Customer accounts receivable 64
 76
Unbilled revenues 52
 54
Under recovered regulatory clause revenues 21
 20
Income taxes receivable, current 
 27
Other accounts and notes receivable 5
 9
Affiliated companies 8
 1
Accumulated provision for uncollectible accounts (1) (1)
Fossil fuel stock, at average cost 93
 108
Materials and supplies, at average cost 58
 56
Other regulatory assets, current 90
 90
Other current assets 18
 22
Total current assets 456
 536
Property, Plant, and Equipment:    
In service 5,058
 5,045
Less accumulated provision for depreciation 1,324
 1,296
Plant in service, net of depreciation 3,734
 3,749
Other utility plant, net 60
 62
Construction work in progress 57
 48
Total property, plant, and equipment 3,851
 3,859
Other Property and Investments 4
 4
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 60
 61
Other regulatory assets, deferred 420
 427
Other deferred charges and assets 37
 33
Total deferred charges and other assets 517
 521
Total Assets $4,828
 $4,920
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 March 31,
2016
 At December 31,
2015
  (in millions)
Current Liabilities:    
Securities due within one year $110
 $110
Notes payable 56
 142
Accounts payable —    
Affiliated 46
 55
Other 42
 44
Customer deposits 36
 36
Accrued taxes —    
Accrued income taxes 10
 4
Other accrued taxes 16
 9
Accrued interest 20
 9
Accrued compensation 8
 25
Deferred capacity expense, current 22
 22
Other regulatory liabilities, current 22
 22
Liabilities from risk management activities 54
 49
Other current liabilities 38
 40
Total current liabilities 480
 567
Long-term Debt 1,193
 1,193
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 899
 893
Employee benefit obligations 128
 129
Deferred capacity expense 136
 141
Asset retirement obligations 114
 113
Other cost of removal obligations 233
 233
Other regulatory liabilities, deferred 45
 47
Other deferred credits and liabilities 100
 102
Total deferred credits and other liabilities 1,655
 1,658
Total Liabilities 3,328
 3,418
Preference Stock 147
 147
Common Stockholder's Equity:    
Common stock, without par value —    
Authorized - 20,000,000 shares    
Outstanding - March 31, 2016: 5,642,717 shares    
                  - December 31, 2015: 5,642,717 shares 503
 503
Paid-in capital 569
 567
Retained earnings 284
 285
Accumulated other comprehensive loss (3) 
Total common stockholder's equity 1,353
 1,355
Total Liabilities and Stockholder's Equity $4,828
 $4,920
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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

FIRST QUARTER 20152016 vs. FIRST QUARTER 2014

2015


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, 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. AppropriatelyEffectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
Through 2015, capacity revenues from long-term non-affiliate sales out of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) represented the majority of Gulf Power's wholesale earnings. The capacity revenues associated with these contracts covering 100% of Gulf Power's ownership represented 82% of wholesale capacity revenues in 2015. Due to the expiration of a wholesale contract at the end of 2015 and another wholesale contract at the end of May 2016, Gulf Power's remaining contracted sales from the unit from June 2016 through 2019 will cover approximately 24% of the unit. The expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. The alternatives Gulf Power is actively evaluating include, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as the contracts expire. The ultimate outcome of this matter cannot be determined at this time.
In 2013, the Florida PSC voted to approve the settlement agreement (Rate Case Settlement Agreement) among Gulf Power and all of the intervenors to Gulf Power's retail base rate case. Under the terms of the Rate Case Settlement Agreement, Gulf Power (1) increased base rates approximately $35 million annually effective January 2014 and subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); (3) may reduce depreciation and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017, of which $34.1 million had been recorded as of March 31, 2016; and (4) is accruing a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until the next base rate adjustment date or January 1, 2017, whichever comes first. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" herein for additional details of the Rate Case Settlement Agreement.
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.

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

RESULTS OF OPERATIONS
Net Income
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(8) (21.6)
Gulf Power's net income after dividends on preference stock for the first quarter 2015 and2016 was $29 million compared to $37 million for the corresponding period in 20142015. The decrease was $37 million. Net income for the first quarter 2015 was positively impacted by a reductionprimarily due to an increase in depreciation expense, as authorized by the Florida PSC, which was largelyand a decrease in non-affiliated wholesale capacity revenues, partially offset by higherlower operations and maintenance expenses.
Retail Revenues
First Quarter 2015 vs. First Quarter 2014
First Quarter 2016 vs. First Quarter 2015First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change) (% change)
$(10) (3.3) (3.4)
In the first quarter 2015,2016, retail revenues were $293$283 million compared to $303$293 million for the corresponding period in 2014.2015.
Details of the changes in retail revenues were as follows:
 First Quarter
2015
 First Quarter 2016
 (in millions) (% change) (in millions) (% change)
Retail – prior year $303
   $293
  
Estimated change resulting from –        
Rates and pricing 4
 1.3
 7
 2.4
Sales decline (2) (0.7)
Sales growth 2
 0.7
Weather 
 
 (4) (1.4)
Fuel and other cost recovery (12) (3.9) (15) (5.1)
Retail – current year $293
 (3.3)% $283
 (3.4)%
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under

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

"Revenues" "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 first quarter 20152016 when compared to the corresponding period in 20142015 primarily due to an increase in retail base rates effective in January 2015 and higher revenues associated with an increase in the environmental andcost recovery clause rate, partially offset by a decrease in the energy conservation cost recovery clause ratesrate, both effective in January 2015.2016.
Revenues attributable to changes in sales decreasedincreased in the first quarter 20152016 when compared to the corresponding period in 2014.2015. For the first quarter 2016, weather-adjusted KWH energy sales to residential customers increased 2.8% due to customer growth and higher customer usage. Weather-adjusted KWH energy sales to residential and commercial customers decreased 5.2% and 2.0%, respectively,increased 0.1% due to customer growth, mostly offset by lower customer usage, partially offset by customer growth.usage. KWH energy sales to industrial customers decreased 2.5%increased 7.1% for the first quarter 2016 primarily due to increaseddecreased customer co-generation.co-generation, partially offset by changes in customers' operations.

74

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

Fuel and other cost recovery revenues decreased in the first quarter 20152016 when compared to the corresponding period in 20142015 primarily due to lower revenues associated with recoverablea decrease in the fuel cost recovery rate effective in January 2016 and a decrease in fuel costs foras the result of decreased generation and lower purchased power costs, partially offset by higher revenues associated with increased recoverable costs under Gulf Power's purchased power capacity cost recovery clause.energy 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 Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(11) (30.6)
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(9) (36.0)
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 energy is generally sold at variable cost. 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 first quarter 2015,2016, wholesale revenues from sales to non-affiliates were $25$16 million compared to $36$25 million for the corresponding period in 2014.2015. The decrease was primarily due to a 59.7%42.2% decrease in capacity revenues resulting from the expiration of a Plant Scherer Unit 3 sales agreement and a 23.9% decrease in KWH sales resulting from lower sales under the remaining Plant Scherer Unit 3 long-term sales agreements due to a planned outage and lower natural gas prices that led to increased customer generation.
Wholesale Revenues – Affiliates
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(31) (58.5)
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

75

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

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 first quarter 2015, wholesale revenues from sales to affiliates were $22 million compared to $53 million for the corresponding period in 2014. The decrease was primarily due to a 28.5% decrease in the price of energy sold to affiliates due to lower pool interchange rates resulting from lower natural gas prices and a 40.8% decrease in KWH sales that resulted from more planned outages for Gulf Power generation resources.prices.
Fuel and Purchased Power Expenses
  First Quarter 2015
vs.
First Quarter 2014
  First Quarter 2016
vs.
First Quarter 2015
 (change in millions) (% change) (change in millions) (% change)
Fuel $(58) (34.5) $(16) (14.5)
Purchased power – non-affiliates 10
 66.7
 5
 20.0
Purchased power – affiliates 2
 28.6
 (7) (77.8)
Total fuel and purchased power expenses $(46)   $(18)  
In the first quarter 2015,2016, total fuel and purchased power expenses were $144$126 million compared to $190$144 million for the corresponding period in 2014.2015. The decrease was primarily the result of a $39 million decrease in the volume of KWHs generated and purchased due to more planned outages for Gulf Power's generation and a resource contracted under a PPA and a $7$23 million decrease due to the lower average cost of fuel and purchased power.power as a result of lower generation from Gulf Power's coal-fired resources, partially offset by a $5 million increase related to the volume of KWHs generated due to higher generation from Gulf Power's gas-fired resources.
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 cost recovery clauses.clauses and long-term wholesale contracts. 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" in Item 8 of the Form 10-K for additional information.

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

Details of Gulf Power's generation and purchased power were as follows:
 First Quarter
2015
 First Quarter
2014
 First Quarter 2016 First Quarter 2015
Total generation (millions of KWHs)
 2,236 2,962 1,816 2,236
Total purchased power (millions of KWHs)
 1,259 1,430 1,760 1,259
Sources of generation (percent) –
  
Coal 59 70 42 59
Gas 41 30 58 41
Cost of fuel, generated (cents per net KWH) –
  
Coal 3.98 4.31 3.92 3.98
Gas 3.95 3.66 3.75 3.95
Average cost of fuel, generated (cents per net KWH)
 3.97 4.11 3.82 3.97
Average cost of purchased power (cents per net KWH)(*)
 4.36 4.79 3.22 4.36
(*)Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.
Fuel
In the first quarter 2015,2016, fuel expense was $110$94 million compared to $168$110 million for the corresponding period in 2014.2015. The decrease was primarily due to a 24.5%41.1% decrease in the volume of KWHs generated due to more planned outages forby Gulf Power's coal-fired generation resources and a resource contracted under a PPA3.8% decrease in the first quarter 2015.

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Tableaverage cost of Contentsfuel, partially offset by a 12.7% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Non-Affiliates
In the first quarter 2015,2016, purchased power expense from non-affiliates was $25$30 million compared to $15$25 million for the corresponding period in 2014.2015. The increase was primarily due to ana 73.8% increase in the average cost per KWH purchased, which included a $16 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA in mid-2014. The increase was partially offset by a 25.2% decrease in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a planned outage for a resource contracted under a PPA.32.2% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired market resources.
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 first quarter 2015,2016, purchased power expense from affiliates was $9$2 million compared to $7$9 million for the corresponding period in 2014.2015. The increasedecrease was primarily due to an 87.8% increasea 62.4% decrease in the volume of KWHs purchased due to more planned outages for Gulf Power's generationlower territorial loads resulting from milder weather and a resource contracted under a PPA, partially offset by a 33.2%39.4% decrease in the average cost per KWH purchased.purchased due to lower power pool interchange rates as a result of lower natural gas prices and lower off-peak energy prices of renewable market resources.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

76

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

Other Operations and Maintenance Expenses
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$9 10.7
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(16) (17.2)
In the first quarter 2015,2016, other operations and maintenance expenses were $93$77 million compared to $84$93 million for the corresponding period in 2014.2015. The decrease was primarily due to a decrease of $11 million in scheduled generation outage expenses.
Depreciation and Amortization
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$18 90.0
In the first quarter 2016, depreciation and amortization was $38 million compared to $20 million for the corresponding period in 2015. The increase was primarily due to increases$14 million less of $7 milliona reduction in routine and planned maintenance expense at generation facilities and $2 milliondepreciation in employee compensation and benefits including pension costs. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
Depreciation and Amortization
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(12) (37.5)
In the first quarter 2015, depreciation and amortization was $20 millionthree months of 2016 compared to $32 million for the corresponding period in 2014. As2015, as authorized by the Florida PSC in a settlement agreement, Gulf Power recorded a $19.6 million reduction in depreciation expense in the first quarter 2015 as compared to $6.2 million in the corresponding period in 2014. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" of Gulf Power in Item 7Case Settlement Agreement, and property additions at generation, transmission, and distribution facilities.
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 and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" herein for additional information.

77

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

Allowance for Equity Funds Used During Construction
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$2 100.0
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(4) (100.0)
In the first quarter 2015,2016, AFUDC equity was $4 millionimmaterial compared to $2$4 million for the corresponding period in 2014.2015. The increasedecrease was primarily due to increased construction related to environmental control projects at generation facilities and transmission facilities.projects being placed in service in 2015.
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 growing sales which are subject to a number of factors. These factors include weather, competition, energy conservation practiced by customers, the use of alternative energy sources 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. ChangesDemand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by 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 andwhich 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 other Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating

77

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

plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's co-ownershipownership of a unit with Georgia Power at Plant Scherer Unit 3 (205 MWs) and consist of both capacity and energy sales. CapacityThrough 2015, capacity revenues representfrom long-term non-affiliate sales out of Gulf Power's ownership of the unit represented the majority of Gulf Power's wholesale earnings. Gulf Power currently has long-term sales agreements forThe capacity revenues associated with these contracts covering 100% of Gulf Power's ownership of that unit through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively pursuing replacement wholesale contracts butin 2015. Due to the expiration of currenta wholesale contract at the end of 2015 and another wholesale contract at the end of May 2016, Gulf Power's remaining contracted sales from the unit from June 2016 through 2019 will cover approximately 24% of the unit. The expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts couldwill have a material negative impact on Gulf Power's earnings. Inearnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. The alternatives Gulf Power is actively evaluating include, without limitation, rededication of the event some portionasset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer is not subjectUnit 3 as being in service to a replacement long-term wholesale contract,retail customers when and as the proportionate amountcontracts expire. The ultimate outcome of the unit maythis matter cannot be sold into the power pool or into the wholesale market.determined at this time.
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 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.modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. 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

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

DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" andMatters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery"Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Coal Combustion ResidualsAir Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Coal Combustion Residuals"Air Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.final MATS rule and regional haze regulations.
On April 17,25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published the Disposalits supplemental finding regarding consideration of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule)costs in the Federal Register, setting October 14, 2015 as the effective datesupport of the CCR Rule.MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Gulf Power units that are subject to the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the CCR Ruleproposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this timetime.and will depend on Gulf Power's ongoing review

78

FERC MattersGULF POWER COMPANY
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 has directed the traditional operating companies (including Gulf Power) and Southern Power, within 60 days, 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. Gulf Power is evaluating the order. The ultimate outcome of this matter cannot be determined at this time.MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for specific 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 Form 10-K for additional information.
Retail Base Rate Case
In December 2013, the Florida PSC approved a settlement agreementthe Rate Case Settlement Agreement providing 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 retail 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 inFor 2014, 2015, and the first three months of 2015.

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Table2016, Gulf Power recognized reductions in depreciation of Contents$8.4 million, $20.1 million, and $5.6 million, respectively.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "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. See Note (B) to the Condensed Financial Statements herein for additional information.
Renewables
The Florida PSC preliminarily approvedissued a final approval order on Gulf Power's Community Solar Pilot Program on April 16, 2015, three energy purchase agreements totaling 120 MWs15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of utility-scalea solar generation located at three military installations in northwest Florida. These contracts are expected to begin in 2016photovoltaic facility with a termelectric generating capacity of 25 years each. The Florida PSC preliminarily approved on May 5, 2015, an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma.1 MW through annual subscriptions. The agreementenergy generated from the solar facility is expected to beginprovide power to all of Gulf Power's customers.
Other Matters
As a result of the cost to comply with environmental regulations imposed by the endEPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. In connection with this retirement announcement, Gulf Power reclassified the net carrying value of 2015these units from plant in service, net of depreciation, to other utility plant, net. The net book value of these units at March 31, 2016 was approximately $60 million. Gulf Power has filed a petition with the Florida PSC requesting permission to create a termregulatory asset for the remaining net book value of 20 years. Purchases underPlant Smith Units 1 and 2 and the remaining inventory associated with these agreements will be for energy only and areunits as of the retirement date. The retirement of these units is not expected to be recovered throughhave a material impact on Gulf Power's fuel cost recovery mechanism. Thefinancial statements as Gulf Power expects to recover these amounts through its rates; however, the ultimate outcome of these mattersdepends on future rate proceedings with the Florida PSC and cannot be determined at this time.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the

79

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

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 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 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.
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, ContingentAsset Retirement Obligations, and Pension and Other Postretirement Benefits.Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015,February 25, 2016, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Gulf PowerASU No. 2016-02,

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

continuesLeases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees 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 inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Gulf Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Gulf Power's balance sheet.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Gulf Power currently reflects unamortized debt issuance costsrecognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in other deferred chargesadditional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Gulf Power is currently evaluating the new standard and assets onhas not yet determined 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.ultimate impact.
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 March 31, 2015.2016. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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

Net cash provided from operating activities totaled $81$132 million for the first three months of 20152016 compared to $142$81 million for the corresponding period in 2014.2015. The $61$51 million decreaseincrease in net cash was primarily due to decreases in cash flows related toa federal income tax refund and the timing of fossil fuel stock purchases and decreases in accounts payable, partially offset by increases in the recovery of fuel costs.vendor payments. Net cash used for investing activities totaled $92$42 million in the first three months of 20152016 primarily due to property additions related to steam generation and transmission.utility plant. Net cash provided fromused for financing activities totaled $27$116 million for the first three months of 20152016 primarily due to an increase inpayments related to notes payable and the issuance of common stock, partially offset by the payment of common stock dividends. 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 three months of 20152016 include increasesdecreases of $58 million in net property, plant, and equipment, $40$86 million in notes payable, $36$27 million of income tax receivables following the receipt of a federal income tax refund, and $26 million in accumulated deferred income tax liabilities,cash and the reclassification of $23 million of long-term debt to debt due within one year.cash equivalents.
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, and trust funding requirements, and unrecognized tax benefits.requirements. Approximately $23$235 million will be required through March 31, 20162017 to fund the repaymenta maturity of long-term debt due within one year.and an announced redemption of long-term debt. 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.

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Sources of Capital
Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external 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, including its commercial paper program which is supported by bank credit facilities.
At March 31, 2015,2016, Gulf Power had approximately $55$48 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 20152016 were as follows:
ExpiresExpires     
Executable Term
Loans
 
Due Within One
Year
Expires     
Executable Term
Loans
 
Due Within One
Year
2015 2016 2017 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
(in millions) (in millions) (in millions) (in millions)
20162016 2017 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
   (in millions) (in millions) (in millions)
$45
 $200
 $30
 $275
 $275
 $50
 $
 $50
 $195
75
 $40
 $165
 $280
 $280
 $45
 $
 $45
 $40

81

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

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 these bank credit arrangements contain covenants that limit debt levels and contain cross defaultacceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross defaultacceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, or guarantee obligations over a specified threshold.the payment of which was then accelerated. 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. In connection therewith, Gulf Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Most of the unused credit arrangements with banks isare 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 March 31, 20152016 was approximately $69$82 million. In addition, at March 31, 2015,2016, Gulf Power had $78approximately $33 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
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.

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

Details of short-term borrowings were as follows:
  Short-term Debt at
March 31, 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 $150
 0.3% $110
 0.3% $150
  
Short-term Debt at
March 31, 2016
 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Commercial paper $56
 0.9% $77
 0.8% $148
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.2016.
Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.
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, transmission, and energy price risk management.

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

The maximum potential collateral requirements under these contracts at March 31, 20152016 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB- and/or Baa3$74
$78
Below BBB- and/or Baa3447
$428
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 the ability of Gulf Power's abilityPower to access capital markets particularlyand would be likely to impact the short-term debt market and the variable rate pollution control revenue bond market.cost at which it does so.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the first quarter 20152016 has not changed materially compared to the December 31, 20142015 reporting period. Gulf Power's exposure to market volatility in 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.
Through 2015, capacity revenues from long-term non-affiliate sales out of Gulf Power currently has long-term sales agreements forPower's ownership of Plant Scherer Unit 3 (205 MWs) represented the majority of Gulf Power's wholesale earnings. The capacity revenues associated with these contracts covering 100% of its wholesale capacity through 2015 and 41% through 2019. These capacity revenuesGulf Power's ownership represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively pursuing replacement wholesale contracts butin 2015. Due to the expiration of currenta wholesale contract at the end of 2015 and another wholesale contract at the end of May 2016, Gulf Power's remaining contracted sales from the unit from June 2016 through 2019 will cover approximately 24% of the unit. The expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts couldwill have a material negative impact on Gulf Power's earnings. Inearnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. The alternatives Gulf Power is actively evaluating include, without limitation, rededication of the event some portionasset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer is not subjectUnit 3 as being in service to a replacement long-term wholesale contract,retail customers when and as the proportionate amountcontracts expire. The ultimate outcome of the unit maythis matter cannot be sold into the power pool or into the wholesale market.determined at this time. 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.

83

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

Financing Activities
In January 2015, Gulf Power issued 200,000 shares of common stock to Southern Company and realized proceeds of $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 addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Subsequent to March 31, 2016, Gulf Power announced the redemption in May 2016 of $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.

8483


MISSISSIPPI POWER COMPANY

8584


MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF OPERATIONSINCOME (UNAUDITED)
 
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Operating Revenues:      
Retail revenues$167
 $207
$183
 $167
Wholesale revenues, non-affiliates77
 97
60
 77
Wholesale revenues, affiliates27
 23
9
 27
Other revenues5
 4
5
 5
Total operating revenues276
 331
257
 276
Operating Expenses:      
Fuel114
 147
76
 114
Purchased power, non-affiliates2
 11

 2
Purchased power, affiliates2
 9
5
 2
Other operations and maintenance73
 66
69
 73
Depreciation and amortization27
 23
38
 27
Taxes other than income taxes25
 20
26
 25
Estimated loss on Kemper IGCC9
 380
53
 9
Total operating expenses252
 656
267
 252
Operating Income (Loss)24
 (325)(10) 24
Other Income and (Expense):      
Allowance for equity funds used during construction28
 38
29
 28
Interest expense, net of amounts capitalized(11) (12)(16) (11)
Other income (expense), net(2) (3)(2) (2)
Total other income and (expense)15
 23
11
 15
Earnings (Loss) Before Income Taxes39
 (302)
Earnings Before Income Taxes1
 39
Income taxes (benefit)4
 (130)(10) 4
Net Income (Loss)35
 (172)
Net Income11
 35
Dividends on Preferred Stock
 

 
Net Income (Loss) After Dividends on Preferred Stock$35
 $(172)
Net Income After Dividends on Preferred Stock$11
 $35
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
 For the Three Months
Ended March 31,
 2015 2014
 (in millions)
Net Income (Loss)$35
 $(172)
Other comprehensive income (loss)
 
Comprehensive Income (Loss)$35
 $(172)
 For the Three Months
Ended March 31,
 2016 2015
 (in millions)
Net Income$11
 $35
Other comprehensive income (loss):
 
Comprehensive Income$11
 $35
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

8685


MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Operating Activities:      
Net income (loss)$35
 $(172)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —   
Net income$11
 $35
Adjustments to reconcile net income
to net cash provided from (used for) operating activities —
   
Depreciation and amortization, total26
 24
39
 26
Deferred income taxes141
 (124)(4) 141
Allowance for equity funds used during construction(28) (38)(29) (28)
Regulatory assets associated with Kemper IGCC(27) (13)(6) (27)
Estimated loss on Kemper IGCC9
 380
53
 9
Other, net11
 8
1
 11
Changes in certain current assets and liabilities —      
-Receivables17
 (14)45
 17
-Fossil fuel stock4
 37
6
 4
-Prepaid income taxes44
 (33)(3) 44
-Other current assets(3) (5)(5) (3)
-Accounts payable(22) 15
(22) (22)
-Accrued taxes(54) (55)(61) (54)
-Accrued interest9
 8
2
 9
-Accrued compensation(20) (2)(16) (20)
-Over recovered regulatory clause revenues22
 (18)9
 22
-Mirror CWIP40
 34

 40
Net cash provided from operating activities204
 32
-Customer liability associated with Kemper refunds(51) 
-Other current liabilities6
 
Net cash provided from (used for) operating activities(25) 204
Investing Activities:      
Property additions(213) (324)(197) (213)
Construction payables(14) (31)(7) (14)
Other investing activities(6) (6)(10) (6)
Net cash used for investing activities(233) (361)(214) (233)
Financing Activities:      
Proceeds —      
Capital contributions from parent company76
 1
1
 76
Interest-bearing refundable deposit
 75
Long-term debt issuance to parent company200
 
Other long-term debt issuances
 250
900
 
Short-term borrowings30
 

 30
Redemptions — Other long-term debt(75) 
Payment of preferred stock dividends
 
Return of capital
 (55)
Redemptions —   
Short-term borrowings(475) 
Other long-term debt(425) (75)
Other financing activities(1) (2)(2) (1)
Net cash provided from financing activities30
 269
199
 30
Net Change in Cash and Cash Equivalents1
 (60)(40) 1
Cash and Cash Equivalents at Beginning of Period133
 145
98
 133
Cash and Cash Equivalents at End of Period$134
 $85
$58
 $134
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —   
Interest (paid $17 and $17, net of $18 and $14 capitalized for 2015 and 2014, respectively)$(1) $3
Cash paid (received) during the period for --   
Interest (paid $22 and $17, net of $10 and $18 capitalized for 2016
and 2015, respectively)
$12
 $(1)
Income taxes, net(180) 26
(24) (180)
Noncash transactions — Accrued property additions at end of period100
 132
97
 100

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

8786


MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At March 31,
2015
 At December 31,
2014
 At March 31,
2016
 At December 31,
2015
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $134
 $133
 $58
 $98
Receivables —        
Customer accounts receivable 38
 43
 23
 26
Unbilled revenues 33
 35
 32
 36
Income taxes receivable, current 
 20
Other accounts and notes receivable 13
 11
 6
 10
Affiliated companies 40
 51
 7
 20
Accumulated provision for uncollectible accounts (1) (1)
Fossil fuel stock, at average cost 96
 100
 99
 104
Materials and supplies, at average cost 64
 62
 76
 75
Other regulatory assets, current 74
 73
 101
 95
Prepaid income taxes 162
 191
 42
 39
Other current assets 6
 6
 5
 8
Total current assets 659
 704
 449
 531
Property, Plant, and Equipment:        
In service 4,396
 4,378
 4,905
 4,886
Less accumulated provision for depreciation 1,194
 1,173
 1,287
 1,262
Plant in service, net of depreciation 3,202
 3,205
 3,618
 3,624
Construction work in progress 2,361
 2,161
 2,400
 2,254
Total property, plant, and equipment 5,563
 5,366
 6,018
 5,878
Other Property and Investments 6
 5
 11
 11
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 243
 226
 303
 290
Other regulatory assets, deferred 419
 385
 520
 525
Income taxes receivable, non-current 544
 544
Other deferred charges and assets 57
 71
 71
 61
Total deferred charges and other assets 719
 682
 1,438
 1,420
Total Assets $6,947
 $6,757
 $7,916
 $7,840
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.


8887


MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholder's Equity At March 31,
2015
 At December 31,
2014
 At March 31,
2016
 At December 31,
2015
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $3
 $778
 $303
 $728
Notes Payable 30
 
Interest-bearing refundable deposit 275
 275
Notes payable 25
 500
Accounts payable —        
Affiliated 80
 86
 82
 85
Other 148
 178
 108
 135
Accrued taxes —    
Accrued income taxes 185
 142
Other accrued taxes 29
 84
Customer deposits 16
 16
Accrued taxes 25
 85
Accrued interest 86
 76
 21
 18
Accrued compensation 6
 26
 10
 26
Asset retirement obligations, current 39
 22
Over recovered regulatory clause liabilities 23
 1
 106
 96
Mirror CWIP 311
 271
Customer liability associated with Kemper refunds 22
 73
Other current liabilities 61
 61
 55
 52
Total current liabilities 1,237
 1,978
 812
 1,836
Long-term Debt 2,328
 1,630
Long-term Debt:    
Long-term debt, affiliated 776
 576
Long-term debt, non-affiliated 2,206
 1,310
Total Long-term Debt 2,982
 1,886
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 397
 285
 771
 762
Deferred credits related to income taxes 8
 8
Accumulated deferred investment tax credits 282
 283
 5
 5
Employee benefit obligations 148
 148
 149
 153
Asset retirement obligations 49
 48
Asset retirement obligations, deferred 136
 154
Unrecognized tax benefits 368
 368
Other cost of removal obligations 168
 166
 167
 165
Other regulatory liabilities, deferred 65
 64
 71
 71
Other deferred credits and liabilities 43
 38
 41
 40
Total deferred credits and other liabilities 1,152
 1,032
 1,716
 1,726
Total Liabilities 4,717
 4,640
 5,510
 5,448
Redeemable Preferred Stock 33
 33
 33
 33
Common Stockholder's Equity:        
Common stock, without par value —        
Authorized — 1,130,000 shares        
Outstanding — 1,121,000 shares 38
 38
 38
 38
Paid-in capital 2,690
 2,612
 2,896
 2,893
Accumulated deficit (524) (559) (555) (566)
Accumulated other comprehensive loss (7) (7) (6) (6)
Total common stockholder's equity 2,197
 2,084
 2,373
 2,359
Total Liabilities and Stockholder's Equity $6,947
 $6,757
 $7,916
 $7,840
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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FIRST QUARTER 20152016 vs. FIRST QUARTER 20142015



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 maintainoperate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the completion and operation of major construction projects, primarily the Kemper 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.
In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC established by the Mississippi PSC was $2.4 billion with a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE(Initial 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).
On April 8, 2016, Mississippi Power's current cost estimatePower received approximately $137 million in additional grants from the DOE for the Kemper IGCC in total is approximately $6.22 billion,(Additional DOE Grants), which includes approximately $4.94 billion of costs subjectare expected to the construction cost cap. Mississippi Power does not intendbe used to seek anyreduce future rate recovery or joint owner contributionsimpacts for any related costs 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 $9 million ($6 million after tax) in the first quarter 2015. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.06 billion ($1.27 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through March 31, 2015.customers.
Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC project in servicein-service in August 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 third quarter 2016.
Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.58 billion, which includes approximately $5.35 billion of costs subject to the construction cost cap and is net of the Additional DOE Grants. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $53 million ($33 million after tax) in the first halfquarter 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2016. The current cost estimate includes costs through March 31,September 30, 2016. As
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a resultstipulation (the 2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to Kemper IGCC assets previously placed in service. On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the additional factors that haveIn-Service Asset Rate Order with the potentialMississippi Supreme Court (Court). On May 5, 2016, the Court dismissed the appeal. Further proceedings related to impact start-up and operational readiness activitiescost recovery for the Kemper IGCC are expected after the remainder of the Kemper IGCC is placed in service, which is currently expected to occur in the third quarter 2016. The ultimate outcome of these matters cannot be determined at this first-of-a-kind technology as described herein, the risk of further schedule extensions and/or cost increases, which could be material, remains.time.
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

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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 filed by Thomas A. Blanton 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 Settlement Agreement (defined below) between8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and the

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi PSC unenforceable due to a lack of public notice for the related proceedings, and directed the Mississippi PSC to enter an order requiringother general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to refundborrow the Mirror CWIP amounts collected pursuant to the 2013 MPSC Rate Order. As of March 31, 2015, $294remaining $300 million had been collected by Mississippi Power. On March 12, 2015,on or before October 15, 2016. Mississippi Power andused the Mississippi PSC filed motions for rehearing. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information.
Mississippi Power also expectsinitial proceeds to seek rate recovery through alternate means, which could include a traditional rate case. On May 1, 2015, Mississippi Power notified the Mississippi PSC of its plans to file a rate request in May 2015.
As of March 31, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $578 million primarily due to $275 million of refundable deposits from SMEPA and the potential refund of approximately $311 million in Mirror CWIP, which includes associated carrying costs. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" and " – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information. In addition, Mississippi Power hasrepay $900 million in maturing bank loans on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loans that matureloan pursuant to this agreement matures on April 1, 2016. Mississippi Power intends to utilize operating cash flows2018 and lines of credit, bank term loans, and commercial paper, as market conditions permit, as well as, under certain circumstances, equity contributions and/or loans from Southern Company, to fund Mississippi Power's short-term capital needs.bears interest based on one-month LIBOR.
Mississippi Power continues to focus on several key performance indicators, including the construction, start-up, and start-uprate 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 2015, as compared to the target.
RESULTS OF OPERATIONS
Net Income (Loss)
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$207N/M
N/M – Not meaningful
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(24) (68.6)
Mississippi Power's net income after dividends on preferred stock for the first quarter 20152016 was $35$11 million compared to a net loss after dividends on preferred stock of $172$35 million for the corresponding period in 2014.2015. The increasedecrease was primarily related to a lowerhigher pre-tax chargecharges of $53 million ($33 million after tax) in the first quarter 2016 compared to pre-tax charges of $9 million ($6 million after tax) in the first quarter 2015 compared to a pre-tax charge of $380 million ($235 million after tax) in the first quarter 2014 for revisions 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 Initial DOE Grants and excluding the Cost Cap Exceptions. The decrease in net income was also related to a decrease in wholesale revenues and an increase wasin depreciation and amortization, partially offset by a decrease in AFUDC equity, increases in non-fuel operations and maintenance expenses, and a decreasean increase in retail revenues primarily resulting fromrevenue due to the Court's decision.

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

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.
Retail Revenues
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(40) (19.3)
In the first quarter 2015, retail revenues were $167 million compared to $207 million for the corresponding period in 2014.
Details of the changes in retail revenues were as follows:
  First Quarter
2015
  (in millions)
(% change)
Retail – prior year $207
  
Estimated change resulting from –    
Rates and pricing (4) (1.9)
Sales decline (4) (1.9)
Weather (1) (0.5)
Fuel and other cost recovery (31) (15.0)
Retail – current year $167
 (19.3)%
Revenues associated with changes in rates and pricing decreased in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to not recognizing revenues associated with the Kemper IGCC cost recovery in 2015 as a result of the Court's decision, partially offset by $1 million in net revenues for the new energy efficiency cost recovery rate, which began in the 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 Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Retail Revenues attributable
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$16 9.6
In the first quarter 2016, retail revenues were $183 million compared to $167 million for the corresponding period in 2015. Details of the changes in sales decreasedretail revenues were as follows:

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  First Quarter 2016
  (in millions)
(% change)
Retail – prior year $167
  
Estimated change resulting from –    
Rates and pricing 26
 15.6
Sales growth 4
 2.4
Weather (3) (1.8)
Fuel and other cost recovery (11) (6.6)
Retail – current year $183
 9.6 %
Revenues associated with changes in rates and pricing increased in the first quarter 20152016 when compared to the corresponding period in 2014. Weather-adjusted KWH2015, primarily due to the implementation of rates for certain Kemper IGCC in-service assets.
See Note 3 to the financial statements of Mississippi Power under "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 to residential and commercial customers decreased 1.9% and 3.5%, respectively,increased in the first quarter 20152016 when compared to the corresponding period in 2015. Weather-adjusted KWH energy sales to residential customers increased 2.0% in the first quarter 2016 due to lowerincreased use per customer usage.and customer growth. Weather-adjusted KWH energy sales to commercial customers increased 0.5% in the first quarter 2016 due to customer growth. KWH energy sales to industrial customers increased 3.5%decreased 3.0% in the first quarter 20152016 due to increaseddecreased usage by larger customers.
In the first quarter 2015, Mississippi Power updated itsthe 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 first quarter 20142015 KWH sales among customer classes that is consistent with the actual allocation in 2015.2016. Without this adjustment, first quarter 20152016 weather-adjusted residential KWH sales decreased 9.9%increased 8.5%, weather-adjusted commercial KWH sales decreased 9.3%increased 8.7%, and industrial KWH sales increased 2.3% asdecreased 0.9% when compared to the corresponding period in 2014.2015.
Fuel and other cost recovery revenues decreased in the first quarter 20152016 when compared to the corresponding period in 2014,2015, primarily as a result of lower recoverable fuel 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(20) (20.6)
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(17) (22.1)
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. In addition, Mississippi Power serves long-term contracts with rural electric cooperative associations and municipalities located in

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

southeastern Mississippi under 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 and – FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.
In the first quarter 2015,2016, wholesale revenues from sales to non-affiliates were $77$60 million compared to $97$77 million for the corresponding period in 2014.2015. The decrease was primarily due to a $9 million decrease in capacity revenues primarily resulting from milder weather and decreased usage and an $8 million decrease in energy revenues primarily resulting from lower marketfuel prices.
Wholesale Revenues – Affiliates
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$4 17.4
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(18) (66.7)
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 this energy is generally sold at marginal cost.
In the first quarter 2015,2016, wholesale revenues from sales to affiliates were $27$9 million compared to $23$27 million for the corresponding period in 2014.2015. The increasedecrease was due to a $4 million increase in energy revenues primarily due to a $14 million increase associated with higher natural gasdecrease in KWH sales resulting from a decrease in sales from coal generation partially offset byand a $10$4 million decrease associated with lower natural gas prices.
Fuel and Purchased Power Expenses
 First Quarter 2015
vs.
First Quarter 2014
 First Quarter 2016
vs.
First Quarter 2015
 (change in millions)
(% change) (change in millions)
(% change)
Fuel $(33) (22.4) $(38) (33.0)
Purchased power – non-affiliates (9) (81.8) (2) (100.0)
Purchased power – affiliates (7) (77.8) 3
 150.0
Total fuel and purchased power expenses $(49)  $(37) 
In the first quarter 2015,2016, total fuel and purchased power expenses were $118$81 million compared to $167$118 million for the corresponding period in 2014.2015. The decrease was due to a $42$19 million decrease in the volume of KWHs generated and purchased and an $18 million decrease in the average cost of fuel and

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purchased power and an $11 million decrease in the volume of KWHs purchased, partially offset by a $4 million increase in the volume of KWHs generated.fuel.
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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Details of Mississippi Power's generation and purchased power were as follows:
 
First Quarter
2015
 
First Quarter
2014
 First Quarter 2016 First Quarter 2015
Total generation (millions of KWHs)(*)
 4,345 4,043
Total generation (millions of KWHs)
 3,588 4,345
Total purchased power (millions of KWHs)
 114 258 261 114
Sources of generation (percent)(*)
   
Sources of generation (percent)
   
Coal 22 46 11 22
Gas 78 54 89 78
Cost of fuel, generated (cents per net KWH)
  
Coal 3.25 4.23 3.55 3.25
Gas(*)
 2.68 3.59
Average cost of fuel, generated (cents per net KWH)(*)
 2.82 3.91
Average cost of purchased power (cents per net KWH)(*)
 3.54 7.90
Gas 2.15 2.68
Average cost of fuel, generated (cents per net KWH)
 2.32 2.82
Average cost of purchased power (cents per net KWH)
 2.17 3.54
(*)Includes energy produced during the test period for the Kemper IGCC which is accounted for in accordance with FERC guidance.
Fuel
In the first quarter 2015,2016, fuel expense was $114$76 million compared to $147$114 million for the corresponding period in 2014.2015. The decrease was primarily due to a 27.9%19% decrease in the volume of KWHs generated, primarily as a result of milder weather, and an 18% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, at lower natural gas prices, partially offset by a 7.3% increaseincluding the Kemper IGCC combined cycle that was placed in the volume of KWHs generated resulting from the availability of lower cost Mississippi Power units.service in 2014. The 7.3% increasedecrease in volume included an increase in gas-fired generation of 60.4%, partially offset by a decrease in coal-fired generation of 47.3%61% and a decrease in gas-fired generation of 5%.
Purchased Power - Non-Affiliates
In the first quarter 2015, purchased power expense from non-affiliates was $2 million compared to $11 million for the corresponding period in 2014. The decrease was primarily the result of an 80.0% decrease in the volume of KWHs purchased due to milder weather and a 33.5% decrease in the average cost per KWH purchased as a result of 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 first quarter 2015, purchased power expense from affiliates was $2 million compared to $9 million for the corresponding period in 2014. The decrease was primarily due to a 52.1% decrease in the average cost per KWH purchased as a result of lower natural gas prices and a 41.7% decrease in the volume of KWHs purchased due to milder weather.
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
94
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$(4) (5.5)
In the first quarter 2016, other operations and maintenance expenses were $69 million compared to $73 million for the corresponding period in 2015. The decrease was primarily due to a $9 million decrease in generation maintenance expenses due to lower outage costs, partially offset by a $7 million increase in generation maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began expensing in the third quarter 2015 in connection with the implementation of interim rates associated with the Kemper IGCC in-service assets. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

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Other OperationsDepreciation and Maintenance ExpensesAmortization
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$7 10.6
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$11 40.7
In the first quarter 2015, other operations2016, depreciation and maintenance expenses were $73amortization was $38 million compared to $66$27 million for the corresponding period in 2014.2015. The increase was primarily due to a $4 million increase in advertising and employee compensation and benefits including pension costs and a $3 million increase in customer accounting primarily due to uncollectible expenses and customer incentives.
See Note (F) to the Condensed Financial Statements under "Retirement Benefits" herein for additional information.
Depreciation and Amortization
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$4 17.4
In the first quarter 2015, depreciation and amortization was $27 million compared to $23 million for the corresponding period in 2014. The increase was primarily due to a $2 million increase in depreciation related to increases in generation and transmission plant in service, a $1 million increase resulting from a lowerof certain regulatory deferralassets associated with the purchase of Plant Daniel Units 3 and 4, and a $1 million increase in amortization primarily resulting from the lower Kemper IGCC regulatory deferrals in 2015.IGCC.
See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. SeeAlso, 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
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$5 25.0
In the first quarter 2015, taxes other than income taxes were $25 million compared to $20 million for the corresponding period in 2014. The increase was primarily due to an increase in ad valorem taxes related to Kemper IGCC assets in service.
Estimated Loss on Kemper IGCC
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(371) (97.6)
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$44N/M
N/M – Not meaningful
In the first quarterquarters of 2016 and 2015, and the first quarter 2014, estimated probable losses on the Kemper IGCC of $9$53 million and $380$9 million, respectively, were recorded toat 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 Initial DOE Grants and excluding the Cost Cap Exceptions.

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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 additional information.
Allowance for Equity Funds Used During ConstructionInterest Expense, Net of Amounts Capitalized
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(10) (26.3)
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$5 45.5
In the first quarter 2015, AFUDC equity2016, interest expense, net of amounts capitalized was $28$16 million compared to $38$11 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to placinga decrease of $8 million in capitalized interest and interest increases of $4 million related to long-term debt, $3 million on unrecognized tax benefits, and $2 million related to short-term debt. These increases were partially offset by an $8 million decrease related to interest on deposits resulting from the combined cycletermination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015 and a $4 million decrease related to the associated common facilities portionrequired refund of the Kemper IGCC in service in August 2014. Mirror CWIP.
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 additional information regarding the Kemper IGCC.information.

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Income Taxes (Benefit)
First Quarter 20152016 vs. First Quarter 20142015
(change in millions)
(% change)
$134(14) N/M
N/M – Not meaningful
In the first quarter 2015,2016, income taxes (benefit) were $4tax benefit was $(10) million compared to $(130)an expense of $4 million for the corresponding period in 2014.2015. The change was primarily reflects adue to the reduction in tax benefitspre-tax earnings related to the estimated probable losses on the construction of the Kemper IGCC recorded in 2014.IGCC.
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 prevail against legal challenges associated with the Kemper IGCC, and recover its prudently-incurred costs in a timely manner during a time of increasing costs, its ability to prevail against legal challenges associated with the Kemper IGCC, and the completion and subsequent operation of the Kemper IGCC andin accordance with any operational parameters that may be adopted by the Plant Daniel scrubber projectMississippi PSC, as well as other ongoing construction projects. Future earnings in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements 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. ChangesDemand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by 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 andwhich 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 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.modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced

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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 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 23, 2015, Mississippi Power made the decision to retire its coal-fired generation at Plant Watson Units 1 and 2 (150 MWs) by July 1, 2015, based on an economic analysis of expected environmental compliance costs. The net book value, at March 31, 2015, of these two units was approximately $2 million excluding the reserve for cost of removal. Mississippi 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 Mississippi PSC in future rate proceedings.
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.
Coal Combustion ResidualsAir Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters Environmental Statutes and Regulations Coal Combustion Residuals"Air Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.final MATS rule and regional haze regulations.
On April 17,25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published the Disposalits supplemental finding regarding consideration of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule)costs in the Federal Register, setting October 14, 2015 as the effective datesupport of the CCR Rule.MATS rule. This finding does not impact MATS rule

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compliance requirements, costs, or deadlines, and all Mississippi Power units that are subject to the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the CCR Ruleproposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this 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 expects to record incremental asset retirement obligations (ARO) of approximately $75 million to $85 million related to the CCR Rule in the second quarter 2015.time.
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 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, 2015,2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgofor an increase in wholesale base revenues as agreed upon in the settlement agreement reached with its wholesale customers under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement provides that base rates under the MRA cost-based electric tariff will increase reflectedapproximately $7 million annually, with revised rates effective for services rendered beginning May 1, 2016. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. Additionally, under the filing by, amongsettlement agreement, the tariff customers agreed in principle to similar regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. The Kemper IGCC regulatory treatment primarily includes (i) recovery of only the Kemper IGCC assets currently operational and providing service to customers and other things, increasingrelated costs and (ii) removing all of the Kemper IGCC CWIP with a corresponding increase in accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, if acceptedeffective May 1, 2016. If approved by the FERC, provides that the additional accrualamount of AFUDCbase rate revenues to be recognized in 2016 is effective April 1, 2015.expected to be approximately $5 million. The additional resulting AFUDC is projectedestimated to be approximately $12 million annually, of which $9 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. The ultimate outcome of this matter cannot be determined at this time.

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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 has directed the traditional operating companies (including Mississippi Power) and Southern Power, within 60 days, 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. Mississippi Power is evaluating the order.$6 million. 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 and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as the Kemper IGCC, fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through Mississippi Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory 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"Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

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Renewables
Subsequent to March 31,In November 2015, the Mississippi Power entered into separate PPAs forPSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power wouldwill purchase all of the energy produced by the solar facilities for the 25-year term under each of the contracts. If approved by the Mississippi PSC, thethree PPAs, two of which were finalized as of December 31, 2015 and one of which was finalized as of March 2, 2016. The projects are expected to be in service by the end of 2016 and the resulting energy purchases willare expected to be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of this matter cannot be determined at this time.
Performance Evaluation Plan
On March 17, 2015,April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2014,2015, which indicated noreflected the need for a $5 million surcharge or refund. On March 26, 2015,to be recovered from customers. The filing has been suspended for review by the Mississippi PSC suspended the filing to allow more time for review.
PSC. The ultimate outcome of this matter cannot be determined at this time.
Ad Valorem Tax AdjustmentFuel Cost Recovery
On April 23, 2015,At March 31, 2016, the amount of over-recovered retail fuel costs included on the balance sheet was $80 million compared to over-recovered retail fuel costs of $71 million at December 31, 2015.
The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle of February. As required by the order, on February 1, 2016, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requestedsubmitted updated natural gas price forecasts and resulting fuel factors to the Mississippi PSC. If approved by the Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an annual rate decrease of 0.35%, or $2additional $36 million in annual retail revenues, primarily due to a decrease in average millage rates.
annually. 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.

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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 Initial 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 continuescurrently expects to focus on completingplace the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for whichin service during the in-service date is currently expected to occur in the first halfthird quarter 2016.

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Recovery of the costs subject to the cost cap and the Cost Cap Exceptions remainremains 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)Court's decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of March 31, 2015, as adjusted for the Court's decision,2016, are as follows:

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Cost Category
2010 Project Estimate(f)
 Current Estimate Actual Costs at March 31, 2015
2010 Project Estimate(f)
 
Current Cost Estimate(a)
 Actual Costs
(in billions)(in billions)
Plant Subject to Cost Cap(a)(g)
$2.40
 $4.94
 $4.37
$2.40
 $5.35
 $4.99
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
 0.12
AFUDC(b)(c)
0.17 0.64 0.48
Combined Cycle and Related Assets Placed in
Service – Incremental(d)

 0.02
 
AFUDC(c)
0.17
 0.71
 0.62
Combined Cycle and Related Assets Placed in
Service – Incremental
(d)(g)

 0.02
 0.01
General Exceptions0.05 0.10 0.080.05
 0.10
 0.09
Deferred Costs(e)(g)

 0.18 0.14
 0.20
 0.18
Total Kemper IGCC(a)(c)
$2.97
 $6.22
 $5.40
Additional DOE Grants
 (0.14) 
Total Kemper IGCC$2.97
 $6.58
 $6.24
(a)
Amounts in the Current Cost Estimate reflect estimated costs through September 30, 2016.
(b)The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the 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" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.
(b)(c)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 $9 million increase in AFUDC related toreflects the impact of 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" herein 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."Liabilities" herein.
(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.
(g)Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at March 31, 2016.
Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2015, $3.272016, $3.61 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants and estimated probable losses of $2.06$2.47 billion), $2$6 million in other property and investments, $52$75 million in fossil fuel stock, $35$45 million in materials and supplies, $174$22 million in other regulatory assets, $12current, $196 million in other regulatory assets, deferred, $1 million in other current assets, and $11 million in other deferred charges and assets and $24 million in AROs in the balance sheet, with $1 million previously expensed.sheet.
Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $9$53 million ($6($33 million after tax) in the first quarter 2015. This amount is2016. Since 2012, in addition tothe aggregate, Mississippi Power has incurred charges totaling $868 million ($536 million after tax), $1.10of $2.47 billion ($681 million after tax), and $78 million ($48 million1.52 billion after tax) as a result of changes in 2014, 2013, and 2012, respectively.the cost estimate above the cost

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cap for the Kemper IGCC through March 31, 2016. The increasesincrease to the cost estimate in the first quarter 20152016 primarily reflectedreflects costs for the extension of the Kemper IGCC's projected in-service date through September 30, 2016, and increased efforts related to additional labor costsoperational readiness and challenges in support of start-up and operational readiness activities. The current estimatecommissioning activities which includes costs through March 31, 2016.the cost of repairs and modifications to the refractory lining inside the gasifiers. Any further extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $30$35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any further extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 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$14 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 totalof approximately $6$2 million per month. For additional information, see "2015 Rate Case" herein.

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Any furtherthe time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. 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 constructionoperating 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 Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operationsincome and these changes could be material.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional tax information related to the Kemper IGCC.
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 Rate Mitigation Plan (defined below) and any alternativefuture 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.

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2013 Settlement AgreementMPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that among other things, establishedwas intended to establish 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 estimated in-service date until securitization is finalized and other costs not included in the 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.

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2013 MPSC Rate Order
Consistent with the terms of the 2013 Settlement Agreement, inIn 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). For the period from March 2013 through March 31, 2015, $294 million had been collected primarily to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. service, based on a mirror CWIP methodology (Mirror CWIP rate).
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.IGCC. 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 collect and defer the approved rates 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. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, 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. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order.
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 and 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 incurred to support operation of 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" 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 filed by Thomas A. Blanton. 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. The Court's ruling remands the matter toOn July 7, 2015, the Mississippi PSC to (1) fix by orderordered that the rates that were in existence prior toMirror CWIP rate be terminated effective July 20, 2015 and required the 2013 MPSC Rate Order, (2) fix no rate increases untilfourth quarter 2015 refund of the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts$342 million collected under the 2013 MPSC Rate Order. Through March 31,Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.
2015 Rate Case
As a result of the 2015 Court decision, on July 10, 2015, Mississippi Power had collected $294 million throughfiled a supplemental filing including a request for interim rates under the 2013 MPSC Rate Order. Any required refunds would also include carrying costs. The Court's decision will become legally effective upon the issuance of a mandate to the Mississippi PSC. Absent specific instruction from the Court,(Supplemental Notice) with the Mississippi PSC will determinewhich presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the methodKemper IGCC assets that are commercially operational and timingcurrently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. On August 13, 2015, the Mississippi PSC approved the implementation of the refund. requested interim rates designed to collect approximately $159 million annually effective with the first billing cycle in September 2015, subject to refund and certain other conditions.
On March 12,December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi PSC filed motionsPower's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for rehearing. If the Court deniesin-service assets. The stipulated revenue requirement excluded the motions, it would issuecosts of the mandateKemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.
With implementation of the new rate on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC no later than seven days following such decision.had excluded from the revenue requirement calculation.

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On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Mitigation PlanOrder with the Court. On May 5, 2016, the Court dismissed the appeal.
In 2013,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 expects to securitize prudently-incurred qualifying facility costs in compliance withexcess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order filed a revisiondid not impact Mississippi Power's ability to utilize alternate financing through securitization or the proposedFebruary 2013 legislation.
Mississippi Power expects to seek additional rate relief to address recovery plan withof the Mississippi PSC for theremaining Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015.In the Rate Mitigation 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, was integral to the Rate Mitigation 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 Rate Mitigation 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 would review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" herein for additional information.
To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See "2015 Mississippi Supreme Court Decision" herein for additional information.
assets. In addition to current estimated costs at March 31, 20152016 of $6.22$6.58 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.
Mississippi Power also expects to seek rate recovery through alternate means, which could include a traditional rate case. On May 1, 2015, Mississippi Power notified the Mississippi PSC of its plans to file a rate request in May 2015.
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. As a result of the Court's decision, Mississippi Power intends to request that the Mississippi PSC reconsider its prudence review schedule. See "2015 Mississippi Supreme Court Decision" 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. Beginning in the third quarter 2015, in connection with the implementation of interim rates, Mississippi Power began expensing certain ongoing project costs and certain debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order. As of March 31, 2015,2016, the regulatory asset balance associated with these regulatory assets was $120 million, of which $22 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC was $174 million. The projected balance attotaled $98 million as of March 31, 2016 is estimated to total approximately $266 million.2016. The amortization period for any such costs approved for recovery remains subjectthese assets is expected to approvalbe determined by the Mississippi PSC.PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
The 2013See "2013 MPSC Rate Order approved retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designedOrder" herein for information related to collect $156 million annually beginning in 2014. On February 12,the July 7, 2015 the Court ordered the Mississippi PSC to refund Mirror CWIP and to fix by order the rates that were in existence prior to the 2013 MPSC Rate Order. Mississippi Power is deferring the collections under the approved rates interminating the Mirror CWIP regulatory liability until otherwise directed by the Mississippi PSC. Mississippi Power is also accruing carrying costs on the unamortized balancerate and requiring refund of thecollections under Mirror CWIP regulatory liability for the benefit of retail customers. As of March 31, 2015, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $311 million.
See "2015 Mississippi Supreme Court Decision" herein for additional information.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.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of March 31, 2016, Mississippi Power recorded a related regulatory liability of approximately $3 million. See "2015 Rate Case" herein 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Denbury and Treetop with 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 CO2 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 respective agreements, anyagreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO2 off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO2 contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in future chemical product salesMississippi Power's 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. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements. 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 Clean Power Plan and related litigation.
The ultimate outcome of these matters cannot be determined at this time.
Civil Lawsuit
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean. The plaintiffs allege that Mississippi Power violated the Mississippi Unfair Trade Practices Act and concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that Mississippi Power's alleged breaches interfered with and destroyed economically advantageous relationships between the plaintiffs and their current and prospective business associates. The plaintiffs seek unspecified actual damages and punitive damages as well as attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend the matter, and the final outcome of this matter cannot be determined at this time.
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 and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.

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

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 they agreed to amend a 2011 power supply agreement between the parties 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 2011 power supply agreement were $4 million in the first quarter 2015 and $17 million in 2014.
By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle on certain issues related 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 payable 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 Kemper IGCC 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 provided 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.
By letter dated December 18, 2014, SMEPA notified Mississippi Power that SMEPA decided not to extend the December 31, 2014 estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination.
The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, 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.
In 2012, in January 2014, and in October 2014, Mississippi Power received $150 million, $75 million, and $50 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. Accordingly, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any refund of the deposits to SMEPA.
The ultimate outcome of these matters cannot be determined at this time.
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.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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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. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits totaling approximately $211 million at March 31, 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," 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.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. Southern Company and Mississippi Power are cooperating fully with the SEC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.
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, Asset Retirement Obligations, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, and AFUDC.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2015,2016, 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 Initial 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 to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial 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 $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third

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MISSISSIPPI POWER COMPANY
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

quarter 2015, $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

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

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 $2.06$2.47 billion ($1.271.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2015.2016.
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 Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operationsincome 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 constructionoperating 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, but not limited to, 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,September 30, 2016. Any further extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $30$35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any further extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 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$14 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 totalof approximately $6$2 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 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.
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015,February 25, 2016, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Mississippi Power continuesASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees 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 inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Mississippi Power is currently reflects unamortized debt issuance costs in other deferred chargesevaluating the new standard and assetshas not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on itsMississippi Power's balance sheet. Upon adoption,
On March 30, 2016, the reclassification will not have a material impact onFASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the results of operations, financial position, oraccounting for income taxes and the cash flows of Mississippi Power.flow presentation for share-based payment award transactions. Most

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MISSISSIPPI POWER COMPANY
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significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Mississippi Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Mississippi Power is currently evaluating the new standard and has not yet determined its ultimate impact.
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. Earnings for the three months ended March 31, 2015 and 20142016 were negatively affected by revisions to the cost estimate for the Kemper IGCCIGCC.
Through March 31, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.11 billion and the Court's decisionis expected to reverse the 2013 MPSC Rate Order; however, Mississippi Power's financial condition remained stable as a resultincur approximately $0.36 billion in additional non-recoverable cash expenditures through completion of the financing activities described herein. Mississippi Power's cash requirements primarily consistconstruction and start-up of funding debt maturities, including $900 million maturing April 1, 2016, ongoing operations and capital expenditures, as well as the potential requirement to refund amounts collected under the 2013 MPSC Rate Order and associated carrying costs ($311 million through March 31, 2015) and the SMEPA deposits ($275 million at March 31, 2015). See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" and "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " 2015 Mississippi Supreme Court Decision" herein for additional information. IGCC.
For the three-year period from 20152016 through 2017,2018, 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, including the Plant Daniel scrubber project, to add environmental equipment formodifications to existing generating units, 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 March 31, 2015,On January 28, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $1.49 billion and is expectedissued a promissory note for up to incur approximately $567$275 million to Southern Company, which matures in additional non-recoverable cash expenditures through completion of the Kemper IGCC.
December 2017, bearing interest based on one-month LIBOR. During the first three months of 2015,2016, Mississippi Power received $75borrowed $100 million in equity contributionsunder this promissory note. In addition, on January 19, 2016, Mississippi Power borrowed an additional $100 million from Southern Company. SubsequentCompany pursuant to a promissory note issued in November 2015. On March 31, 2015,8, 2016, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, inan unsecured term loan agreement for an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used$1.2 billion to repay existing indebtedness and 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 amountborrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016.
As of $425March 31, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $363 million which, among other things, extended the maturity dates from various datesprimarily due to $300 million in 2015senior notes scheduled to April 1, 2016.mature on October 15, 2016 and $25 million in short-term debt. Mississippi Power intends to utilize operating cash flows and lines of credit bank term loans, and commercial paper, as market conditions permit,(to the extent available) as well as loans and, under certain circumstances, equity contributions and/or loans from Southern Company to fund Mississippi Power's short-termthe remainder of its capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided fromused for operating activities totaled $204$25 million for the first three months of 2015, an increase2016, a decrease of $172$229 million as compared to the corresponding period in 2014.2015. The increasedecrease in cash provided from operating activities is primarily due to R&Elower research and experimental tax deductions, a reduction in the customer liability associated with Kemper IGCC refunds due to offsetting service provided, a decrease in prepaid income taxes, and bonus depreciation reducing tax payments,a decrease in Mirror CWIP regulatory liability due to the Mirror CWIP refund, partially offset by an increase in fuel recovery, and Mirror CWIP, net of the Kemper IGCC regulatory deferral, partially offset by the timing of payments for accounts payable and fuel purchases.receivables. See Notes (B) and Note (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $233$214 million for the first three months of 20152016 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project.IGCC. Net cash provided from financing activities totaled $30$199 million for the first three months of 20152016 primarily due to capital contributions from Southern Company and short-term borrowings,long-term debt issuances, partially offset by redemptions of long-term debt.debt and short-term 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 three months of 2015 include a decrease in securities due within one year of $775 million and an increase in long-term debt of $698 million, primarily due to refinancing or replacing maturing debt. See "Sources of Capital" herein for additional information. Total property, plant, and equipment

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Significant balance sheet changes for the first three months of 2016 include an increase in long-term debt of $1.1 billion. A portion of this debt was used to repay securities and notes payable resulting in a $425 million decrease in securities due within one year and a $475 million decrease in notes payable. Total property, plant, and equipment increased $197 million, other regulatory assets, deferred increased $34 million, and the Mirror CWIP regulatory liability increased $40$140 million primarily due to the construction and startup activities for the Kemper IGCC. See "Integrated Coal Gasification Combined Cycle" herein for additional information. Additional changes included a decrease in prepaid income taxes of $29 million, a decrease in other accrued taxes of $55 million primarily due to ad valorem tax payments, and increases in accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and accrued income taxes of $95 million and $43 million, respectively, primarily due to R&E tax deductions and the related reserve. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" and Note (G) to the Condensed Financial Statements herein for additional information. Total common stockholder's equity increased $113 million primarily due to the receipt of $75 million in capital contributions from Southern Company and due to net income for the quarter.The customer liability associated with Kemper IGCC refunds decreased $51 million.
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. Mississippi Power has noApproximately $300 million will be required through March 31, 2017 to fund maturities of long-term debt, maturing at or priorand $25 million will be required to March 31, 2016. Approximately $900 million in bank term loans are scheduled to mature on April 1, 2016.fund maturities of short-term debt. See "Sources of Capital" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $841 million for 2016, $216 million for 2017, and $264 million for 2018, which includes expenditures related to the construction of the Kemper IGCC of $665 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 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,In December 2015, the Mississippi Power plans to obtainPSC approved the funds requiredIn-Service Asset Rate Order, which among other things, provided for construction and other purposes from operating cash flows, security issuances, term loans, and/or short-term debt, as well as, under certain circumstances, equity contributions and/or loans from Southern Company. Operating cash flows would be adversely impacted by $156retail rate recovery of an annual revenue requirement of approximately $126 million annually with the removal of rates implemented under the 2013 MPSC Rate Order.effective December 17, 2015. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which may includeincludes 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"Rate Case" of Mississippi Power in Item 7 of the Form 10-K and hereinfor additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE Grants is expected to be received for commercial operation of the Kemper IGCC. On April 8, 2016, Mississippi Power received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. 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.

109106

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

As of March 31, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $578 million primarily due to refundable deposits from SMEPA and the potential Mirror CWIP refund. Subsequent to March 31, 2015,On January 28, 2016, Mississippi Power entered into two floating rate bank loans withissued a maturity date of April 1, 2016,promissory note for up to $275 million to Southern Company, which matures in an aggregate principal amount of $475 million,December 2017, bearing interest based on one-month LIBOR. The proceedsDuring the first three months of these loans were used2016, Mississippi Power borrowed $100 million from Southern Company pursuant to the $275 million promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for the repayment of term loans in an aggregate principal amount of $275 million, working capital,$1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power also amended three outstanding floating rateborrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans for an aggregate principal amount of $425on March 8, 2016 and expects the remaining $300 million which, among other things, extended the maturity dates from various datesto be used to repay senior notes maturing in 2015October 2016. The term loan pursuant to this agreement matures on April 1, 2016. 2018 and bears interest based on one-month LIBOR.
Mississippi Power intends to utilize operating cash flows and lines of credit bank term loans, and commercial paper, as market conditions permit,(to the extent available) as well as loans and, under certain circumstances, equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs.
At March 31, 2015,2016, Mississippi Power had approximately $134$58 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 20152016 were as follows:
ExpiresExpires   
Executable Term
Loans
 
Due Within One
Year
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)
20162016 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
 (in millions) (in millions) (in millions)
$135
 $165
 $300
 $270
 $25
 $40
 $65
 $235
205
 $205
 $180
 $30
 $15
 $45
 $160
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.
Most of these bank credit arrangements, as well as Mississippi Power's term loan arrangements, contain covenants that limit debt levels and typically contain cross acceleration or 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 specifiedspecific threshold. Such cross acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. 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 extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the $270$180 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 March 31, 20152016 was approximately $40 million.
Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power are loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

110107

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

Details of short-term borrowings were as follows:
  
Short-term Debt at
March 31, 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 $30
 1.2% $7
 1.2% $30
  
Short-term Debt at
March 31, 2016
 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Short-term bank debt $25
 2.1% $375
 2.0% $500
(*)    Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2016.
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 have required or could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB-BBB and/or Baa3.Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.management, and transmission. At March 31, 2015,2016, the maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $281$266 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, anya credit rating downgrade could impact the ability of Mississippi Power's abilityPower to access capital markets, particularlyand would be likely to impact the short-term debt market and the variable rate pollution control revenue bond market.cost at which it does so.
Financing Activities
In March 2015,January 2016, Mississippi Power repaid at maturityissued a $75 million bank term loan.
Subsequent to March 31, 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016,promissory note to Southern Company in an aggregate principal amount of $475up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. The proceedsAs of these loans were usedMarch 31, 2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015.
On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for the repayment of term loans in an aggregate principal amount of $275 million, working capital,$1.2 billion to repay existing indebtedness and for other general corporate purposes, including Mississippi Power's ongoing construction program.purposes. Mississippi Power also amended three outstanding floating rateborrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans for an aggregate principal amount of $425notes on March 8, 2016 and expects the remaining $300 million which, among other things, extended the maturity dates from various datesto be used to repay senior notes maturing in 2015October 2016. The term loan pursuant to this agreement matures on April 1, 2016.2018 and bears interest based on one-month LIBOR.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations,Also in March 2016, Mississippi Power plans to continue, when economically feasible,renewed a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.$10 million short-term note, which matures on June 30, 2016, bearing interest based on three-month LIBOR.

111108



SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

112109



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Operating Revenues:      
Wholesale revenues, non-affiliates$232
 $278
$215
 $232
Wholesale revenues, affiliates114
 72
97
 114
Other revenues2
 1
3
 2
Total operating revenues348
 351
315
 348
Operating Expenses:      
Fuel138
 125
91
 138
Purchased power, non-affiliates16
 28
13
 16
Purchased power, affiliates10
 29
6
 10
Other operations and maintenance52
 53
79
 52
Depreciation and amortization59
 51
73
 59
Taxes other than income taxes6
 6
6
 6
Total operating expenses281

292
268
 281
Operating Income67
 59
47
 67
Other Income and (Expense):      
Interest expense, net of amounts capitalized(22) (22)(21) (22)
Other income (expense), net2
 
Total other income and (expense)(19) (22)
Earnings Before Income Taxes45
 37
28
 45
Income taxes12
 3
Income taxes (benefit)(23) 12
Net Income33
 34
51
 33
Less: Net income attributable to noncontrolling interests
 1
1
 
Net Income Attributable to Southern Power Company$33
 $33
Net Income Attributable to Southern Power$50
 $33
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Net Income$33
 $34
$51
 $33
Other comprehensive income (loss)
 
Other comprehensive income (loss):   
Qualifying hedges:   
Reclassification adjustment for amounts included in net
income, net of tax of $-, and $-, respectively
1
 
Total other comprehensive income (loss)1
 
Less: Comprehensive income attributable to noncontrolling interests
 1
1
 
Comprehensive Income Attributable to Southern Power Company$33
 $33
Comprehensive Income Attributable to Southern Power$51
 $33
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

113110



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For the Three Months
Ended March 31,
For the Three Months
Ended March 31,
2015 20142016 2015
(in millions)(in millions)
Operating Activities:      
Net income$33
 $34
$51
 $33
Adjustments to reconcile net income to net cash provided from (used for) operating activities —   
Adjustments to reconcile net income to net cash used for operating activities —   
Depreciation and amortization, total60
 53
75
 60
Deferred income taxes(54) (14)(132) (54)
Investment tax credits
 26
Amortization of investment tax credits(4) (2)(7) (4)
Deferred revenues(20) (20)(26) (20)
Other, net3
 3
9
 3
Changes in certain current assets and liabilities —      
-Receivables2
 21
(3) 2
-Fossil fuel stock6
 2
1
 6
-Prepaid income taxes(2) 15
(31) (2)
-Other current assets
 (1)
-Accounts payable(25) 2
(12) (25)
-Accrued taxes(4) 6
(37) (4)
-Accrued interest(15) (15)2
 (15)
-Other current liabilities1
 

 1
Net cash provided from (used for) operating activities(19) 110
Net cash used for operating activities(110) (19)
Investing Activities:      
Plant acquisitions(114) (6)
Property additions(38) (5)(767) (33)
Change in construction payables17
 1
31
 17
Payments pursuant to long-term service agreements(16) (10)(25) (16)
Investment in restricted cash(289) 
Distribution of restricted cash292
 
Other investing activities(1) (1)(1) 
Net cash used for investing activities(38) (15)(873) (38)
Financing Activities:      
Increase in notes payable, net38
 
276
 38
Distributions to noncontrolling interests(4) 
Capital contributions from noncontrolling interests131
 
Purchase of membership interests from noncontrolling interests(129) 
Payment of common stock dividends(33) (33)(68) (33)
Other financing activities
 (2)
Net cash provided from (used for) financing activities5
 (35)
Net cash provided from financing activities206
 5
Net Change in Cash and Cash Equivalents(52) 60
(777) (52)
Cash and Cash Equivalents at Beginning of Period75
 69
830
 75
Cash and Cash Equivalents at End of Period$23
 $129
$53
 $23
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —   
Interest (net of $- and $- capitalized for 2015 and 2014, respectively)$36
 $36
Cash paid (received) during the period for --   
Interest (net of $10 and $- capitalized for 2016 and 2015, respectively)$15
 $36
Income taxes, net79
 (44)188
 79
Noncash transactions — Accrued property additions at end of period16
 5
262
 16
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

114111



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets At March 31,
2015
 At December 31,
2014
 At March 31,
2016
 At December 31,
2015
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $23
 $75
 $53
 $830
Receivables —        
Customer accounts receivable 71
 77
 76
 75
Other accounts receivable 14
 15
 23
 19
Affiliated companies 37
 34
 31
 30
Fossil fuel stock, at average cost 16
 22
 14
 16
Materials and supplies, at average cost 59
 58
 63
 63
Prepaid service agreements — current 10
 8
Prepaid income taxes 21
 19
 77
 45
Deferred income taxes, current 379
 306
Other prepaid expenses 10
 8
 23
 23
Assets from risk management activities 
 5
 6
 7
Total current assets 640
 627
 366
 1,108
Property, Plant, and Equipment:        
In service 5,658
 5,657
 7,738
 7,275
Less accumulated provision for depreciation 1,093
 1,035
 1,299
 1,248
Plant in service, net of depreciation 4,565
 4,622
 6,439
 6,027
Construction work in progress 48
 11
 1,535
 1,137
Total property, plant, and equipment 4,613
 4,633
 7,974
 7,164
Other Property and Investments:        
Goodwill 2
 2
 2
 2
Other intangible assets, net of amortization of $9 and $8 at
March 31, 2015 and December 31, 2014, respectively
 46
 47
Other intangible assets, net of amortization of $13 and $12
at March 31, 2016 and December 31, 2015, respectively
 316
 317
Total other property and investments 48
 49
 318
 319
Deferred Charges and Other Assets:        
Prepaid long-term service agreements 137
 124
 184
 166
Other deferred charges and assets — affiliated 13
 5
 20
 9
Other deferred charges and assets — non-affiliated 113
 112
 137
 139
Total deferred charges and other assets 263
 241
 341
 314
Total Assets $5,564
 $5,550
 $8,999
 $8,905
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

115112



SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Liabilities and Stockholders' Equity At March 31,
2015
 At December 31,
2014
 At March 31,
2016
 At December 31,
2015
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $525
 $525
 $401
 $403
Notes payable 233
 195
 413
 137
Accounts payable —        
Affiliated 69
 78
 62
 66
Other 32
 30
 347
 327
Accrued taxes —    
Accrued income taxes 65
 72
 9
 198
Other accrued taxes 16
 5
Accrued interest 15
 30
 25
 23
Contingent consideration 21
 36
Other current liabilities 19
 17
 49
 44
Total current liabilities 958
 947
 1,343
 1,239
Long-term Debt 1,095
 1,095
 2,722
 2,719
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 882
 863
 470
 601
Accumulated deferred investment tax credits 596
 601
 1,025
 889
Accrued income taxes, non-current 109
 109
Asset retirement obligations 25
 21
Deferred capacity revenues — affiliated 5
 15
 6
 17
Other deferred credits and liabilities — affiliated 
 1
Other deferred credits and liabilities — non-affiliated 16
 18
Other deferred credits and liabilities 11
 3
Total deferred credits and other liabilities 1,499
 1,498
 1,646
 1,640
Total Liabilities 3,552
 3,540
 5,711
 5,598
Redeemable Noncontrolling Interest 40
 39
Redeemable Noncontrolling Interests 44
 43
Common Stockholder's Equity:        
Common stock, par value $.01 per share —    
Authorized — 1,000,000 shares    
Outstanding — 1,000 shares 
 
Common stock, par value $.01 per share --    
Authorized - 1,000,000 shares    
Outstanding - 1,000 shares 
 
Paid-in capital 1,176
 1,176
 1,821
 1,822
Retained earnings 574
 573
 640
 657
Accumulated other comprehensive income 3
 3
 5
 4
Total common stockholder's equity 1,753
 1,752
 2,466
 2,483
Noncontrolling Interest 219
 219
Noncontrolling Interests 778
 781
Total Stockholders' Equity 1,972
 1,971
 3,244
 3,264
Total Liabilities and Stockholders' Equity $5,564
 $5,550
 $8,999
 $8,905
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.

116113

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

FIRST QUARTER 20152016 vs. FIRST QUARTER 2014

2015


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.
During the first quarter 2015,three months ended March 31, 2016, Southern Power acquired or commenced construction of approximately 140 MWs of additional solar facilities. Southern Power also entered into agreementsan agreement to acquire an approximately 299-MW40-MW wind facility located in Oklahoma, andMaine. Subsequent to March 31, 2016, Southern Power acquired an approximately 199 MWs of additional solar facilities: the Decatur County and Butler Solar Projects, both151-MW wind facility located in Georgia.Oklahoma. See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" herein for additional information.
To evaluate operating results and to ensure Southern Power's ability to meet its contractual commitments to customers,At March 31, 2016, Southern Power focuseshad an average investment coverage ratio of 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025) with an average remaining contract duration of approximately 18 years. This includes the PPAs and capacity associated with solar facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL "Power Sales Agreements" herein for additional information.
Southern Power continues to focus on several key performance indicators. These indicators includinginclude 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
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$17 51.5
Net income attributable to Southern Power for the first quarter 20152016 was $50 million compared to $33 million for the corresponding period in 2015. The increase was primarily due to increased tax benefits from solar ITCs and 2014 was $33 million. Increaseswind PTCs and increased renewable energy sales arising from new solar and wind facilities, partially offset by increases in depreciation and income taxesoperations and maintenance expenses.
Operating Revenues
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(33) (9.5)
Operating revenues include PPA capacity revenues which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues which include sales from natural gas, biomass, solar, and wind facilities. To the extent Southern Power has unused capacity, it may sell power into the wholesale market or into the power pool.

114

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

  First Quarter 2016
vs.
First Quarter 2015
 (change in millions) (% change)
PPA capacity revenues$(3) (2.1)
PPA energy revenues
 N/M
Total PPA revenues(3) (1.1)
Revenue not covered by PPA(31) (30.0)
Other revenues1
 50.0
Total operating revenues$(33) (9.5)%
N/M – Not meaningful
In the first quarter 2016, operating revenues were $315 million compared to $348 million for the corresponding period in 2015. The $33 million decrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $3 million as a result of a $15 million decrease in non-affiliate capacity revenues, partially offset by a $12 million increase in affiliate capacity revenues primarily due to PPA remarketing.
PPA energy revenuesremained flat; however, a $20 million increase in renewable energy sales, arising from new solar and wind facilities, was offset by a decrease of $20 million in purchased power expenses.fuel revenues related to natural gas PPAs.
Wholesale RevenuesNon-Affiliates
Revenues not covered by PPA decreased $31 million primarily due to a 23% decrease in non-PPA KWH sales associated with increased scheduled outages and a reduction in demand driven by milder weather in 2016 as compared to 2015.
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$(46) (16.5)
Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of thoseSouthern Power's 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.
Capacity revenues are an integral component of Southern Power's natural gas and biomass PPAs and generally represent the greatest contribution to net income. Energy under the PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges.
Southern Power's electricity sales from solar and wind generating facilities are also through long-term PPAs, but do not have a capacity charge. Instead, the customers purchase the energy output of a dedicated renewable facility through an energy charge. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.

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Details of the changes in wholesale revenues from non-affiliates were as follows:
 
First Quarter
 2015
 (in millions) (% change)
Wholesale Revenues – Non-Affiliates, prior year$278
  
Change resulting from -   
Capacity(7) (2.5)
Energy(39) (14.0)
Wholesale Revenues – Non-Affiliates, current year$232
 (16.5)%
The decrease in capacity was primarily the result of contract expirations. The decrease in energy revenues reflects a 20.8% decrease in the average price of energy and a 20.0% decrease in non-affiliate KWH sales for the first quarter 2015. This was primarily due to lower fuel revenues, reduced load, and contract expirations, partially offset by an increase in energy revenues from new solar PPAs.
Wholesale RevenuesAffiliates
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$42 58.3
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 first quarter 2015 were $114 million compared to $72 million for the corresponding period in 2014. The increase was primarily the result of a $38 million increase in energy revenues from sales under the IIC as a result of lower natural gas prices.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. Additionally, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:
   First Quarter 2015
vs.
First Quarter 2014
  (change in millions)
(% change)
Fuel $13
 10.4
Purchased power – non-affiliates (12) (42.9)
Purchased power – affiliates (19) (65.5)
Total fuel and purchased power expenses $(18)  
 First Quarter 2016First Quarter 2015
Generation (in billions of KWHs)
7.77.9
Purchased power (in billions of KWHs)
0.60.5
Total generation and purchased power8.38.4
Total generation and purchased power (excluding solar, wind and tolling)5.35.9
Southern PowerPower's PPAs for natural gas-firedgas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel.fuel relating to the energy delivered under such PPAs. Consequently, any increase or decrease in such fuel costcosts 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 wholesale market or sold to affiliates underinto the IIC.power pool, for capacity owned directly by Southern Power (excluding its subsidiaries).
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.

118
   First Quarter 2016
vs.
First Quarter 2015
  (change in millions)
(% change)
Fuel $(47) (34.1)
Purchased power (7) (26.9)
Total fuel and purchased power expenses $(54)  
In the first quarter 2016, total fuel and purchased power expenses were $110 million compared to $164 million for the corresponding period in 2015. The decrease was primarily due to the following:
Fuel expense decreased $47 million primarily due to a $28 million decrease associated with the average cost of natural gas per KWH generated and a $19 million decrease associated with the volume of KWHs generated.
Purchased power expense decreased $7 million due to a $12 million decrease in the average cost of purchased power and a $4 million decrease associated with a PPA expiration, partially offset by a $9 million increase associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
First Quarter 2016 vs. First Quarter 2015
(change in millions) (% change)
$27 51.9
In the first quarter 2016, other operations and maintenance expenses were $79 million compared to $52 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase associated with

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scheduled outage and maintenance expenses, a $6 million increase in business support services expenses, and a $5 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016.
Depreciation and Amortization
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$14 23.7
In the first quarter 2015, total fuel2016, depreciation and purchased power expenses were $164amortization was $73 million compared to $182$59 million for the corresponding period in 2014.2015. The decreaseincrease was the result of a $97 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $79 millionadditional depreciation related to new solar and wind facilities placed in service in 2015 and 2016.
Interest Expense, net increase in the volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.Amounts Capitalized
Fuel
First Quarter 2016 vs. First Quarter 2015
(change in millions)
(% change)
$(1) (4.5)
In the first quarter 2015, fuel2016, interest expense, net of amounts capitalized was $138$21 million compared to $125$22 million for the corresponding period in 2014. The increase was due to an 88.4% increase in the volume of KWHs generated primarily due to increased demand resulting from lower natural gas prices, partially offset by a 41.1% decrease in the average cost of natural gas per KWH generated.
Purchased Power
In the first quarter 2015, purchased power expense was $26 million compared to $57 million for the corresponding period in 2014. The decrease was the result of a 52.8% decrease in the volume of KWHs purchased and a 5.5% decrease in the average cost per KWH of purchased power primarily due to lower natural gas prices.
Other Operations and Maintenance Expenses
First Quarter 2015 vs. First Quarter 2014
(change in millions) (% change)
$(1) (1.9)
In the first quarter 2015, other operations and maintenance expenses were $52 million compared to $53 million for the corresponding period in 2014.2015. The decrease was primarily due to a $7$9 million decrease as a resultincrease in capitalized interest associated with the construction of lower outage costs,solar facilities, largely offset by a $6an increase of $8 million increase in expenses associated with labor, maintenance, support services, and new plants placed in service in 2014.
Depreciation and Amortization
First Quarter 2015 vs. First Quarter 2014
(change in millions)
(% change)
$8 15.7
In the first quarter 2015, depreciation and amortization was $59 million compared to $51 million for the corresponding period in 2014. The increase was primarilyinterest expense related to solar facilities placed in service in 2014.additional debt issued primarily to fund Southern Power's growth strategy and continuous construction program.
Income Taxes (Benefit)
First Quarter 20152016 vs. First Quarter 20142015
(change in millions)
(% change)
$9(35) N/M
N/M – Not meaningful
In the first quarter 2015,2016, income taxes were $12tax benefit was $(23) million compared to $3an expense of $12 million for the corresponding period in 2014.2015. The increasechange was primarily due to beneficial changes impacting 2014 state income taxes and higher pre-tax earningsa $28 million increase in 2015, partially offset by increased federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $7 million decrease in tax expense related to ITCslower pre-tax earnings in 2015.2016.
See Note (G) to the Condensed Financial Statements herein for additional information.

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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 creationgrowth strategy, including successfully expandingsuccessful additional investments in renewable and other energy projects, and to construct generating facilities, including the impact of federal ITCs. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
Other factors that could influence future earnings include weather, demand, cost of generatinggeneration from units within the power pool, and operational limitations. For additional information relating to these issues, see RISK FACTORS in

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Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
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, electric cooperatives, and other load-serving entities.
At December 31, 2015, Southern Power's generation contract coverage ratio, which compares contracted capacity (MW) to available demonstrated capacity (MW), was an average of 75% for the next five years (through 2020) and 70% for the next 10 years (through 2025), with an average remaining contract duration of approximately 10 years.
Southern Power believes an investment contract ratio better identifies the value of assets covered since it represents the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction or being acquired) as the investment amount. At March 31, 2016, the investment coverage ratio was 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025), with an average remaining contract duration of approximately 18 years. At December 31, 2015, the investment coverage ratio would have been 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025), with an average remaining contract duration of approximately 18 years.
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.
Acquisitions
During 2015, Southern Power Company acquired or contracted to acquire the following projects2016, 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,acquired or contracted to acquire through its wholly-owned subsidiarysubsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., entered into a purchase agreementthe projects set forth in the following table. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Project FacilityApprox. Nameplate CapacityLocationPercentage Ownership Expected/Actual CODPPA Contract Period
 (MW)     
SOLAR
Calipatria(a)
20Imperial County, CA90% February 11, 201620 years
East Pecos(b)
120Pecos County, TX100% Fourth quarter 201615 years
WIND
Grant Wind(c)
151Grant County, OK100% April 8, 201620 years
Passadumkeag(d)
40Penobscot County, ME100% Second quarter 201615 years
(a) Calipatria - On February 11, 2016, Southern Power, together with Kay Wind Holdings,the minority owner, Turner Renewable Energy, LLC a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire(TRE), which owns 10%, acquired all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on 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. In March 2015, Kay Wind obtained the necessary financing for the construction of the facility, and the acquisition is expected to close in the fourth quarter 2015. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, and various other customary conditions to closing. 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.Calipatria Solar, LLC.
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 $34 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

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entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 20-MW Lost Hills and the approximately 12-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 and then to Pacific Gas and Electric Company, that together extend approximately 29 years.
North Star Solar Facility
(b) East Pecos - On April 30, 2015,March 4, 2016, Southern Power Company, through its subsidiary SRP, acquired 100% ofall the class Aoutstanding membership interests of NSEast Pecos Solar, Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar,LLC. Total construction costs, which include the developer of the project, for approximately $208 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $99 million. SRP and the class B memberacquisition price allocated to CWIP, 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 is constructing and owns the approximately 60-MW North Star solar facility in Fresno County, California, which is expected to begin commercial operation in June 2015. The entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company.be approximately $200 million to $220 million. The ultimate outcome of this matter cannot be determined at this time.
(c) Grant Wind - Subsequent to March 31, 2016, Southern Power acquired all the outstanding membership interests of Grant Wind, LLC.
(d) Passadumkeag - On March 11, 2016, Southern Power entered into an agreement to acquire all of the outstanding membership interests of Quantum Wind Acquisition I, LLC, which is expected to close in the second quarter 2016. The ultimate outcome of this matter cannot be determined at this time.
Construction Projects
During 2015,See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" of Southern Power Company commenced or plans to commencein Item 7 of the following construction projectsForm 10-K for additional information.
During the first quarter 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through March 31, 2016, total costs of construction incurred for the projects below were $2.2 billion, of which are included$1.5 billion remains in Southern Power's capital program estimates for 2015.CWIP. The ultimate outcome of these matters cannot be determined at this time.
Decatur County Solar Projects
On February 19,
Solar FacilityApprox. Nameplate CapacityLocationExpected/Actual CODPPA
Contract Period
Estimated Construction Costs 
 (MW)   (in millions) 
Butler103Taylor County, GAFourth quarter 201630 years$220
-230(a)
Desert Stateline
299(b)
San Bernardino County, CAThrough third quarter 201620 years$1,200
-1,300(c)
Garland and
Garland A
(d)
205Kern County, CAFourth quarter 2016 Third quarter 201615 years
and 20 years
$532
-552(e)
Roserock(d)
160Pecos County, TXFourth quarter 201620 years$333
-353(e)
Sandhills146Taylor County, GAFourth quarter 201625 years$260
-280 
Tranquillity(d)
205Fresno County, CAThird quarter 201618 years$473
-493(f)
(a)
Butler - Total estimated construction costs include the acquisition price of all outstanding membership interests of the related entity.
(b) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 Southern Power Company acquired all ofand 76 MWs were placed in service in the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. as part of Southern Power's plansfirst quarter 2016. Subsequent to build two solar photovoltaic facilities: the Decatur Parkway Solar Project and the Decatur County Solar Project. These two projects, approximately 80March 31, 2016, 38 MWs and 19were placed in service. The remaining 75 MWs respectively, will be constructed on separate sites in Decatur County, Georgia. Construction of the Decatur Parkway Solar Project commenced in February 2015, while construction of the Decatur County Solar Project is expected to commence in June 2015. Both projects are expected to begin commercial operationbe placed in late 2015, andservice by the entire output of each project is contracted to Georgia Power. The Decatur Parkway Solar Project is contracted under a 25-year PPA and the Decatur County Solar Project is contracted under a separate 20-year PPA. Construction costs incurred through March 31, 2015 were $32 million. The total estimated costend of the facilities is expected to be between $200 millionthird quarter 2016.
(c)
Desert Stateline - On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.
(d)
Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project.
(e)Total estimated construction costs include the acquisition price allocated to CWIP. During the first quarter 2016, the allocation of the purchase price to individual assets was finalized with no changes.
(f)Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.
See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and $220 million, which includes the acquisition priceContractual Obligations" herein for all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc.additional information.
Butler Solar Project
On March 12, 2015, Southern Power Company entered into a purchase agreement with CERSM, LLC and Community Energy, Inc. to acquire all of the outstanding membership interests of Butler Solar LLC as part of Southern Power's plans to build an approximately 100-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in July 2015, with commercial operation expected to begin in December 2016. The entire output of the project is contracted to Georgia Power under a 30-year PPA. The total estimated cost of the facility is expected to be between $220 million and $230 million, which includes the acquisition price for all of the outstanding membership interests of Butler Solar LLC from CERSM, LLC and Community Energy, Inc. The acquisition is expected to close later in May 2015, and is subject to customary conditions to closing.

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Pawpaw Solar Project
On April 22, 2015, Southern Power Company entered into a purchase agreement with Longview Solar, LLC to acquire all of the outstanding membership interests of LS – Pawpaw, LLC as part of Southern Power's plans to build an approximately 30-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in June 2015, with commercial operation expected to begin in December 2015. The entire output of the project is contracted to Georgia Power under a 30-year PPA. The total estimated cost of the facility is expected to be between $65 million and $75 million, which includes the acquisition price for all of the outstanding membership interests of LS – Pawpaw, LLC from Longview Solar, LLC. The acquisition is expected to close later in May 2015, and is subject to customary conditions to closing.
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 March 31, 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 has directed the traditional operating companies and Southern Power, within 60 days, 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. Southern Power is evaluating the order. The ultimate outcome of this matter cannot be determined at this time.
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.

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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 LivedLong-Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015,February 25, 2016, the FASB issued an exposure draft proposingASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the standard be effectivebalance sheet a lease liability and a right-of-use asset for fiscal years beginning after December 15, 2017. Southern Power continues to evaluateall leases. ASU 2016-02 also changes the requirementsrecognition, measurement, and presentation 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 modelexpense associated with leases and the voting model, including changes toprovides clarification regarding the identification of variable interests, the variable interest entity characteristics forcertain components of contracts that would represent a limited partnership or similar entity, and the primary beneficiary determination. Thislease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Southern Power is currently evaluating these requirements. The ultimate impact of this ASUthe new standard and 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 ondetermined 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.ultimate impact.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at March 31, 2015.2016. 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 used for operating activities totaled $110 million for the first three months of 2016, compared to $19 million for the first three months of 2015, a change of $129 million as compared to $110 million of net cash provided from operating activities for the first three months of 2014.2015. The decreaseincrease in cash provided fromused for operating activities was primarily due to an increase in unutilized federal ITCs created during the 2014 tax year that were repaid in the first three months of 2015 primarily due to bonus depreciation, as well as a reduction in accounts payable. The federal ITCs carried forward are expected to be utilized during the 2015 tax year.income taxes paid. Net cash used for investing activities totaled $38$873 million for the first three months of 20152016 primarily due to expenditures related toacquisitions and the construction of new solar facilities and payments pursuant to long-term service agreements.renewable facilities. Net cash provided from financing activities totaled $5$206 million for the first three months of 20152016 primarily due to the issuance of commercial paper, partially offset by the payment of common stock dividends.an increase in notes payable. Fluctuations in cash flow from financing activities vary yearfrom period to yearperiod based on capital needs and the

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the maturity or redemption of securities.
Significant balance sheet changes for the first three months of 20152016 include a $37$398 million increase in CWIP due to continued construction of new solar facilities and a $412 million increase in plant in service, primarily due to the construction of the Decatur County solar projects.facilities being placed in service. Other significant changes include a $54$777 million changedecrease in accumulated deferred income taxes, net of current deferred income tax items, primarily ascash and cash equivalents and a result of the timing and amount of ITCs utilized, partially offset by property related changes. Southern Power Company's$276 million increase in notes payable due to funding of acquisitions and construction projects, and income taxes. See FUTURE EARNINGS POTENTIAL "Acquisitions" herein for commercial paper increased by $38 million.additional information.
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.benefits, and other purchase commitments. Approximately $525$400 million will be required to fund maturities ofrepay long-term debt due July 15, 2015.September 28, 2016. There are no other scheduled maturities of long-term debt through March 31, 2016.2017. In addition, during the first quarter 2016, Southern Power entered into four new long-term service agreements (LTSA), which begin in 2020 and result in additional future commitments totaling approximately $627 million.
The capitalconstruction program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction. In addition, the construction as well as ongoingprogram includes capital improvements and work to be performed under long-term service agreements.LTSAs. 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 innumerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; 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 (I) to the Condensed Financial Statements herein for additional information.
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.
As of March 31, 2015,2016, Southern Power's current liabilities exceeded current assets by $318$977 million due to the long-term debt maturing in 2015 and2016, the use of short-term debt as a funding source, and construction payables, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.business and the stage of its acquisitions and construction projects. In 2015,2016, Southern Power expects to utilize the capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its maturities.
To meet liquidity and capital resource requirements,As of March 31, 2016, Southern Power had at March 31, 2015 cash and cash equivalents of approximately $23 million and$53 million.
Other than borrowings pursuant to the Project Credit Facilities (defined below), Southern Power had no short-term borrowings during the first quarter 2016.
Company Facility
At March 31, 2016, Southern Power had a committed credit facility (Facility) of $500$600 million (Facility) expiring in 2018,2020, of which $488$560 million iswas unused. Southern Power's subsidiaries are not borrowers under the Facility.

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

The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization (each as(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. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power Companyto the extent such debt is non-recourse to Southern Power , and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
Proceeds from thisthe Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power 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'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. Southern Power's subsidiaries are not borrowers under the commercial paper program.
Subsidiary Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of March 31, 2016.
124
Project Maturity Date Construction Loan Facility Bridge Loan Facility Total Total Undrawn Letter of Credit Facility Total Undrawn
    (in millions)
Tranquillity Earlier of COD or December 31, 2016 $86
 $172
 $258
 $52
 $77
 $26
Roserock Earlier of COD or November 30, 2016 63
 180
 243
 121
 23
 16
Garland Earlier of COD or November 30, 2016 86
 308
 394
 309
 49
 32
Total   $235
 $660
 $895
 $482
 $149
 $74
The Project Credit Facilities had total amounts outstanding as of March 31, 2016 of $413 million at a weighted average interest rate of 1.99%. For the three months ended March 31, 2016, these credit agreements had a maximum amount outstanding of $413 million, and an average amount outstanding of $260 million at a weighted average interest rate of 1.99%.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, bank term loans, and operating cash flows.

122

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

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.
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)
March 31, 2015: $233
 0.6% $156
 0.5% $234
(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 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 Baa3Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.management, and transmission.
The maximum potential collateral requirements under these contracts at March 31, 20152016 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and Baa2$9
At BBB and/or Baa2$11
At BBB- and/or Baa3310
$350
Below BBB- and/or Baa31,077
$1,063
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, anya credit rating downgrade could impact the ability of Southern Power's abilityPower to access capital markets particularlyand would be likely to impact the short-term debt market.cost at which it does so.
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'sPower'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
Southern Power did not issue or redeem any securities duringDuring the three months ended March 31, 2015.2016, Southern Power's subsidiary repaid $3 million of long-term debt payable to TRE and borrowed $2 million due February 28, 2036 under promissory notes payable to TRE.
During the three months ended March 31, 2016, Southern Power's subsidiaries borrowed $276 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.99%. In addition, Southern Power's subsidiaries issued $8 million in letters of credit.
Subsequent to March 31, 2016, Southern Power's subsidiaries borrowed $187 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.93%.
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.

125123


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





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


126124


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, 20142015 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 three-month periods ended March 31, 20152016 and 2014.2015. 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 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 at March 31, 2015. 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.
Recently Issued Accounting Standards
In May 2014,On February 25, 2016, the Financial Accounting Standards Board (FASB)FASB issued ASC 606,ASU No. 2016-02, Revenue from ContractsLeases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with Customers. ASC 606 revisesleases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be 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.
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. Thisexisting leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015. Southern Power is2018, with early adoption permitted. The registrants are currently evaluating these requirements. Thethe new standard and have not yet determined its ultimate impactimpact; however, adoption of this ASU 2016-02 is expected to have a significant impact on Southern Power has not yet been determined.Company and the traditional operating companies' balance sheets.
On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company and the traditional operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years

127125


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

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. Upon2016, with early 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 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this 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.
In the second quarter 2015,permitted. Southern Company and the traditional operating companies expect to record incremental asset retirement obligations (ARO) related toare currently evaluating the CCR Rule in amounts currently estimated to fall within the following ranges:new standard and have not yet determined its ultimate impact.
 Low High
 (in millions)
Southern Company$525
 $575
Alabama Power$330
 $350
Georgia Power$10
 $20
Gulf Power$70
 $80
Mississippi Power$75
 $85
(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.

128


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

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 seek 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 litigated in the U.S. District Court for the Northern District of Alabama, resulting in 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 for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. In 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.
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 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.affected sites. 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 March 31, 20152016 was $27$28 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 partiesPRPs at the Brunswick site have completed thea removal of wastes from the Brunswick siteaction as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damagesresponse actions at this site orare anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the assessmentBrunswick site. 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

129


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

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. On March 20, 2015, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court's ruling. The plaintiffs may seek review by the U.S. Supreme Court.
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 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$46 million as of March 31, 2015.2016. 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 $0.5 million as
126


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

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,and 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.
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 March 31, 2015 for any potential recoveries from

130


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

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, 2015,2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgofor an increase in wholesale base revenues as agreed upon in the settlement agreement reached with its wholesale customers under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement provides that base rates under the MRA cost-based electric tariff will increase reflectedapproximately $7 million annually, with revised rates effective for services rendered beginning May 1, 2016. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. Additionally, under the filing by, amongsettlement agreement, the tariff customers agreed in principle to similar regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking under the Mississippi PSC order (In-Service Asset Rate Order). The Kemper IGCC regulatory treatment primarily includes (i) recovery of only the Kemper IGCC assets currently operational and providing service to customers and other things, increasingrelated costs and (ii) removing all of the Kemper IGCC CWIP with a corresponding increase in accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, if acceptedeffective May 1, 2016. If approved by the FERC, provides that the additional accrualamount of AFUDCbase rate revenues to be recognized in 2016 is effective April 1, 2015.expected to be approximately $5 million. The additional resulting AFUDC is projectedestimated to be approximately $12 million annually, of which $9 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.$6 million. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At March 31, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $25 million compared to $24 million at December 31, 2015. See Note 3 to the financial statements of Mississippi Power under "FERC Matters Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
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,in 2014, which included continued reliance on the energy auction as tailored mitigation. OnIn 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, theThe FERC has directed the traditional operating companies and Southern Power within 60 days, 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 are evaluatingfiled a request for rehearing in May 2015 and in June 2015 filed their response with the order.FERC. The ultimate outcome of this matter cannot be determined at this time.

131127


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

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 recovery on the balance sheet follows:
Regulatory Clause
Balance Sheet Line ItemMarch 31, 2015
December 31,
2014



(in millions)
Rate CNP Compliance – Under*

Deferred under recovered regulatory clause revenues$25

$2
  Under recovered regulatory clause revenues, current16
 47
Rate CNP PPA – Under
Deferred under recovered regulatory clause revenues62

29
  Under recovered regulatory clause revenues, current
 27
Retail Energy Cost Recovery – Over
Deferred over recovered regulatory clause revenues81

47
Natural Disaster Reserve
Other regulatory liabilities, deferred82

84
* Formerly Known As Rate CNP Environmental
Rate CNP
In March 2015, the Emerging Issues Task Force unanimously recommended to allow the normal purchases and normal sales exception for physical forward transactions in nodal energy markets. The FASB proposed new accounting guidance reflecting the recommendation on April 23, 2015. This guidance is subject to a public comment period before the FASB issues a final accounting standard. The ultimate outcome of this matter cannot be determined at this time.
Rate CNP Compliance(Formerly Known As Rate CNP Environmental)
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.
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 $14 million of non-environmental compliance costs during the first quarter 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 the year.
Regulatory Clause
Balance Sheet Line ItemMarch 31, 2016
December 31, 2015



(in millions)
Rate CNP Compliance Under recovered regulatory clause revenues, current$22
 $43
Rate CNP PPA
Deferred under recovered regulatory clause revenues105

99
Retail Energy Cost Recovery
Other regulatory liabilities, current173

238


Deferred over recovered regulatory clause revenues64


Natural Disaster Reserve
Other regulatory liabilities, deferred74

75
Georgia Power
Integrated Resource PlanRate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated ResourceRate Plans" and "Retail Regulatory Matters – Integrated ResourceRate Plans," respectively, in Item 8 of the Form 10-K for additional information.

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

To comply withGeorgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the April 16, 2015 effective dateoversight of the MATS rule,Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant BranchVogtle Units 1, 3 and 4 (1,266 MWs), Plant Yates Units 1are being collected through 5 (579 MWs),the NCCR tariff and Plant McManus Units 1fuel costs are collected through separate fuel cost recovery tariffs. See "Fuel Cost Recovery" below and 2 (122 MWs) were retiredNote 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery and the NCCR tariff, respectively.
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs)14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and its decertificationGeorgia Power will be requestedrequired to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) will retain the merger savings, net of transition costs, as defined in connectionthe settlement agreement; through December 31, 2022, net merger savings will be shared on a 60/40 basis between customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Unit 7 and is underway at Plant Yates Unit 6. Plant Yates Unit 7 was returned to service on May 4, 2015 and Plant Yates Unit 6 is expected to return to service in mid-2015.Merger.
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 March 31, 2016 and December 31, 2015, Georgia Power's underover recovered fuel balance totaled $151$177 million and $116 million, respectively, and is included in current assetsliabilities and other deferred charges and assetsliabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein. AsOn April 14, 2016, Georgia Power filed a

128


request with the Georgia PSC approved the deferral ofto decrease fuel rates by 15% effective June 1, 2016, which is expected to reduce annual billings by approximately $313 million. Georgia Power'sPower is currently scheduled to file its next fuel case filing untilby February 28, 2017. The ultimate outcome of this matter cannot be determined at least June 30, 2015.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 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, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and pending litigation.the Contractor Settlement Agreement (as defined below).
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. 4 (Vogtle 3 and 4 Agreement).
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 isguarantees, 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 the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.
On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.)WECTEC under the Vogtle 3 and 4 Agreement arewere originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (a(which is now a subsidiary of Chicago Bridge & Iron Company, N.V.)CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. 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. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.
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

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

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 workGeorgia PSC voted to begin oncertify construction of 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). 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 has subsequently asserted related minimum damages (based on Georgia Power's ownership interest) of $113 million. 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.
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% above the certified cost 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. In February 2013, Georgia Power's eighth VCM report filed in 2013Power 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

129


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

billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into bybetween Georgia Power and the Georgia PSC staffStaff (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
On April 15, 2015, 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).

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

Georgia Power does not believe that the Contractor's revised forecast reflects all efforts that may be possible to mitigate the Contractor's delay. In addition, 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. Consistentissued a procedural order in connection 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 for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated owner'sVogtle 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 Pursuant 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 aPSC's 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 and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.
On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $241 million had been paid as of March 31, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.
On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. The Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the

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

Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.
The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.
The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.7 billion as of March 31, 2016.
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 may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the DCDWestinghouse Design Control Document and the COLs,combined construction and operating licenses, 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 tomay 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.
AdditionalFuture claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely tocould arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement but alsoand, under the enhanced dispute resolution procedures, may be resolved through litigation.

135

Tablelitigation after the completion of Contentsnuclear fuel load for both units.

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

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 providing 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 retail ROE, as reported to the Florida PSC

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

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 inFor 2014, 2015, and the first three months of 2015.2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $5.6 million, respectively.
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 recovery on the balance sheet follows:
Recovery Clause
Balance Sheet Location
March 31, 2015
December 31, 2014




(in millions)
Fuel Cost Recovery – Under
Under recovered regulatory clause revenues
$32

$40
Purchased Power Capacity Recovery – Under
Under recovered regulatory clause revenues
3


Environmental Cost Recovery – Under
Under recovered regulatory clause revenues
12

10
Energy Conservation Cost Recovery – Under
Under recovered regulatory clause revenues
1

3
Regulatory Clause
Balance Sheet Location
March 31, 2016
December 31, 2015




(in millions)
Fuel Cost Recovery
Other regulatory liabilities, current
$20

$18
Purchased Power Capacity Recovery
Under recovered regulatory clause revenues
4

1
Environmental Cost Recovery Under recovered regulatory clause revenues 17
 19
Energy Conservation Cost Recovery Other regulatory liabilities, current 2
 4
Mississippi Power
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,April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2014,2015, which indicated noreflected the need for a $5 million surcharge or refund. On March 26, 2015,to be recovered from customers. The filing has been suspended for review by the Mississippi PSC suspended the filing to allow more time for review.
PSC. 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 more time for review.
The ultimate outcome of this matter cannot be determined at this time.

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

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 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 in December 2015. As of March 31, 2015, total project expenditures were $570 million, of which Mississippi Power's portion was $290 million, excluding AFUDC of $22 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. The filing is under review by the Mississippi PSC.
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 retail fuel cost recovery.
At March 31, 2015,2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $15$80 million compared to under-recoveredover-recovered retail fuel costs of $2$71 million at December 31, 2014.2015.
Ad Valorem Tax Adjustment
See Note 3The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 ofPSC. If approved by the Form 10-K forMississippi PSC, the updated forecast would decrease fuel cost recovery rates by an 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$36 million in annual retail revenues, primarily due to a decrease in average millage rates.
annually. 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

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

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.

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

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(Initial 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 continuescurrently expects to focus on completingplace the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for whichin service during the in-service date is currently expected to occur in the first halfthird quarter 2016.

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

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) remainremains 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)decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of March 31, 2015, as adjusted for the Court's decision,2016, are as follows:

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

Cost Category
2010 Project Estimate(f)
 Current Estimate Actual Costs at March 31, 2015
2010 Project Estimate(f)
 
Current Cost Estimate(a)
 Actual Costs
(in billions)(in billions)
Plant Subject to Cost Cap(a)(g)
$2.40
 $4.94
 $4.37
$2.40
 $5.35
 $4.99
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
 0.12
AFUDC(b)(c)
0.17 0.64 0.48
AFUDC(c)
0.17
 0.71
 0.62
Combined Cycle and Related Assets Placed in
Service – Incremental
(d)(g)

 0.02
 

 0.02
 0.01
General Exceptions0.05 0.10 0.080.05
 0.10
 0.09
Deferred Costs(e)(g)

 0.18 0.14
 0.20
 0.18
Total Kemper IGCC(a)(c)
$2.97
 $6.22
 $5.40
Additional DOE Grants(h)

 (0.14) 
Total Kemper IGCC$2.97
 $6.58
 $6.24
(a)Amounts in the Current Cost Estimate reflect estimated costs through September 30, 2016.
(b)The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the 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" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.
(b)(c)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 $9 million increase in AFUDC related toreflects the impact of 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" herein 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."Liabilities" herein.
(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.
(g)Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at March 31, 2016.
(h)On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers.
Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2015, $3.272016, $3.61 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants and estimated probable losses of $2.06$2.47 billion), $2$6 million in other property and investments, $52$75 million in fossil fuel stock, $35$45 million in materials and supplies, $174$22 million in other regulatory assets, $12current, $196 million in other regulatory assets, deferred, $1 million in other current assets, and $11 million in other deferred charges and assets and $24 million in AROs in the balance sheet, with $1 million previously expensed.sheet.

134


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

Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $9$53 million ($633 million after tax) in the first quarter 2015. This amount is2016. Since 2012, in addition tothe aggregate, Mississippi Power has incurred charges totaling $868 million ($536 million after tax), $1.10of $2.47 billion ($681 million after tax), and $78 million ($48 million1.52 billion after tax) as a result of changes 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.above the cost cap for the Kemper IGCC through March 31, 2016. The increasesincrease to the cost estimate in the first quarter 20152016 primarily reflectedreflects costs for the extension of the Kemper IGCC's projected in-service date through September 30, 2016, and increased efforts related to additional labor costsoperational readiness and challenges in support of start-up and operational readiness activities. The current estimatecommissioning activities which includes costs through March 31, 2016.the cost of repairs and modifications to the refractory lining inside the gasifiers. Any further extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $30$35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any further extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 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$14 million per month, as well as carrying

139


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

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 totalof approximately $6$2 million per month. For additional information, see "2015 Rate Case" herein.
Any furtherMississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. 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 constructionoperating 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 Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and Mississippi Power's statements of operationsincome and these changes could be material.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional tax information related to the Kemper IGCC.
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 Rate Mitigation Plan (defined below) and any alternativefuture proceedings related to the operation of the Kemper

135


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

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 AgreementMPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that among other things, establishedwas intended to establish 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 estimated in-service date until securitization is finalized and other costs not included in the Rate Mitigation Plan as

140


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

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, inIn 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). For the period from March 2013 through March 31, 2015, $294 million had been collected primarily to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. service, based on a mirror CWIP methodology (Mirror CWIP rate).
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.IGCC. 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 collect and defer the approved rates 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. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, 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. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order.
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 and 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 incurred to support operation of 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" 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 filed by Thomas A. Blanton. 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. The Court's ruling remands the matter toOn July 7, 2015, the Mississippi PSC to (1) fix by orderordered that the rates that were in existence prior toMirror CWIP rate be terminated effective July 20, 2015 and required the 2013 MPSC Rate Order, (2) fix no rate increases untilfourth quarter 2015 refund of the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts$342 million collected under the 2013 MPSC Rate Order. Through March 31,Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.
2015 Rate Case
As a result of the 2015 Court decision, on July 10, 2015, Mississippi Power had collected $294filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) 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. On August 13, 2015, the Mississippi PSC approved the implementation of the requested interim rates designed to collect approximately $159 million through rates underannually effective with the 2013 MPSCfirst billing cycle in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order. Any required refunds would also include carryingOrder adopting in full a stipulation entered into between Mississippi Power and the Mississippi Public Utilities Staff (MPUS) regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The Court's decision will become legally effective uponIn-Service Asset Rate Order also included a prudence finding of all costs in the issuancestipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of a mandatethe Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi PSC. Absent specific instruction fromPower continues to evaluate its alternatives with respect to its investment and related costs associated with the Court, the15% undivided interest.

141136


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

Mississippi PSC will determine the method and timingWith implementation of the refund. Onnew rate on December 17, 2015, the interim rates were terminated and, in March 12, 2015,2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.
On February 25, 2016, Greenleaf CO2 Solutions, LLC filed motions for rehearing. Ifa notice of appeal of the In-Service Asset Rate Order with the Court. On May 5, 2016, the Court deniesdismissed the motions, it would issue the mandateappeal.
Legislation to the Mississippi PSC no later than seven days following such decision.
Rate Mitigation Plan
In 2013,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 expects to securitize prudently-incurred qualifying facility costs in compliance withexcess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order filed a revisiondid not impact Mississippi Power's ability to utilize alternate financing through securitization or the proposedFebruary 2013 legislation.
Mississippi Power expects to seek additional rate relief to address recovery plan withof the Mississippi PSC for theremaining Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015.In the Rate Mitigation 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, was integral to the Rate Mitigation 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 Rate Mitigation 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 would review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" herein for additional information.
To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See "2015 Mississippi Supreme Court Decision" herein for additional information.
assets. In addition to current estimated costs at March 31, 20152016 of $6.22$6.58 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.
Mississippi Power also expects to seek rate recovery through alternate means, which could include a traditional rate case. On May 1, 2015, Mississippi Power notified the Mississippi PSC of its plans to file a rate request in May 2015.
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. As a result of the Court's decision, Mississippi Power intends to request that the Mississippi PSC reconsider its prudence review schedule. See "2015 Mississippi Supreme Court Decision" 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,

142


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

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. Beginning in the third quarter 2015, in connection with the implementation of interim rates, Mississippi Power began expensing certain ongoing project costs and certain debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order. As of March 31, 2015,2016, the regulatory asset balance associated with these regulatory assets was $120 million, of which $22 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC was $174 million. The projected balance attotaled $98 million as of March 31, 2016 is estimated to total approximately $266 million.2016. The amortization period for any such costs approved for recovery remains subjectthese assets is expected to approvalbe determined by the Mississippi PSC.PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
The 2013See "2013 MPSC Rate Order approved retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designedOrder" herein for information related to collect $156 million annually beginning in 2014. On February 12,the July 7, 2015 the Court ordered the Mississippi PSC to refund Mirror CWIP and to fix by order the rates that were in existence prior to the 2013 MPSC Rate Order. Mississippi Power is deferring the collections under the approved rates interminating the Mirror CWIP regulatory liability until otherwise directed by the Mississippi PSC. Mississippi Power is also accruing carrying costs on the unamortized balancerate and requiring refund of thecollections under Mirror CWIP regulatory liability for the benefit of retail customers. As of March 31, 2015, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $311 million.
See "2015 Mississippi Supreme Court Decision" herein for additional information.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.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of

137


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

March 31, 2016, Mississippi Power recorded a related regulatory liability of approximately $3 million. See "2015 Rate Case" herein 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 Denbury and Treetop with 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 CO2 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 respective agreements, anyagreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO2 off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO2 contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in future chemical product salesMississippi Power's 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. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.
The ultimate outcome of these matters cannot be determined at this time.
Civil Lawsuit
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean. The plaintiffs allege that Mississippi Power violated the Mississippi Unfair Trade Practices Act and concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that Mississippi Power's alleged breaches interfered with and destroyed economically advantageous relationships between the plaintiffs and their current and prospective business associates. The plaintiffs seek unspecified actual damages and punitive damages as well as attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could impact Southern Company's results of operations, financial condition, and liquidity and could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend the matter, and the final outcome of this matter cannot be determined at this time.

143138


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

(C)FAIR VALUE MEASUREMENTS
As of March 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
 Fair Value Measurements Using    
As of March 31, 2016:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Net Asset Value as a Practical Expedient (NAV) Total
 (in millions)
Southern Company         
Assets:         
Energy-related derivatives$
 $12
 $
 $
 $12
Interest rate derivatives
 33
 
 
 33
Nuclear decommissioning trusts(a)
624
 898
 
 16
 1,538
Cash equivalents503
 
 
 
 503
Other investments9
 
 1
 
 10
Total$1,136
 $943
 $1
 $16
 $2,096
Liabilities:         
Energy-related derivatives$
 $201
 $
 $
 $201
Interest rate derivatives
 193
 
 
 193
Total$
 $394
 $
 $
 $394
          
Alabama Power         
Assets:         
Energy-related derivatives$
 $3
 $
 $
 $3
Nuclear decommissioning trusts(b)
        

Domestic equity365
 67
 
 
 432
Foreign equity46
 48
 
 
 94
U.S. Treasury and government agency securities
 25
 
 
 25
Corporate bonds11
 137
 
 
 148
Mortgage and asset backed securities
 21
 
 
 21
Private Equity
 
 
 16
 16
Other
 9
 
 
 9
Cash equivalents321
 
 
 
 321
Total$743
 $310
 $
 $16
 $1,069
Liabilities:         
Energy-related derivatives$
 $49
 $
 $
 $49

139


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

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 they agreed to amend a 2011 power supply agreement between the parties 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 2011 power supply agreement were $4 million in the first quarter 2015 and $17 million in 2014.
By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle on certain issues related 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 payable 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 Kemper IGCC 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 provided 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.
 Fair Value Measurements Using    
As of March 31, 2016:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Net Asset Value as a Practical Expedient (NAV) Total
 (in millions)
Georgia Power         
Assets:         
Energy-related derivatives$
 $4
 $
 $
 $4
Interest rate derivatives
 14
 
 
 14
Nuclear decommissioning trusts(b) (c)
         
Domestic equity180
 1
 
 
 181
Foreign equity
 115
 
 
 115
U.S. Treasury and government agency securities
 111
 
 
 111
Municipal bonds
 66
 
 
 66
Corporate bonds
 146
 
 
 146
Mortgage and asset backed securities
 145
 
 
 145
Other22
 7
 
 
 29
Cash equivalents57
 
 
 
 57
Total$259
 $609
 $
 $
 $868
Liabilities:         
Energy-related derivatives$
 $11
 $
 $
 $11
          
Gulf Power         
Assets:         
Cash equivalents$20
 $
 $
 $
 $20
Liabilities:         
Energy-related derivatives$
 $94
 $
 $
 $94
Interest rate derivatives
 5
 
 
 5
Total$
 $99
 $
 $
 $99
          
Mississippi Power         
Assets:         
Cash equivalents$24
 $
 $
 $
 $24
Liabilities:         
Energy-related derivatives$
 $44
 $
 $
 $44
          
Southern Power         
Assets:         
Energy-related derivatives$
 $5
 $
 $
 $5
Interest rate derivatives
 1
 
 
 1
Cash equivalents39
 
 
 
 39
Total$39
 $6
 $
 $
 $45
Liabilities:         
Energy-related derivatives$
 $3
 $
 $
 $3
By letter dated December 18, 2014, SMEPA notified Mississippi Power that SMEPA decided not to extend the December 31, 2014 estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination.
The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, 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.
In 2012, in January 2014, and in October 2014, Mississippi Power received $150 million, $75 million, and $50 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. Accordingly, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any refund of the deposits to SMEPA. The ultimate outcome of these matters cannot be determined at this time.
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 March 31, 2015, Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $207 million had 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

144140


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

Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. In addition, a portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's proposed purchase of an undivided interest in the Kemper IGCC as described above. The ultimate outcome of this matter cannot be determined at this time.
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. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits totaling approximately $211 million at March 31, 2015. See Note 5 to the financial statements of Southern Company and Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Note (G) herein under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this matter cannot be determined at this time.

145


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

(C)FAIR VALUE MEASUREMENTS
As of March 31, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
  Fair Value Measurements Using  
As of March 31, 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)
Southern Company        
Assets:        
Energy-related derivatives $
 $7
 $
 $7
Interest rate derivatives 
 8
 
 8
Nuclear decommissioning trusts(a)
 632
 937
 4
 1,573
Cash equivalents 863
 
 
 863
Other investments 9
 
 1
 10
Total $1,504
 $952
 $5
 $2,461
Liabilities:        
Energy-related derivatives $
 $225
 $
 $225
Interest rate derivatives 
 46
 
 46
Total $
 $271
 $
 $271
         
Alabama Power        
Assets:        
Energy-related derivatives $
 $1
 $
 $1
Nuclear decommissioning trusts(b)
        
Domestic equity 393
 90
 
 483
Foreign equity 36
 65
 
 101
U.S. Treasury and government agency securities 
 34
 
 34
Corporate bonds 10
 113
 
 123
Mortgage and asset backed securities 
 18
 
 18
Other 
 6
 4
 10
Cash equivalents 287
 
 
 287
Total $726
 $327
 $4
 $1,057
Liabilities:        
Energy-related derivatives $
 $59
 $
 $59
Interest rate derivatives 
 14
 
 14
Total $
 $73
 $
 $73

146


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

  Fair Value Measurements Using  
As of March 31, 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)
Georgia Power        
Assets:        
Energy-related derivatives $
 $6
 $
 $6
Interest rate derivatives 
 6
 
 6
Nuclear decommissioning trusts(b) (c)
        
Domestic equity 182
 2
 
 184
Foreign equity 
 126
 
 126
U.S. Treasury and government agency securities 
 86
 
 86
Municipal bonds 
 92
 
 92
Corporate bonds 
 192
 
 192
Mortgage and asset backed securities 
 107
 
 107
Other 11
 6
 
 17
Cash equivalents 406
 
 
 406
Total $599
 $623
 $
 $1,222
Liabilities:        
Energy-related derivatives $
 $24
 $
 $24
Interest rate derivatives 
 31
 
 31
Total $
 $55
 $
 $55
         
Gulf Power        
Assets:        
Cash equivalents $18
 $
 $
 $18
Liabilities:        
Energy-related derivatives 
 90
 
 90
         
Mississippi Power        
Assets:        
Cash equivalents $110
 $
 $
 $110
Liabilities:        
Energy-related derivatives 
 52
 
 52
         
Southern Power        
Assets:        
Cash equivalents $3
 $
 $
 $3
(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, payables related to pending investment 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 March 31, 2015,2016, approximately $50$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.

147

TableSouthern 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 months ended March 31, 2016 and March 31, 2015, the change in fair value of Contentsthe funds, including reinvested interest and dividends and excluding the funds' expenses, increased by $20 million and $33 million, respectively, at Southern Company. For the three months ended March 31, 2016 and March 31, 2015, Alabama Power recorded an increase in fair value of $11 million and $15 million, respectively, as an increase in regulatory liabilities related to its asset retirement obligations. For the three months ended March 31, 2016 and March 31, 2015, Georgia Power recorded an increase in fair value of $9 million and $18 million, respectively, as a reduction of its regulatory asset related to its asset retirement obligations.

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

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 derivatives are also standard over-the-counter financial products that are valued using theobservable market approach. Inputs fordata and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include LIBOR interest rates, interest rate futures contracts,the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) herein for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing 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,judgments, are also obtained when available.
Investments See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in private equity and real estate within Alabama 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 natureItem 8 of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.Form 10-K for additional information.
"Other investments" include investments that are not traded in the open market. 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 executions.

148141


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

As of March 31, 2015,2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent), as a practical expedient, as well as the nature and risks of those investments, were as follows:
As of March 31, 2015: 
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
  (in millions)      
Southern Company      
Nuclear decommissioning trusts:        
Foreign equity funds $126
 None Monthly 5 days
Equity - commingled funds 65
 None Daily/Monthly Daily/7 days
Debt - commingled funds 16
 None Daily 5 days
Other - commingled funds 6
 None Daily Not applicable
Other - money market funds 11
 None Daily Not applicable
Trust-owned life insurance 118
 None Daily 15 days
Cash equivalents:        
Money market funds 863
 None Daily Not applicable
Alabama Power        
Nuclear decommissioning trusts:        
Equity - commingled funds $65
 None Daily/Monthly Daily/7 days
Debt - commingled funds 16
 None Daily 5 days
Trust-owned life insurance 118
 None Daily 15 days
Cash equivalents:        
Money market funds 287
 None Daily Not applicable
Georgia Power        
Nuclear decommissioning trusts:        
Foreign equity funds $126
 None Monthly 5 days
Other - commingled funds 6
 None Daily Not applicable
Other - money market funds 11
 None Daily Not applicable
Cash equivalents:        
Money market funds 406
 None Daily Not applicable
Gulf Power        
Cash equivalents:        
Money market funds $18
 None Daily Not applicable
Mississippi Power        
Cash equivalents:        
Money market funds $110
 None Daily Not applicable
Southern Power        
Cash equivalents:        
Money market funds $3
 None Daily Not applicable
As of March 31, 2016: 
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
  (in millions)    
Southern Company $16
 $29
 Not Applicable Not Applicable
Alabama Power $16
 $29
 Not Applicable Not Applicable
The NRC requires licensees of commissioned nuclear power reactors to establishPrivate equity funds include 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 primarilyfund-of-funds that invests in high-quality private equity funds across several market sectors, a diversified portfolio of equity securities of foreign companies, including thosefund that invests 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 American depositary receipts, European depositary receipts,assets, and global depositary receipts), and rights and warrantsa fund that acquires companies 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

149


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

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 foreigncreate resale value. Private equity fund, then the foreign equity fund's board may refuse to 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.
The other-commingled funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio of high-quality, short-term, liquid debt securities. The funds represent cash collateral received under the Funds' managers' securities lending program and/or excess cash held within each separate investment account. The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or 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 trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios 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 trusts do not ownhave redemption rights. Distributions from these funds will be received as 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. These 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 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 months ended March 31, 2015, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $65 million at Southern Company. For the three months ended March 31, 2015, Alabama Power recorded an increase in fair value of $47 million as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $18 million as a reduction of its regulatory asset related to its ARO.
The money market funds are short-term investments of excess funds inliquidated. Liquidations are expected to occur at various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated bytimes over 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.next ten years.

150


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

As of March 31, 2015,2016, 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 $24,241
 $26,350
 $28,341
 $29,827
Alabama Power $6,922
 $7,696
 $7,089
 $7,688
Georgia Power $9,801
 $10,733
 $10,549
 $11,400
Gulf Power $1,370
 $1,501
 $1,303
 $1,366
Mississippi Power $2,251
 $2,323
 $3,209
 $2,938
Southern Power $1,621
 $1,789
 $3,123
 $3,171
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 effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
 Three Months
Ended
March 31, 2015

Three Months
Ended
March 31, 2014
 Three Months Ended March 31, 2016
Three Months Ended March 31, 2015
 (in millions) (in millions)
As reported shares 910
 890
 916
 910
Effect of options and performance share award units 5
 3
 6
 5
Diluted shares 915
 893
 922
 915

142


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

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three months ended March 31, 20152016 and were 17 million for the three months ended March 31, 2014.2015.

151


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

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 Noncontrolling Interest Issued Treasury 
Noncontrolling Interests(*)
 
(in thousands) (in millions)(in thousands) (in millions)
Balance at December 31, 2015915,073
 (3,352) $20,592
 $609
 $781
 $21,982
Consolidated net income attributable to Southern Company
 
 485
 
 
 485
Other comprehensive income (loss)
 
 (114) 
 
 (114)
Stock issued6,572
 
 270
 
 
 270
Stock-based compensation
 
 60
 
 
 60
Cash dividends on common stock
 
 (497) 
 
 (497)
Contributions from noncontrolling interests
 
 
 
 129
 129
Distributions to noncontrolling interests
 
 
 
 (4) (4)
Purchase of membership interests from noncontrolling interests
 
 
 
 (129) (129)
Net income attributable to noncontrolling interests
 
 
 
 1
 1
Other
 (35) 1
 
 
 1
Balance at March 31, 2016921,645
 (3,387) $20,797
 $609
 $778
 $22,184
           
Balance at December 31, 2014908,502
 (725) $19,949
 $756
 $221
 $20,926
908,502
 (725) $19,949
 $756
 $221
 $20,926
Net income after dividends on preferred and preference stock
 
 508
 
 
 508
Consolidated net income attributable to Southern Company
 
 508
 
 
 508
Other comprehensive income (loss)
 
 (15) 
 
 (15)
 
 (15) 
 
 (15)
Stock issued3,094
 
 112
 
 
 112
3,094
 
 112
 
 
 112
Stock-based compensation
 
 53
 
 
 53

 
 53
 
 
 53
Stock repurchased, at cost
 (2,599) (115) 
 
 (115)
 (2,599) (115) 
 
 (115)
Cash dividends on common stock
 
 (478) 
 
 (478)
 
 (478) 
 
 (478)
Other
 (11) 3
 
 
 3

 (11) 3
 
 
 3
Balance at March 31, 2015911,596
 (3,335) $20,017
 $756
 $221
 $20,994
911,596
 (3,335) $20,017
 $756
 $221
 $20,994
           
Balance at December 31, 2013892,733
 (5,647) $19,008
 $756
 $
 $19,764
Net income after dividends on preferred and preference stock
 
 351
 
 
 351
Other comprehensive income (loss)
 
 2
 
 
 2
Treasury stock re-issued
 2,404
 111
 
 
 111
Stock issued1,340
 
 53
 
 
 53
Stock repurchased, at cost
 
 (4) 
 
 (4)
Cash dividends on common stock
 
 (451) 
 
 (451)
Other
 (18) 
 
 
 
Balance at March 31, 2014894,073
 (3,261) $19,070
 $756
 $
 $19,826
(*)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 March 31, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.

152143


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

(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 March 31, 20152016 was approximately $1.8 billion (comprised of approximately $864$810 million at Alabama Power, $865$868 million at Georgia Power, $69$82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at March 31, 2015,2016, the traditional operating companies had approximately $396$269 million (comprised of approximately $200$167 million at Alabama Power, $118$69 million at Georgia Power, and $78$33 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that were 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. Subsequent to March 31, 2015, $80 million and $65 million of these fixed rate pollution control revenue bonds were purchased and are being held by Alabama Power and Georgia Power, respectively, and currently are not required to be remarketed within the next 12 months. See "Financing Activities" herein for additional information.
The following table outlines the committed credit arrangements by company as of March 31, 2015:2016:
 Expires   
Executable Term
Loans
 
Due Within One
Year
Expires   
Executable Term
Loans
 
Due Within One
Year
Company 2015
 2016
 2017 2018 Total Unused 
One
Year
 
Two
Years
 
Term
Out
 
No Term
Out
2016
201720182020 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)
Southern Company(a) $
 $
 $
 $1,000
 $1,000
 $1,000
 $
 $
 $
 $
$
$
$1,000
$1,250 $2,250
 $2,250
 $
 $
 $
 $
Alabama Power 228
 50
 
 1,030
 1,308
 1,308
 58
 
 58
 170
40

500
800
 1,340
 1,340
 
 
 
 40
Georgia Power 
 150
 
 1,600
 1,750
 1,736
 
 
 
 150



1,750
 1,750
 1,732
 
 
 
 
Gulf Power 45
 200
 30
 
 275
 275
 50
 
 50
 195
75
40
165

 280
 280
 45
 
 45
 40
Mississippi Power 135
 165
 
 
 300
 270
 25
 40
 65
 235
205



 205
 180
 30
 15
 45
 160
Southern Power 
 
 
 500
 500
 488
 
 
 
 
Southern Power Company (b)



600
 600
 560
 
 
 
 
Other 70
 
 
 
 70
 70
 20
 
 20
 50
70



 70
 70
 20
 
 20
 50
Total $478
 $565
 $30
 $4,130
 $5,203
 $5,147
 $153
 $40
 $193
 $800
$390
$40
$1,665
$4,400 $6,495
 $6,412
 $95
 $15
 $110
 $290
(a)Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.
(b)Excluding its subsidiaries. See "Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.
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 intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue a minimum of $8.0 billion in debt prior to closing the Merger and a minimum of $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, the proposed acquisition of PowerSecure International, Inc. (PowerSecure), and Southern Power and other Southern Company system capital projects. Total capital raised in 2016 may increase due to cash needed at the closing of the Merger, settlement of hedges, and incremental investment opportunities, including additional Southern Power projects in excess of its current capital plans. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. As of March 31, 2016, Southern Company had no outstanding loans under the Bridge Agreement. See Note (I) under "Southern Company Proposed Merger with AGL Resources" for additional information regarding the Merger. See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information regarding the Bridge Agreement.

153144


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

Southern Power Project Credit Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of March 31, 2016.
Project Maturity Date Construction Loan Facility Bridge Loan Facility Total Total Undrawn Letter of Credit Facility Total Undrawn
    (in millions)
Tranquillity Earlier of COD or December 31, 2016 $86
 $172
 $258
 $52
 $77
 $26
Roserock Earlier of COD or November 30, 2016 63
 180
 243
 121
 23
 16
Garland Earlier of COD or November 30, 2016 86
 308
 394
 309
 49
 32
Total   $235
 $660
 $895
 $482
 $149
 $74
The Project Credit Facilities had total amounts outstanding as of March 31, 2016 of $413 million at a weighted average interest rate of 1.99%. For the three months ended March 31, 2016, these credit agreements had a maximum amount outstanding of $413 million, and an average amount outstanding of $260 million at a weighted average interest rate of 1.99%.
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2015:2016:
Company(a)
Senior Note Issuances 
Senior
Note Redemptions
 
Other
Long-Term
Debt Redemptions
and Maturities(b)
Senior Note Issuances 
Senior
Note Maturities and Redemptions
 Revenue
Bond
Maturities Redemptions and
Repurchases
 
Other
Long-Term
Debt
Issuances
 
Other
Long-Term
Debt Redemptions
and
Maturities(b)
(in millions)(in millions)
Alabama Power$550
 $250
 $
$400
 $200
 $
 $45
 $
Georgia Power
 
 3
650
 250
 4
 
 1
Mississippi Power
 
 76

 
 
 1,100
 426
Southern Power
 
 
 2
 3
Other
 
 4

 
 
 
 4
Elimination(c)

 
 
 (200) 
Total$550
 $250
 $83
$1,050
 $450
 $4
 $947
 $434
(a)Southern Company Gulf Power, and SouthernGulf Power did not issue or redeem any long-term debt during the first three months of 2015.2016.    
(b)Includes reductions in capital lease obligations resulting from cash payments under capital leases.
(c)Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.
Alabama Power
In March 2015, Alabama Power issued $550 million aggregate principal amount of Series 2015A 3.750% Senior Notes due March 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, 2035 and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequent to March 31, 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 may reoffer these bonds to the public at a later date.
Also subsequent to March 31, 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 will be used for the announced redemption on May 15, 2015 of 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 will be used for general corporate purposes, including Alabama Power's continuous construction program.
Georgia Power
Subsequent to March 31, 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 may reoffer these bonds to the public at a later date.
Mississippi Power
Subsequent to March 31, 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.

154145


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

MississippiAlabama Power
In January 2016, Alabama Power also amendedissued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of Alabama Power's Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including Alabama Power's continuous construction program.
In March 2016, Alabama Power entered into three outstanding floating rate bank loans forterm loan agreements with maturity dates of March 2021, in an aggregate principal amount of $425$45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR.
Georgia Power
In March 2016, Georgia Power issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016, to repay a portion of Georgia Power's short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.
Mississippi Power
In January 2016, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which amongmatures on December 1, 2017, bearing interest based on one-month LIBOR. As of March 31, 2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015.
On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other things, extendedgeneral corporate purposes. Mississippi Power borrowed $900 million under the maturity dates from various datesterm loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in 2015maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2016.2018 and bears interest based on one-month LIBOR.
Also in March 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2016, bearing interest based on three-month LIBOR.
Southern Power
During the three months ended March 31, 2016, Southern Power's subsidiary repaid $3 million of long-term debt payable to Turner Renewable Energy, LLC (TRE) and borrowed $2 million due February 28, 2036 under promissory notes payable to TRE.
During the three months ended March 31, 2016, Southern Power's subsidiaries borrowed $276 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.99%. In addition, Southern Power's subsidiaries issued $8 million in letters of credit.
(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,

146


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

as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015.2016. 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.
Components of the net periodic benefit costs for the three months ended March 31, 2015 and 20142016 were as follows:
Pension Plans 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 (in millions) (in millions)
Three Months Ended March 31, 2016          
Service cost $62
 $14
 $17
 $3
 $3
Interest cost 100
 24
 34
 5
 5
Expected return on plan assets (187) (46) (64) (9) (9)
Amortization:          
Prior service costs 4
 1
 1
 
 
Net (gain)/loss 38
 10
 14
 2
 2
Net cost $17
 $3
 $2
 $1
 $1
Three Months Ended March 31, 2015                    
Service cost $64
 $15
 $18
 $3
 $3
 $64
 $15
 $18
 $3
 $3
Interest cost 111
 26
 38
 5
 5
 111
 26
 38
 5
 5
Expected return on plan assets (181) (45) (63) (8) (8) (181) (45) (63) (8) (8)
Amortization:                    
Prior service costs 6
 2
 3
 
 
 6
 2
 3
 
 
Net (gain)/loss 54
 14
 19
 3
 3
 54
 14
 19
 3
 3
Net cost $54
 $12
 $15
 $3
 $3
 $54
 $12
 $15
 $3
 $3
Three Months Ended March 31, 2014          
Service cost $53
 $12
 $16
 $3
 $3
Interest cost 109
 26
 38
 5
 5
Expected return on plan assets (161) (42) (57) (7) (7)
Amortization:          
Prior service costs 6
 1
 3
 
 
Net (gain)/loss 28
 8
 10
 1
 1
Net cost $35
 $5
 $10
 $2
 $2

155147


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

Postretirement Benefits 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 (in millions) (in millions)
Three Months Ended March 31, 2016          
Service cost $5
 $1
 $2
 $
 $
Interest cost 18
 5
 8
 1
 1
Expected return on plan assets (14) (6) (6) 
 
Amortization:          
Prior service costs 2
 1
 
 
 
Net (gain)/loss 3
 
 2
 
 
Net cost $14
 $1
 $6
 $1
 $1
Three Months Ended March 31, 2015                    
Service cost $6
 $1
 $2
 $
 $
 $6
 $1
 $2
 $
 $
Interest cost 19
 5
 8
 1
 1
 19
 5
 8
 1
 1
Expected return on plan assets (15) (6) (6) 
 
 (15) (6) (6) 
 
Amortization:                    
Prior service costs 1
 1
 
 
 
 1
 1
 
 
 
Net (gain)/loss 5
 
 3
 
 
 5
 
 3
 
 
Net cost $16
 $1
 $7
 $1
 $1
 $16
 $1
 $7
 $1
 $1
Three Months Ended March 31, 2014          
Service cost $5
 $1
 $2
 $
 $
Interest cost 20
 5
 8
 1
 1
Expected return on plan assets (15) (6) (6) 
 
Amortization:          
Prior service costs 1
 1
 
 
 
Net (gain)/loss 1
 
 
 
 
Net cost $12
 $1
 $4
 $1
 $1

156148


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

(G)EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITSINCOME TAXES
Current and Deferred Income Taxes
Southern Power ITC Carryforwards
As of March 31, 2016, Southern Power had federal ITC carryforwards which are expected to result in $694 million of federal income tax benefits compared to $551 million as of December 31, 2015. The carryforwards as of March 31, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021.
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.equity, and federal income tax benefits from ITCs and PTCs.
Southern Company's effective tax rate was 34.3%30.8% for the three months ended March 31, 20152016 compared to 32.3%34.3% for the corresponding period in 2014.2015. The effective tax rate increasedecrease was primarily due to higher netincreased federal income tax benefits from ITCs and beneficial changes that impacted 2014 state income taxes.PTCs and lower pre-tax earnings in 2016.
Mississippi Power
Mississippi Power's effective tax rate was 10.0%(838.7)% for the three months ended March 31, 20152016 compared to (43.0)%10.0% for the corresponding period in 2014.2015. The increaseeffective tax rate decrease was primarily due to higher net income, partially offset by a decreasean increase in non-taxable AFUDC equitytax benefits related to the estimated probable losses on construction of the Kemper IGCC.
Southern Power
Southern Power's effective tax rate was 25.8%(84.0)% for the three months ended March 31, 20152016 compared to 8.5%25.8% for the corresponding period in 2014.2015. The increaseeffective tax rate decrease was primarily due to beneficial changes that impacted 2014 state income taxes, which was partially offset by increased federal income tax benefits from ITCs related to ITCssolar projects expected to be placed in the current year.service in 2016 and additional PTCs related to wind projects in 2016 compared to 2015.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
Changes during 2016 for unrecognized tax benefits were as follows:
 Mississippi Power Southern Power Southern Company
 (in millions)
Unrecognized tax benefits as of December 31, 2015$421
 $8
 $433
Tax positions from current periods
 5
 5
Balance as of March 31, 2016$421
 $13
 $438
The tax positions from current periods primarily relate to federal income tax benefits from ITCs.

149


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

The impact on the effective tax rate, if recognized, is as follows:
 As of March 31, 2016 As of December 31, 2015
 Mississippi Power Southern Power Southern Company Southern Company
 (in millions)
Tax positions impacting the effective tax rate$(2) $13
 $15
 $10
Tax positions not impacting the effective tax rate423
 
 423
 423
Balance of unrecognized tax benefits$421
 $13
 $438
 $433
The tax positions impacting the effective tax rate primarily relate to federal income tax benefits from ITCs. The tax positions not impacting the effective tax rate relate to deductions for Kemper IGCC-related research and experimental (R&E) expenditures. See "Section 174 Research and Experimental Deduction" below for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company reduced tax payments for 2014, and included in its 2013Company's consolidated federal income tax returnreturns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC. IGCC in its federal income tax calculations since 2013 and has filed amended federal income tax returns for 2008 through 2013 to also include such deductions.
The Kemper IGCC is based on first-of-a-kind technology, and Southern Company 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, Southern Company and Mississippi Power and Southern Company had related unrecognized tax benefits associated with these R&E deductions of approximately $211$423 million and associated interest of $3$12 million atas of March 31, 2015.
2016. The ultimate outcome of this matter cannot be determined at this time.
(H)DERIVATIVES
Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate 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

150


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

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.
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,

157


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

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 prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, 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(which are mainly used to hedge anticipated purchases and sales andsales) 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.
At March 31, 2015,2016, 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 241 2020 2017 235 2020 2017
Alabama Power 54 2018  60 2019 
Georgia Power 44 2017  65 2019 
Gulf Power 92 2020  74 2020 
Mississippi Power 49 2018  28 2018 
Southern Power 2  2017 8 2016 2017

151


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

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 4 million mmBtu for Southern Company 3 million mmBtu forand Georgia Power, and 1 million mmBtu for Southern Power.

158


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

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 20162017 are immaterial for all registrants.
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. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

152


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

At March 31, 2015,2016, the following interest rate derivatives were outstanding:
 
Notional
Amount
 
Interest
Rate
Received
 
Weighted
Average
Interest
Rate Paid
 
Hedge
Maturity
Date
 
Fair Value
Gain (Loss) at March 31,
2015
 
Notional
Amount
 
Interest
Rate
Received
 
Weighted
Average
Interest
Rate Paid
 
Hedge
Maturity
Date
 Fair Value
Gain (Loss) at March 31, 2016
 (in millions)       (in millions) (in millions)       (in millions)
Cash Flow Hedges of Forecasted DebtCash Flow Hedges of Forecasted Debt  Cash Flow Hedges of Forecasted Debt  
Alabama Power $200
 3-month
LIBOR 
 2.93% October 2025 $(14)
Georgia Power 350
 3-month
LIBOR 
 2.57% May 2025 (17)
Georgia Power 350
 3-month
LIBOR 
 2.57% November 2025 (13)
Southern Company $1,500
 3-month
LIBOR 
 2.14% November 2026 $(55)
Southern Company 1,200
 3-month
LIBOR 
 2.60% November 2046 (127)
Gulf Power 80
 3-month
LIBOR 
 2.32% December 2026 (4)
Cash Flow Hedges of Existing DebtCash Flow Hedges of Existing Debt  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 
 200
 3-month
LIBOR + 0.40%
 1.01% August 2016 
Fair Value Hedges on Existing DebtFair Value Hedges on Existing Debt  Fair Value Hedges on Existing Debt  
Southern Company 250
 1.30% 3-month
LIBOR + 0.17%
 August 2017 1
 250
 1.30% 3-month
LIBOR + 0.17%
 August 2017 1
Southern Company 300
 2.75% 3-month
LIBOR + 0.92%
 June 2020 10
Georgia Power 250
 5.40% 3-month
LIBOR + 4.02%
 June 2018 2
 250
 5.40% 3-month
LIBOR + 4.02%
 June 2018 3
Georgia Power 200
 4.25% 3-month
LIBOR + 2.46%
 December 2019 4
 200
 4.25% 3-month
LIBOR + 2.46%
 December 2019 6
Georgia Power 500
 1.95% 3-month
LIBOR + 0.76%
 December 2018 5
Derivatives not Designated as HedgesDerivatives not Designated as Hedges  
Southern Power 65
(a,d) 
3-month
LIBOR 
 2.50% October 2016
(e) 

Southern Power 47
(b,d) 
3-month
LIBOR 
 2.21% October 2016
(e) 

Southern Power 65
(c,d) 
3-month
LIBOR 
 2.21% November 2016
(f) 

Total $2,050
 $(37) $4,657
 $(161)
(a)Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
(b)Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
(c)Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
(d)Amortizing notional amount.
(e)Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.
(f)Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap.

153


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

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 20162017 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2037.2046.

159


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

Derivative Financial Statement Presentation and Amounts
At March 31, 2016, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
Asset Derivatives at March 31, 2016
  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 $2
 $1
 $1
 $
 $
  
Other deferred charges and assets 5
 2
 3
 
 
  
Total derivatives designated as hedging instruments for regulatory purposes $7
 $3
 $4
 $
 $
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Energy-related derivatives:            
Other current assets(*)
 $4
 $
 $
 $
 $
 $4
Interest rate derivatives:            
Other current assets 18
 
 7
 
 
 
Other deferred charges and assets 14
 
 7
 
 
 
Total derivatives designated as hedging instruments in cash flow and fair value hedges $36
 $
 $14
 $
 $
 $4
Derivatives not designated as hedging instruments            
Energy-related derivatives:            
Other current assets(*)
 $1
 $
 $
 $
 $
 $1
Interest rate derivatives:            
Other current assets(*)
 1
 
 
 
 
 1
Total derivatives not designated as hedging instruments $2
 $
 $
 $
 $
 $2
Total asset derivatives $45
 $3
 $18
 $
 $
 $6
(*)Southern Power includes current assets related to derivatives in "Assets from risk management activities."

154


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

Liability Derivatives at March 31, 2016
  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(*)
 $124
 $37
 $9
 $49
 $29
  
Other deferred credits and liabilities 74
 12
 2
 45
 15
  
Total derivatives designated as hedging instruments for regulatory purposes $198
 $49
 $11
 $94
 $44
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Energy-related derivatives:            
Liabilities from risk management activities(*)
 $2
 $
 $
 $
 $
 $2
Interest rate derivatives:            
Liabilities from risk management activities(*)
 193
 
 
 5
 
 
Total derivatives designated as hedging instruments in cash flow and fair value hedges $195
 $
 $
 $5
 $
 $2
Derivatives not designated as hedging instruments 

 

 

 

 

 

Energy-related derivatives:            
Liabilities from risk management activities(*)
 $1
 $
 $
 $
 $
 $1
Total liability derivatives $394
 $49
 $11
 $99
 $44
 $3
(*)Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

155


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

At December 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
Asset Derivatives at March 31, 2015
Asset Derivatives at December 31, 2015Asset Derivatives at December 31, 2015
 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 $6
 $1
 $5
 $
 $
   $3
 $1
 $2
 $
 $
 N/A
Other deferred charges and assets 1
 
 1
 
 
  
Total derivatives designated as hedging instruments for regulatory purposes $7
 $1
 $6
 $
 $
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges                        
Energy-related derivatives:            
Other current assets(*)
 $3
 $
 $
 $
 $
 $3
Interest rate derivatives:                        
Other current assets $7
 $
 $5
 $
 $
 $
 19
 
 5
 1
 
 
Other deferred charges and assets 1
 
 1
 
 
 
Total derivatives designated as hedging instruments in cash flow and fair value hedges $8
 $
 $6
 $
 $
 $
 $22
 $
 $5
 $1
 $
 $3
Derivatives not designated as hedging instruments            
Energy-related derivatives:            
Other current assets(*)
 $1
 $
 $
 $
 $
 $1
Interest rate derivatives:            
Other current assets(*)
 3
 
 
 
 
 3
Total derivatives not designated as hedging instruments $4
 $
 $
 $
 $
 $4
Total asset derivatives $15
 $1
 $12
 $
 $
 $
 $29
 $1
 $7
 $1
 $
 $7
(*)Southern Power includes current assets related to derivatives in "Assets from risk management activities."

Liability Derivatives at March 31, 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(*)
 $117
 $33
 $21
 $37
 $26
  
Other deferred credits and liabilities 108
 26
 3
 53
 26
  
Total derivatives designated as hedging instruments for regulatory purposes $225
 $59
 $24
 $90
 $52
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Interest rate derivatives:            
Other current liabilities(*)
 $45
 $14
 $31
 $
 $
 $
Other deferred credits and liabilities 1
 
 
 
 
 
Total derivatives designed as hedging instruments in cash flow and fair value hedges $46
 $14
 $31
 $
 $
 $
Total liability derivatives $271
 $73
 $55
 $90
 $52
 $
(*) Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

160156


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

At December 31, 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, 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 $7
 $1
 $6
 $
 $
  
Other deferred charges and assets 
 
 1
 
 
  
Total derivatives designated as hedging instruments for regulatory purposes $7
 $1
 $7
 $
 $
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Interest rate derivatives:            
Other current assets $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 current assets(*)
 $6
 $
 $
 $
 $
 $5
Total asset derivatives $21
 $1
 $13
 $
 $
 $5
(*) Southern Power includes current assets related to derivatives not designated as hedging instruments in "Assets from risk management activities."

161


NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Liability Derivatives at December 31, 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:            
Liabilities from risk management activities(*)
 $130
 $40
 $12
 $49
 $29
  
Other deferred credits and liabilities 87
 15
 3
 51
 18
 

Total derivatives designated as hedging instruments for regulatory purposes $217
 $55
 $15
 $100
 $47
 N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges            
Energy-related derivatives:            
Liabilities from risk management activities(*)
 $2
 $
 $
 $
 $
 $2
Interest rate derivatives:            
Liabilities from risk management activities 23
 15
 
 
 
 
Other deferred credits and liabilities 7
 
 6
 
 
 
Total derivatives designated as hedging instruments in cash flow and fair value hedges $32
 $15
 $6
 $
 $
 $2
Derivatives not designated as hedging instruments            
Energy-related derivatives:            
Liabilities from risk management activities(*)
 $1
 $
 $
 $
 $
 $1
Total liability derivatives $250
 $70
 $21
 $100
 $47
 $3

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
(*) Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."
(*)Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."
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 March 31, 20152016 and December 31, 20142015 are presented in the following tables.

162157


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

Derivative Contracts at March 31, 2015
Derivative Contracts at March 31, 2016Derivative Contracts at March 31, 2016
 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)
 $7
 $1
 $6
 $
 $
 $
 $12
 $3
 $4
 $
 $
 $5
Gross amounts not offset in the Balance Sheet (b)
 (6) (1) (6) 
 
 
 (10) (3) (3) 
 
 (2)
Net energy-related derivative assets $1
 $
 $
 $
 $
 $
 $2
 $
 $1
 $
 $
 $3
Interest rate derivatives:                        
Interest rate derivatives presented in the Balance Sheet (a)
 $8
 $
 $6
 $
 $
 $
 $33
 $
 $14
 $
 $
 $1
Gross amounts not offset in the Balance Sheet (b)
 (2) 
 (2) 
 
 
 (21) 
 
 
 
 
Net interest rate derivative assets $6
 $
 $4
 $
 $
 $
 $12
 $
 $14
 $
 $
 $1
Liabilities                        
Energy-related derivatives:                        
Energy-related derivatives presented in the Balance Sheet (a)
 $225
 $59
 $24
 $90
 $52
 $
 $201
 $49
 $11
 $94
 $44
 $3
Gross amounts not offset in the Balance Sheet (b)
 (6) (1) (6) 
 
 
 (10) (3) (3) 
 
 (2)
Net energy-related derivative liabilities $219
 $58
 $18
 $90
 $52
 $
 $191
 $46
 $8
 $94
 $44
 $1
Interest rate derivatives:                        
Interest rate derivatives presented in the Balance Sheet (a)
 $46
 $14
 $31
 $
 $
 $
 $193
 $
 $
 $5
 $
 $
Gross amounts not offset in the Balance Sheet (b)
 (2) 
 (2) 
 
 
 (21) 
 
 
 
 
Net interest rate derivative liabilities $44
 $14
 $29
 $
 $
 $
 $172
 $
 $
 $5
 $
 $
(a)None of the registrants offsets 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.

(a) None of the registrants offsets 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.

163158


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

Derivative Contracts at December 31, 2014
Derivative Contracts at December 31, 2015Derivative Contracts at December 31, 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)
 $13
 $1
 $7
 $
 $
 $5
 $7
 $1
 $2
 $
 $
 $4
Gross amounts not offset in the Balance Sheet (b)
 (9) 
 (7) 
 
 
 (6) (1) (2) 
 
 (1)
Net energy-related derivative assets $4
 $1
 $
 $
 $
 $5
 $1
 $
 $
 $
 $
 $3
Interest rate derivatives:                        
Interest rate derivatives presented in the Balance Sheet (a)
 $8
 $
 $6
 $
 $
 $
 $22
 $
 $5
 $1
 $
 $4
Gross amounts not offset in the Balance Sheet (b)
 (8) 
 (6) 
 
 
 (9) 
 (4) 
 
 
Net interest rate derivative assets $
 $
 $
 $
 $
 $
 $13
 $
 $1
 $1
 $
 $4
Liabilities                        
Energy-related derivatives:                        
Energy-related derivatives presented in the Balance Sheet (a)
 $201
 $53
 $27
 $72
 $45
 $4
 $220
 $55
 $15
 $100
 $47
 $3
Gross amounts not offset in the Balance Sheet (b)
 (9) 
 (7) 
 
 
 (6) (1) (2) 
 
 (1)
Net energy-related derivative liabilities $192
 $53
 $20
 $72
 $45
 $4
 $214
 $54
 $13
 $100
 $47
 $2
Interest rate derivatives:                        
Interest rate derivatives presented in the Balance Sheet (a)
 $24
 $8
 $14
 $
 $
 $
 $30
 $15
 $6
 $
 $
 $
Gross amounts not offset in the Balance Sheet (b)
 (8) 
 (6) 
 
 
 (9) 
 (4) 
 
 
Net interest rate derivative liabilities $16
 $8
 $8
 $
 $
 $
 $21
 $15
 $2
 $
 $
 $
(a)None of the registrants offsets 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.

(a) None of the registrants offsets 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.

164159


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

At March 31, 20152016 and December 31, 2014,2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at March 31, 2015
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at March 31, 2016Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at March 31, 2016
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 $(117) $(33) $(21) $(37) $(26) $(124) $(37) $(9) $(49) $(29)
Other regulatory assets, deferred (108) (26) (3) (53) (26) (74) (12) (2) (45) (15)
Other regulatory liabilities, current (a)
 6
 1
 5
 
 
 2
 1
 1
 
 
Other regulatory liabilities, deferred (b)
 1
 
 1
 
 
 5
 2
 3
 
 
Total energy-related derivative gains (losses) $(218) $(58) $(18) $(90) $(52) $(191) $(46) $(7) $(94) $(44)
(a) Southern Company 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.
(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
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2015Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 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 $(118) $(32) $(23) $(37) $(26) $(130) $(40) $(12) $(49) $(29)
Other regulatory assets, deferred (79) (21) (4) (35) (19) (87) (15) (3) (51) (18)
Other regulatory liabilities, current (a)
 7
 1
 6
 
 
Other regulatory liabilities, deferred (b)
 
 
 1
 
 
Other regulatory liabilities, current(*)
 3
 1
 2
 
 
Total energy-related derivative gains (losses) $(190) $(52) $(20) $(72) $(45) $(214) $(54) $(13) $(100) $(47)
(a) Southern Company 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.
(*)Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.
For the three months ended March 31, 20152016 and 2014,2015, 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)
 
Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion)
 
Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion)
 Statements of Income Location Amount  Statements of Income Location Amount
 2015 2014 2015 2014 2016 2015 2016 2015
 (in millions) (in millions) (in millions) (in millions)
Southern Company                
Interest rate derivatives $(29) $
 Interest expense, net of amounts capitalized $(2) $(2) $(190) $(29) Interest expense, net of amounts capitalized $(3) $(2)
Alabama Power                
Interest rate derivatives $(6) $
 Interest expense, net of amounts capitalized $(1) $(1) $(4) $(6) Interest expense, net of amounts capitalized $(1) $(1)
Georgia Power                
Interest rate derivatives $(23) $
 Interest expense, net of amounts capitalized $(1) $(1) $
 $(23) Interest expense, net of amounts capitalized $(1) $(1)
Gulf Power        
Interest rate derivatives $(5) $
 Interest expense, net of amounts capitalized $
 $
For the three months ended March 31, 20152016 and 2014,2015, 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.

165160


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

For the three months ended March 31, 20152016 and 2014,2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants. Furthermore,as follows:
Derivatives in Fair Value Hedging Relationships 
   Gain (Loss)
Derivative Category Statements of Income Location2016 2015
   (in millions)
Southern Company     
Interest rate derivatives: Interest expense, net of amounts capitalized$20
 $7
Georgia Power     
Interest rate derivatives: Interest expense, net of amounts capitalized$14
 $6
For the three months ended March 31, 2016 and 2015, 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 months ended March 31, 20152016 and 2014,2015, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for 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 March 31, 2015,2016, the registrants' collateral posted with their derivative counterparties was immaterial.
At March 31, 2015,2016, the fair value of derivative liabilities with contingent features was $59$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 $59$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 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
During
Southern Company
Proposed Merger with AGL Resources
On August 23, 2015, Southern Power Company acquired or contractedentered into the Merger Agreement to acquire AGL Resources. Under the following projects in accordance with its overall growth strategy.
Decatur County Solar Projects
On February 19, 2015, Southern Power Company acquired allterms of the outstanding membership interestsMerger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. as part of Southern Power's plans to build two solar photovoltaic facilities: the Decatur Parkway Solar Project and the Decatur County Solar Project. These two projects, approximately 80 MWs and 19 MWs, respectively, will be constructed on separate sites in Decatur County, Georgia. Construction of the Decatur Parkway Solar Project commenced in February 2015, while construction of the Decatur County Solar Project is expected to commence in June 2015. Both projects are expected to begin commercial operation in late 2015, and the entire output of each project is contracted to Georgia Power. The Decatur Parkway Solar Project is contracted under a 25-year PPA and the Decatur County Solar Project is contracted under a separate 20-year PPA. Construction costs incurred through March 31, 2015 were $32 million.
The total estimated cost of the facilities is expected to be between $200 million and $220 million, which includes the acquisition price for all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and

166161


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

Decatur County Solar Project, LLC from TradeWindspecified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned, direct subsidiary of Southern Company.
The Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of AGL Resources' assets and liabilities will be recorded as goodwill. Southern Company expects total cash of $8.2 billion to be required to fund the purchase price of approximately $8.0 billion to acquire AGL Resources common stock, options to purchase shares of AGL Resources common stock, and restricted stock units payable in shares of AGL Resources common stock and to fund acquisition-related expenses and financing costs of approximately $200 million. Southern Company will also assume AGL Resources' outstanding indebtedness.
Through May 5, 2016, the Maryland PSC, the Georgia PSC, the California Public Utilities Commission, and the Virginia State Corporation Commission have approved the Merger. On April 15, 2016, Southern Company, AGL Resources, and Northern Illinois Gas Company (collectively, the Joint Applicants) and the Retail Energy Supply Association filed a settlement agreement with the Illinois Commerce Commission. On April 28, 2016, the Joint Applicants, the Illinois Attorney General's Office, and the Citizens Utility Board filed a settlement agreement with the Illinois Commerce Commission. Collectively, these agreements resolve all remaining contested issues for Illinois Commerce Commission approval of the Merger. On May 5, 2016, Southern Company, AGL Resources, Merger Sub, Pivotal Utility Holdings, Inc. d/b/a Elizabethtown Gas, the Division of Rate Counsel, the Staff of the New Jersey Board of Public Utilities, and New Jersey Large Energy Users Coalition entered into a comprehensive settlement agreement relating to the New Jersey Board of Public Utilities review of the Merger. Additionally, the Federal Communications Commission (FCC) has approved the transfer of control over the FCC licenses of certain AGL Resources subsidiaries. Consummation of the Merger remains subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the approval of the Illinois Commerce Commission and the New Jersey Board of Public Utilities and other approvals required under applicable state laws, (ii) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement.
During the first quarter 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the proposed Merger of approximately $20 million, of which $6 million is included in operating expenses and $14 million is included in other income and (expense).
The ultimate outcome of these matters cannot be determined at this time. See Note 12 to the financial statements of Southern Company under "Southern Company – Proposed Merger with AGL Resources" in Item 8 of the Form 10-K for additional information.
Kay County Wind FacilityMerger Financing
Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company expects to issue the debt to fund the cash consideration for the Merger in several tranches including long-dated maturities. The amount of debt issued at each maturity will depend on prevailing market conditions at the time of the offering and other factors. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information regarding the Bridge Agreement.
Proposed Acquisition of PowerSecure
On February 24, 2015,2016, 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). 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.
In March 2015, Kay Wind obtained the necessary financing for the construction of the facility, and Southern Power Company's acquisition is expected to close in the fourth quarter 2015. The purchase price is expected to be approximately $492 million, with potential purchase price adjustments based on performance testing, and is included in Southern Power's capital program estimates for 2015. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.
Butler Solar Project
On March 12, 2015, Southern Power Company entered into a purchase agreement with CERSM, LLCan Agreement and Community Energy, Inc.Plan of Merger to acquire all ofPowerSecure. Under the outstanding membership interests of Butler Solar LLC as part of Southern Power's plans to build an approximately 100-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in July 2015, with commercial operation expected to begin in December 2016. The entire output of the project is contracted to Georgia Power under a 30-year PPA.
Southern Power Company's acquisition of Butler Solar LLC is expected to close later in May 2015 and the total estimated cost of the facility is expected to be between $220 million and $230 million, which includes the acquisition price for all of the outstanding membership interests of Butler Solar LLC from CERSM, LLC and Community Energy, Inc. The completion of the acquisition is subject to customary conditions to closing. The ultimate outcometerms of this matter cannotmerger agreement, the stockholders of PowerSecure will be determined at this time.
Subsequent Events
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 $34 million. SRP and the class B member are entitled to 51% and 49%, respectively,receive $18.75 in cash for each share of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially allcommon stock in a transaction with a total purchase price of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 20-MW Lost Hills and the approximately 12-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 and then to Pacific Gas and Electric Company, that together extend approximately 29 years.$431 million.
Pawpaw Solar Project
On April 22, 2015, Southern Power Company entered into a purchase agreement with Longview Solar, LLC to acquire all of the outstanding membership interests of LS – Pawpaw, LLC as part of Southern Power Company's plans to build an approximately 30-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in June 2015, with commercial operation expected to begin in December 2015. The entire output of the project is contracted to Georgia Power under a 30-year PPA.

167162


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

Following this transaction, PowerSecure will become a wholly-owned subsidiary of Southern Power Company's acquisition of LS – Pawpaw, LLCCompany. This transaction is expected to close later in May 2015 and the total estimated cost of the facility is expected to be between $65 million and $75 million, which includes the acquisition price for all of the outstanding membership interests of LS – Pawpaw, LLC from Longview Solar, LLC. The completion of the acquisition is subject to customary conditions to closing.2016. The ultimate outcome of this matter cannot be determined at this time.
Southern Power
See Note 2 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information. During the first quarter 2016, the fair values of the assets and liabilities acquired of Lost Hills, Blackwell, North Star, Solar Facilityand Morelos were finalized and there were no changes.
On April 30, 2015,During 2016, in accordance with its overall growth strategy, Southern Power Company,acquired or contracted to acquire through its subsidiary SRP, acquired 100%wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., the projects set forth in the following table. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.
Project FacilitySeller; Acquisition DateApprox. Nameplate CapacityLocationSouthern Power Percentage Ownership Expected/Actual CODPPA
Counterparties for Plant Output
PPA Contract PeriodApprox. Purchase Price 
  (MW)      (in millions) 
SOLAR
CalipatriaSolar Frontier Americas Holding, LLC
February 11, 2016
20Imperial County, CA90% February 11, 2016San Diego Gas & Electric Company20 years$51
(a)
East PecosFirst Solar, Inc. March 4, 2016120Pecos County, TX100% Fourth quarter 2016Austin Energy15 years$41
(b)
WIND
Grant WindApex Clean Energy Holdings, LLC
April 7, 2016
151Grant County, OK100% April 8, 2016Western Farmers, East Texas, and Northeast Texas Electric Cooperative20 years$258
(c)
PassadumkeagQuantam Wind Acquisition I, LLC40Penobscot County, ME100% Second quarter 2016Western Massachusetts Electric Company15 years$127
(d)
(a)
Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest and contingent consideration of $6 million, is approximately $57 million. As of March 31, 2016, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $58 million as property, plant, and equipment, $1 million as a transmission interconnection prepaid, and $2 million as payables; however, the allocation of the purchase price to individual assets has not been finalized.
(b)
East Pecos - The total purchase price is approximately $41 million. As of March 31, 2016, the fair values of the assets acquired through the business combination were recorded as $41 million to CWIP; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $200 million to $220 million. The ultimate outcome of this matter cannot be determined at this time.
(c)
Grant Wind - Subsequent to March 31, 2016, Southern Power acquired all of the outstanding membership interests of Grant Wind, LLC. The purchase price includes approximately $23 million of contingent consideration which may be adjusted based on performance testing and production over the first 10 years of operation.
(d)
Passadumkeag - On March 11, 2016, Southern Power entered into an agreement to acquire all of the outstanding membership interests of Quantum Wind Acquisition I, LLC, which is expected to close in the second quarter 2016. The ultimate outcome of this matter cannot be determined at this time.
Construction Projects
During the first quarter 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the class A membership interests of NSButler Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $208 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $99 million. SRPFarm and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star.Pawpaw solar facilities. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star is constructing and owns the approximately 60-MW North Star solar facility in Fresno County, California, which is expected to begin commercial operation in June 2015. The entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company. The ultimate outcome of this matter cannot be determined at this time.

168163


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

continued construction of the projects set forth in the table below. Through March 31, 2016, total costs of construction incurred for the projects below were $2.2 billion, of which $1.5 billion remains in CWIP. The ultimate outcome of these matters cannot be determined at this time.
Solar FacilitySellerApprox. Nameplate CapacityLocationExpected/Actual CODPPA Counterparties
for Plant Output
PPA
Contract Period
Estimated Construction Costs 
  (MW)    (in millions) 
ButlerCERSM, LLC and Community Energy, Inc.103Taylor County, GAFourth quarter 2016
Georgia Power(a)
30 years$220
-230(b)
Desert StatelineFirst Solar, Inc.
299(c)
San Bernardino County, CAThrough third quarter 2016Southern California Edison Company (SCE)20 years$1,200
-1,300(d)
Garland and
Garland A
Recurrent Energy, LLC205Kern County, CA
Fourth quarter 2016
  Third quarter 2016
SCE15 years and
20 years
$532
-552(e,f)
RoserockRecurrent Energy, LLC160Pecos County, TXFourth quarter 2016Austin Energy20 years$333
-353(e,f)
SandhillsN/A146Taylor County, GAFourth quarter 2016Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations25 years$260
-280 
TranquillityRecurrent Energy, LLC205Fresno County, CAThird quarter 2016Shell Energy North America (US), LP/SCE18 years$473
-493(f,g)
(a)
Butler - Affiliate PPA subject to FERC approval.
(b)
Butler - Total estimated construction costs include the acquisition price of all outstanding membership interests of the related entity.
(c) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 76 MWs were placed in service in the first quarter 2016. Subsequent to March 31, 2016, 38 MWs were placed in service. The remaining 75 MWs are expected to be placed in service by the end of the third quarter 2016.
(d)
Desert Stateline - On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.
(e)Total estimated construction costs include the acquisition price allocated to CWIP. During the first quarter 2016, the allocation of the purchase price to individual assets was finalized with no changes.
(f)Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project.
(g) Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

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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 $114$97 million and $72$114 million for the three months ended March 31, 20152016 and March 31, 2014,2015, 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 months ended March 31, 20152016 and 20142015 was as follows:
 Electric Utilities      
 
Traditional
Operating
Companies
 
Southern
Power
 Eliminations Total 
All
Other
 Eliminations Consolidated
 (in millions)
Three Months Ended March 31, 2015:             
Operating revenues$3,948
 $348
 $(124) $4,172
 $40
 $(29) $4,183
Segment net income (loss)(a)(b)
477
 33
 
 510
 3
 (5) 508
Total assets at March 31, 2015$65,530
 $5,564
 $(273) $70,821
 $1,091
 $(302) $71,610
Three Months Ended March 31, 2014:             
Operating revenues$4,378
 $351
 $(102) $4,627
 $41
 $(24) $4,644
Segment net income (loss)(a)(b)
318
 33
 
 351
 
 
 351
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 March 31, 2015 and March 31, 2014 includes a $9 million pre-tax charge ($6 million after tax) and a $380 million pre-tax charge ($235 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.
 Electric Utilities      
 
Traditional
Operating
Companies
 
Southern
Power
 Eliminations Total 
All
Other
 Eliminations Consolidated
 (in millions)
Three Months Ended March 31, 2016:             
Operating revenues$3,742
 $315
 $(103) $3,954
 $47
 $(36) $3,965
Segment net income (loss)(a)(b)
464
 50
 
 514
 (26) (3) 485
Total assets at March 31, 2016$69,240
 $8,999
 $(396) $77,843
 $2,070
 $(1,178) $78,735
Three Months Ended March 31, 2015:             
Operating revenues$3,948
 $348
 $(124) $4,172
 $40
 $(29) $4,183
Segment net income (loss)(a)(b)
477
 33
 
 510
 3
 (5) 508
Total assets at December 31, 2015$69,052
 $8,905
 $(397) $77,560
 $1,819
 $(1,061) $78,318
(a)Attributable to Southern Company.
(b)Segment net income (loss) for the traditional operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $53 million ($33 million after tax) and $9 million ($6 million after tax) for the three months ended March 31, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.
Products and Services
 Electric Utilities' Revenues Electric Utilities' Revenues
Period Retail Wholesale Other Total Retail Wholesale Other Total
 (in millions) (in millions)
Three Months Ended March 31, 2016 $3,377
 $396
 $181
 $3,954
Three Months Ended March 31, 2015 $3,542
 $467
 $163
 $4,172
 3,542
 467
 163
 4,172
Three Months Ended March 31, 2014 3,858
 604
 165
 4,627

169165


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 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 (*)
January 1 – January 31 N/A
 N/A
 N/A
 N/A
February 1 – February 28 N/A
 N/A
 N/A
 N/A
March 1 – March 31 2,599,366
 $44.227
 2,599,366
 N/A
Total 2,599,366
 $44.227
 2,599,366
 17,400,634
(*)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.

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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.
 (4) Instruments Describing Rights of Security Holders, Including Indentures
    
 AlabamaGeorgia Power
    
 (b)(c)1-Fifty-ThirdFifty-fourth Supplemental Indenture to Senior Note Indenture, dated as of March 11, 2015,8, 2016, providing for the issuance of the Series 2015A 3.750%2016A 3.250% Senior Notes due MarchApril 1, 2045.2026. (Designated in Form 8-K dated March 5, 2015,2, 2016, File No. 1-3164,1-6468, as Exhibit 4.6.4.2(a).)
    
 (b)(c)2-Fifty-FourthFifty-fifth Supplemental Indenture to Senior Note Indenture, dated as of April 14, 2015,March 8, 2016, providing for the issuance of the Series 2015B 2.800%2016B 2.400% Senior Notes due April 1, 2025.2021. (Designated in Form 8-K dated April 9, 2015,March 2, 2016, File No. 1-3164,1-6468, as Exhibit 4.6(b)4.2(b).)
    
 (10) Material Contracts
*
(c)3Southern Company-Amendment No. 2 to Loan Guarantee Agreement between Georgia Power and the DOE, dated as of March 9, 2016.
   
#(a)1-Retention Award Agreement between Southern Nuclear and Stephen E. Kuczynski effective as of October 20, 2014.
 
#(a)2-Base Salaries of Named Executive Officers.
Georgia Power
#(c)1-Base Salaries of Named Executive Officers.
#(c)2-First Amendment to the Deferred Compensation Plan for Outside Directors of Georgia Power Company, Amended and Restated Effective January 1, 2008.
#(c)3-Deferred Compensation Agreement between Southern Company, Southern Company Services, Inc., and John L. Pemberton, effective October 8, 2008.
#(c)4-Summary of Non-Employee Director Compensation Arrangements.
 Mississippi Power
    
#*(e)1-Base SalariesTerm Loan Agreement among Mississippi Power and the lenders identified therein, dated as of Named Executive Officers.March 8, 2016.
(10) Material Contracts
    
Mississippi Power
#*(e)1-Letter Agreement between Mississippi Power and Emile J. Troxclair III dated December 11, 2014.
#*(e)2-Performance Award Agreement between Southern Company Services, Inc. and Emile J. Troxclair III effective as of January 3, 2015.
 (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, 2014,2015, File No. 1-3526 as Exhibit 24(a).)
    
 Alabama Power
    
 (b)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014,2015, File No. 1-3164 as Exhibit 24(b).)
    
 Georgia Power
    
 (c)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014,2015, File No. 1-6468 as Exhibit 24(c).)
    

171166


 Gulf Power
    
 (d)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014,2015, File No. 001-31737 as Exhibit 24(d).)
    
 Mississippi Power
    
 (e)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014,2015, File No. 001-11229 as Exhibit 24(e).1.)
    
(e)2-Power of Attorney for Anthony L. Wilson. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-11229 as Exhibit 24(e)2.)
 Southern Power
    
 (f)1-Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014,2015, File No. 333-98553 as Exhibit 24(f).1.)
    
(f)2-Power of Attorney for Joseph A. Miller. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 333-98553 as Exhibit 24(f)2.)
 (31) Section 302 Certifications
    
 Southern Company
    
 *(a)1-Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(a)2-Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Alabama Power
    
 *(b)1-Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(b)2-Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Georgia Power
    
 *(c)1-Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(c)2-Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Gulf Power
    
 *(d)1-Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(d)2-Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 Mississippi Power
    
 *(e)1-Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(e)2-Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    

167


 Southern Power
    
 *(f)1-Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
    
 *(f)2-Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

172


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

173168


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: May 7, 20155, 2016

174169


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: May 7, 20155, 2016

175170


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, Treasurer, and TreasurerCorporate Secretary
  (Principal Financial Officer)
    
By /s/Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: May 7, 20155, 2016

176171


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.
  Chairman, 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: May 7, 20155, 2016

177172


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.Anthony L. Wilson
  Chairman, President and Chief Executive Officer
  (Principal Executive Officer)
    
By Moses H. Feagin
  Vice President, Treasurer, and Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: May 7, 20155, 2016

178173


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 IVJoseph A. Miller
  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: May 7, 20155, 2016

179174