UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September~~June 30, ~~2014~~2015

¨ 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 18^th 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 ~~September~~June 30, ~~2014~~2015
The Southern Company	Par Value $5 Per Share	~~899,812,716~~908,424,808
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
Gulf Power Company	Without Par Value	~~5,442,717~~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.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

~~September~~June 30, ~~2014~~2015



		Page Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		7

	PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	The Southern Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	10
	Condensed Consolidated Statements of Comprehensive Income	11
	Condensed Consolidated Statements of Cash Flows	12
	Condensed Consolidated Balance Sheets	13
	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
	Alabama Power Company
	Condensed Statements of Income	3940
	Condensed Statements of Comprehensive Income	3940
	Condensed Statements of Cash Flows	4041
	Condensed Balance Sheets	4142
	Management's Discussion and Analysis of Financial Condition and Results of Operations	4344
	Georgia Power Company
	Condensed Statements of Income	5760
	Condensed Statements of Comprehensive Income	5760
	Condensed Statements of Cash Flows	5861
	Condensed Balance Sheets	5962
	Management's Discussion and Analysis of Financial Condition and Results of Operations	6164
	Gulf Power Company
	Condensed Statements of Income	7982
	Condensed Statements of Comprehensive Income	7982
	Condensed Statements of Cash Flows	8083
	Condensed Balance Sheets	8184
	Management's Discussion and Analysis of Financial Condition and Results of Operations	8386
	Mississippi Power Company
	Condensed Statements of Operations	98102
	Condensed Statements of Comprehensive Income (Loss)	98102
	Condensed Statements of Cash Flows	99103
	Condensed Balance Sheets	~~100~~104
	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~102~~106
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	~~129~~134
	Condensed Consolidated Statements of Comprehensive Income	~~129~~134
	Condensed Consolidated Statements of Cash Flows	~~130~~135
	Condensed Consolidated Balance Sheets	~~131~~136
	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~133~~138
	Notes to the Condensed Financial Statements	~~144~~149
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3738
Item 4.	Controls and Procedures	3738

INDEX TO QUARTERLY REPORT ON FORM 10-Q

~~September~~June 30, ~~2014~~2015



		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	~~189~~195
Item 1A.	Risk Factors	~~189~~195
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~Inapplicable~~ 195
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	~~189~~196
	Signatures	~~192~~200

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DEFINITIONS



Term	Meaning

2012 MPSC CPCN Order	A 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 ARP	Alternative Rate Plan approved by the Georgia PSC for Georgia Power for the years 2014 through 2016
AFUDC	Allowance for ~~Funds Used During Construction~~funds used during construction
Alabama Power	Alabama Power Company
ASC	Accounting Standards Codification
Baseload Act	State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
~~Chancery Court~~CCR	~~Chancery Court of Harrison County, Mississippi~~Coal combustion residuals
Clean Air Act	Clean Air Act Amendments of 1990
Contractor	Westinghouse 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
CPCN	Certificate of ~~Public Convenience~~public convenience and ~~Necessity~~necessity
CWIP	Construction work in progress
DOE	U.S. Department of Energy
ECO Plan	Mississippi Power's Environmental Compliance Overview Plan
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
Fitch	Fitch Ratings, Inc.
Form 10-K	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, ~~2013~~2014
GAAP	Generally accepted accounting principles
Georgia Power	Georgia Power Company
~~GHG~~	~~Greenhouse gas~~
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany ~~Interchange Contract~~interchange contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
~~ITCs~~ITC	Investment tax ~~credits~~credit
Kemper IGCC	IGCC facility under construction in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
MATS rule	Mercury and Air Toxics Standards rule
Mirror CWIP	A regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal ~~unit~~units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
~~NCCR~~	~~Nuclear Construction Cost Recovery~~
~~NRC~~	~~U.S. Nuclear Regulatory Commission~~
~~OCI~~	~~Other comprehensive income~~

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DEFINITIONS

(continued)



Term	Meaning

NCCR	Georgia Power's Nuclear Construction Cost Recovery
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
PEP	Mississippi Power's Performance Evaluation Plan
Plant Vogtle Units 3 and 4	Two new nuclear generating units under construction at Plant Vogtle
power pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power Company are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreement
PSC	Public Service Commission
Rate CNP	Alabama Power's Rate Certificated New Plant
Rate CNP Compliance	Alabama Power's Rate Certificated New Plant Compliance
Rate CNP Environmental	Alabama Power's Rate Certificated New Plant Environmental
Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company
ROE	Return on equity
S&P	Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
scrubber	Flue gas desulfurization system
SEC	U.S. Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association
Southern Company	The Southern Company
Southern Company system	Southern 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 Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
~~S&P~~	~~Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.~~
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Vogtle Owners	Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Westinghouse	Westinghouse Electric Company LLC
~~wholesale revenues~~	~~revenues generated from sales for resale~~

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~~CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION~~

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, the strategic goals for the wholesale business, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the American Taxpayer Relief Act of 2012, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other capital expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•

the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, CO₂, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

current and future litigation, regulatory investigations, proceedings, or inquiries, including pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS and state tax audits;

~~the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;~~

variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

~~available sources and costs of fuels;~~

~~effects of inflation;~~

ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity factors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training, unforeseen engineering or design problems, delays associated with start-up activities (including major equipment failure and system integration), and/or operations;

ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any operational and environmental performance standards, including any PSC requirements and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

~~investment performance of Southern Company's employee and retiree benefit plans and the Southern Company system's nuclear decommissioning trust funds;~~

~~advances in technology;~~

~~state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;~~

legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions and related legal proceedings involving the commercial parties;

actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of Mississippi Power's proposed rate recovery plan, as ultimately amended, which currently includes the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2014, and satisfaction of requirements to utilize ITCs and grants;

~~Mississippi PSC review of the prudence of Kemper IGCC costs;~~

~~Table of Contents~~

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;

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;

actions related to cost recovery for the Kemper IGCC, including actions relating to Mississippi PSC approval of a rate recovery plan, including Mississippi Power's request for interim rates, proposed securitization, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2015, and satisfaction of requirements to utilize ITCs and grants;

the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;

Mississippi PSC review of the prudence of Kemper IGCC costs;

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

the ~~outcome~~ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's order implementing such decision, and any further related legal or regulatory ~~proceedings regarding any settlement agreement between Mississippi Power~~proceedings;

the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and the ~~Mississippi PSC, the March 2013 rate order approving retail rate increases consistent with the terms~~successful performance of ~~any settlement agreement, or the Baseload Act;~~necessary corporate functions;

the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

internal restructuring or other restructuring options that may be pursued;

potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

the ability to obtain new short- and long-term contracts with wholesale customers;

the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist ~~incidents, including cyber intrusion;~~incidents;

interest rate fluctuations and financial market conditions and the results of financing ~~efforts, including~~efforts;

changes in Southern Company's and any of its subsidiaries' credit ~~ratings;~~ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

the impacts of any ~~potential U.S. credit rating downgrade or other~~ sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

the ability of Southern Company's subsidiaries to obtain additional generating capacity at competitive prices;

catastrophic events such as fires, earthquakes, explosions, floods, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;

the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

the effect of accounting pronouncements issued periodically by ~~standard setting~~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.

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THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in millions)						(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	4,558		$	4,319		$	12,186		$	11,237		$	3,714		$	3,770		$	7,256		$	7,628
Wholesale revenues	600			520			1,719			1,406			448			515			915			1,119
Other electric revenues	169			166			503			477			162			169			325			334
Other revenues	12			12			42			40			13			13			24			30
Total operating revenues	5,339			5,017			14,450			13,160			4,337			4,467			8,520			9,111
Operating Expenses:
Fuel	1,656			1,580			4,765			4,216			1,200			1,462			2,412			3,109
Purchased power	194			145			514			367			171			133			315			320
Other operations and maintenance	1,021			928			3,026			2,849			1,100			1,019			2,222			2,005
Depreciation and amortization	514			480			1,515			1,422			500			504			987			1,001
Taxes other than income taxes	258			243			751			710			245			246			497			493
Estimated loss on Kemper IGCC	418			150			798			1,140			23			—			32			380
Total operating expenses	4,061			3,526			11,369			10,704			3,239			3,364			6,465			7,308
Operating Income	1,278			1,491			3,081			2,456			1,098			1,103			2,055			1,803
Other Income and (Expense):
Allowance for equity funds used during construction	63			53			182			139			39			62			102			119
Interest expense, net of amounts capitalized	(207		)	(202		)	(623		)	(628		)	(180		)	(210		)	(393		)	(416		)
Other income (expense), net	(7		)	(5		)	(20		)	(31		)	(12		)	(6		)	(19		)	(13		)
Total other income and (expense)	(151		)	(154		)	(461		)	(520		)	(153		)	(154		)	(310		)	(310		)
Earnings Before Income Taxes	1,127			1,337			2,620			1,936			945			949			1,745			1,493
Income taxes	392			468			889			657			302			321			576			497
Consolidated Net Income	735			869			1,731			1,279			643			628			1,169			996
Dividends on Preferred and Preference Stock of Subsidiaries	17			17			51			49			14			17			31			34
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	718		$	852		$	1,680		$	1,230		$	629		$	611		$	1,138		$	962
Common Stock Data:
Earnings per share (EPS) -
Earnings per share (EPS) —
Basic EPS	$	0.80		$	0.97		$	1.88		$	1.41		$	0.69		$	0.68		$	1.25		$	1.08
Diluted EPS	$	0.80		$	0.97		$	1.87		$	1.40		$	0.69		$	0.68		$	1.25		$	1.07
Average number of shares of common stock outstanding (in millions)
Basic	898			878			894			874			909			895			910			892
Diluted	902			881			898			879			912			899			914			896
Cash dividends paid per share of common stock	$	0.5250		$	0.5075		$	1.5575		$	1.5050		$	0.5425		$	0.5250		$	1.0675		$	1.0325

The accompanying notes as they relate to Southern Company are an integral part of these ~~condensed~~consolidated financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in millions)						(in millions)						(in millions)						(in millions)
Consolidated Net Income	$	735		$	869		$	1,731		$	1,279		$	643		$	628		$	1,169		$	996
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2 and $5, respectively	1			1			4			7
Changes in fair value, net of tax of $12, $-, $1, and $-, respectively													19			—			1			—
Reclassification adjustment for amounts included in net income, net of tax of $1, $-, $2, and $2, respectively													2			1			3			2
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2 and $3, respectively	1			1			2			4
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2, and $1, respectively													1			1			3			2
Total other comprehensive income (loss)	2			2			6			11			22			2			7			4
Dividends on preferred and preference stock of subsidiaries	(17		)	(17		)	(51		)	(49		)	(14		)	(17		)	(31		)	(34		)
Comprehensive Income	$	720		$	854		$	1,686		$	1,241		$	651		$	613		$	1,145		$	966

The accompanying notes as they relate to Southern Company are an integral part of these ~~condensed~~consolidated financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months Ended September 30,						For the Six Months Ended June 30,
	2014			2013			2015				2014
	(in millions)						(in millions)
Operating Activities:
Consolidated net income	$	1,731		$	1,279		$	1,169			$	996
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,798			1,725			1,171				1,182
Deferred income taxes	330			263			783				46
Allowance for equity funds used during construction	(182		)	(139		)	(102		)		(119		)
Stock based compensation expense	51			48			66				40
Estimated loss on Kemper IGCC	798			1,140			32				380
Income taxes receivable, non-current							(444		)		—
Other, net	(74		)	76			(6		)		23
Changes in certain current assets and liabilities —
-Receivables	(640		)	(407		)	(158		)		(579		)
-Fossil fuel stock	522			471			136				419
-Materials and supplies	(45		)	33			(21		)		(20		)
-Other current assets	(29		)	(1		)	(78		)		(88		)
-Accounts payable	(92		)	(140		)	(311		)		(231		)
-Accrued taxes	403			268			(60		)		72
-Accrued compensation	96			(198		)	(269		)	��	(40		)
-Mirror CWIP							82				67
-Other current liabilities	20			(7		)	117				(78		)
Net cash provided from operating activities	4,687			4,411			2,107				2,070
Investing Activities:
Property additions	(3,903		)	(3,978		)	(2,647		)		(2,692		)
Investment in restricted cash	(11		)	(169		)
Distribution of restricted cash	37			94
Nuclear decommissioning trust fund purchases	(635		)	(744		)	(933		)		(445		)
Nuclear decommissioning trust fund sales	633			742			928				443
Cost of removal, net of salvage	(106		)	(90		)	(87		)		(54		)
Change in construction payables, net							56				89
Prepaid long-term service agreement	(145		)	(79		)	(110		)		(93		)
Other investing activities	(27		)	122			27				(17		)
Net cash used for investing activities	(4,157		)	(4,102		)	(2,766		)		(2,769		)
Financing Activities:
Decrease in notes payable, net	(1,117		)	(70		)
Increase in notes payable, net							184				339
Proceeds —
Long-term debt issuances	2,715			2,421			3,075				1,314
Interest-bearing refundable deposit	75			—			—				75
Preference stock	—			50
Common stock issuances	484			479			116				318
Redemptions —
Short-term borrowings							320				—
Redemptions and repurchases—
Long-term debt	(437		)	(1,767		)	(939		)		(431		)
Common stock repurchased	(5		)	(19		)
Interest-bearing refundable deposits							(275		)		—
Preferred and preference stock							(412		)		—
Common stock							(115		)		(5		)
Short-term borrowings							(250		)		—
Payment of common stock dividends	(1,391		)	(1,314		)	(972		)		(920		)
Payment of dividends on preferred and preference stock of subsidiaries	(51		)	(49		)	(36		)		(34		)
Other financing activities	(48		)	14			66				(33		)
Net cash provided from (used for) financing activities	225			(255		)
Net cash provided from financing activities							762				623
Net Change in Cash and Cash Equivalents	755			54			103				(76		)
Cash and Cash Equivalents at Beginning of Period	659			628			710				659
Cash and Cash Equivalents at End of Period	$	1,414		$	682		$	813			$	583
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $80 and $67 capitalized for 2014 and 2013, respectively)	$	560		$	564
Cash paid (received) during the period for --
Interest (net of $57 and $47 capitalized for 2015 and 2014, respectively)							$	374			$	365
Income taxes, net	263			149			(16		)		212
Noncash transactions — accrued property additions at end of period	415			539
Noncash transactions — capital lease obligation	—			83
Noncash transactions — Accrued property additions at end of period							345				509

The accompanying notes as they relate to Southern Company are an integral part of these ~~condensed~~consolidated financial statements.

Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


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

The accompanying notes as they relate to Southern Company are an integral part of these ~~condensed~~consolidated financial statements.

Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


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

The accompanying notes as they relate to Southern Company are an integral part of these ~~condensed~~consolidated financial statements.

Table of Contents

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~THIRD~~SECOND QUARTER ~~2014~~2015 vs. ~~THIRD~~SECOND QUARTER ~~2013~~2014

AND

YEAR-TO-DATE ~~2014~~2015 vs. YEAR-TO-DATE ~~2013~~2014

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional operating companies ~~– Alabama Power, Georgia Power, Gulf Power, and Mississippi Power –~~ and Southern Power Company and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business of electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company's other business activities include investments in leveraged lease projects and telecommunications. For additional information on these businesses, see BUSINESS – "The Southern Company System – Traditional Operating Companies," ~~"Southern~~" – Southern Power," and ~~"Other~~" – Other Businesses" in Item 1 of the Form 10-K.

In addition, ~~subsidiaries of Southern Company are constructing~~construction continues on Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and ~~the~~Mississippi Power's 582-MW Kemper ~~IGCC (in which Mississippi Power is ultimately expected to hold an 85% ownership interest in the 582-MW facility).~~IGCC. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements herein.

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects, and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7 of the Form 10-K. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding revisions to the cost estimate for the Kemper IGCC that have negatively impacted Southern Company's earnings per share, one of its key performance indicators, for 2014, as compared to the target.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$(134) (15.7) $450 36.6

Southern Company's ~~third~~second quarter ~~2014~~2015 net income after dividends on preferred and preference stock of subsidiaries was ~~$718~~$629 million ($~~0.80~~0.69 per share) compared to ~~$852~~$611 million ($~~0.97~~0.68 per share) for the ~~third~~second quarter ~~2013.~~2014. The increase was primarily due to an increase in retail revenues resulting from retail base rate increases and warmer weather in the second quarter 2015 as compared to the corresponding period in 2014, partially offset by the correction of an error affecting billings to certain Georgia Power commercial and industrial customers. Also contributing to the increase were state income tax benefits realized and a decrease in interest expense. The increase in net income was partially offset by increases in non-fuel operations and maintenance expenses and a decrease in AFUDC equity.

Southern Company's year-to-date 2015 net income after dividends on preferred and preference stock of subsidiaries was $1.1 billion ($1.25 per share) compared to $962 million ($1.08 per share) for the corresponding period in 2014. The increase was primarily the result of lower pre-tax charges of $32 million ($20 million after tax) recorded in 2015 compared to a ~~$418 million~~ pre-tax charge of $380 million ($~~258~~235 million after tax) recorded in the ~~third quarter~~corresponding period in 2014 ~~compared to a $150 million pre-tax charge ($93 million after tax) recorded in the third quarter 2013~~ for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, as well as increases in non-fuel operations and maintenance expenses. The decrease was partially offset by an increase in revenues due to retail base rate increases and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.

Southern Company's year-to-date 2014 net income after dividends on preferred and preference stock of subsidiaries was $1.7 billion ($1.88 per share) compared to $1.2 billion ($1.41 per share) for the corresponding period in 2013. The increase was primarily the result of $798 million in pre-tax charges ($493 million after tax) recorded year-to-

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

date 2014 compared to $1.1 billion in pre-tax charges ($704 million after tax) recorded year-to-date 2013 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC. The increase was also related toIGCC, as well as an increase in ~~revenues due to~~ retail base ~~rate increases as well as colder weather~~rates. The increase in ~~the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013,~~net income was partially offset by increases in non-fuel operations and maintenance expenses.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$239 5.5 $949 8.4

In the ~~third~~second quarter ~~2014,~~2015, retail revenues were ~~$4.6~~$3.7 billion compared to ~~$4.3~~$3.8 billion for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, retail revenues were ~~$12.2~~$7.3 billion compared to ~~$11.2~~$7.6 billion for the corresponding period in ~~2013.~~2014.

Details of the changes in retail revenues were as follows:


	Third Quarter 2014				Year-to-Date 2014				Second Quarter 2015					Year-to-Date 2015
	(in millions)		(% change)		(in millions)		(% change)		(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	4,319			$	11,237			$	3,770				$	7,628
Estimated change resulting from –
Rates and pricing	89		2.1		242		2.1		30			0.8		107			1.4
Sales growth	9		0.2		29		0.3		23			0.6		41			0.5
Weather	87		2.0		238		2.1		46			1.2		8			0.1
Fuel and other cost recovery	54		1.2		440		3.9		(155		)	(4.1	)	(528		)	(6.9	)
Retail – current year	$	4,558	5.5	%	$	12,186	8.4	%	$	3,714		(1.5	)%	$	7,256		(4.9	)%

Revenues associated with changes in rates and pricing increased in the ~~third~~second quarter and year-to-date ~~2014~~2015 when compared to the corresponding periods in ~~2013~~2014 primarily due to ~~retail~~increased revenues at Alabama Power associated with an increase in rates under rate ~~increases at all of the traditional operating companies. The increases in revenues~~stabilization and equalization (Rate RSE) and at Georgia Power ~~were primarily due~~related to base tariff increases ~~effective January 1, 2014, as~~ approved ~~by the Georgia PSC in~~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, ~~as well as higher contributions from market-driven rates from~~all effective January 1, 2015. The increase was partially offset by the correction of an error affecting billings since 2013 to a small number of large commercial and industrial ~~customers. Also contributing~~customers under a rate plan allowing for variable demand-driven pricing at Georgia Power. See Note (A) to the ~~increases were increased revenues at Alabama Power associated with Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets~~Condensed Financial Statements herein and increased revenues at Gulf Power primarily resulting from the retail base rate increase effective January 2014, as approved by the Florida PSC. In addition, the year-to-date 2014 increase also reflects increased revenues at Mississippi Power related to the collection of Kemper IGCC cost recovery revenues, the majority of which were deferred to a regulatory liability, and a PEP base rate increase, which both became effective in March 2013.

~~See~~ Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate RSE" and "Retail Regulatory Matters – Georgia Power – Rate ~~Plans," "Retail Regulatory Matters – Alabama Power~~ – ~~Rate CNP," and "Retail Regulatory Matters~~ – ~~Gulf Power – Retail Base Rate Case"~~Plans" in Item 8 of the Form 10-K for additional information. Also see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power – Performance Evaluation Plan" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

Revenues attributable to changes in sales increased in the ~~third~~second quarter ~~and year-to-date 2014~~2015 when compared to the corresponding ~~periods~~period in ~~2013.~~2014. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales increased 1.2% and 0.7%, respectively, in the second quarter 2015, both as a result of customer growth. Industrial KWH ~~energy~~ sales increased ~~4.8%~~0.2% in the ~~third~~second quarter ~~and 3.6% for year-to-date 2014~~2015 primarily due to increased sales in the non-manufacturing, transportation, and pipeline sectors, partially offset by decreased sales in the primary metals, chemicals, and paper sectors.

Revenues attributable to changes in sales increased for year-to-date 2015 when compared to the corresponding period in 2014. Industrial KWH sales increased 1.1% for year-to-date 2015 primarily due to increased sales in the non-manufacturing, transportation, pipeline, and ~~stone, clay,~~petroleum sectors, partially offset by decreased sales in the primary metals and ~~glass~~chemicals sectors. Weather-adjusted commercial KWH ~~energy~~ sales ~~decreased 1.1% in the third quarter and 0.5%~~increased 0.7% for year-to-date ~~2014~~2015 primarily due to ~~decreased~~ customer ~~usage,~~growth. Weather-adjusted residential KWH sales increased 0.7% for year-to-date 2015 as a result of customer growth, partially offset by decreased customer usage.

In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled second quarter and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~customer growth. Weather-adjusted~~this adjustment, second quarter 2015 weather-adjusted residential sales increased 1.4%, weather-adjusted commercial sales increased 0.5%, and industrial KWH sales ~~remained relatively flat~~increased 0.1% as compared to the corresponding period in 2014. Also, without this adjustment, year-to-date 2015 weather-adjusted residential sales increased 0.6%, weather-adjusted commercial sales increased 0.4%, and industrial KWH sales increased 1.0% as compared to the ~~third quarter and for year-to-date 2014 as a result of customer growth offset by decreased customer usage. Household income, one of the primary drivers of residential customer usage, has been flat~~corresponding period in 2014.

Fuel and other cost recovery revenues ~~increased $54~~decreased $155 million and $528 million in the ~~third~~second quarter ~~2014~~and year-to-date 2015, respectively, when compared to the corresponding period in 2013 primarily due to increased energy sales as a result of warmer weather in the third quarter 2014 as compared to the corresponding period in 2013. Fuel and other cost recovery revenues increased $440 million for year-to-date 2014 when compared to the corresponding period in 2013 primarily due to higher natural gas prices and increased energy sales as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in ~~2013.~~2014 primarily due to a decrease in fuel prices.

Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. The traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPAs.

Wholesale Revenues

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$80 15.4 $313 22.3

Wholesale revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale revenues from PPAs (other than solar PPAs) have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Wholesale revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

In the ~~third~~second quarter ~~2014,~~2015, wholesale revenues were ~~$600~~$448 million compared to ~~$520~~$515 million for the corresponding period in ~~2013 primarily~~2014 related to ~~an $82~~a $44 million ~~increase in energy revenues. The increase~~decrease in energy revenues ~~was primarily related to new solar PPAs~~ and ~~requirements contracts and increased revenue under existing contracts primarily at Southern Power, as well as an increase~~a $23 million decrease in ~~KWH sales resulting from utilization of the Southern Company system's lower cost generation.~~

capacity revenues. For year-to-date ~~2014,~~2015, wholesale revenues were ~~$1.7 billion~~$915 million compared to ~~$1.4~~$1.1 billion for the corresponding period in ~~2013, reflecting~~2014 related to a ~~$303~~$162 million ~~increase~~decrease in energy revenues and a ~~$10~~$42 million ~~increase~~decrease in capacity revenues. The ~~increase~~decreases in energy revenues ~~was~~were primarily related to ~~increased revenue under existing contracts as well as~~lower fuel costs, partially offset by increases in energy revenues from new solar PPAs ~~and requirements contracts primarily~~ at Southern ~~Power, increased demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013, and an increase in the average cost of natural gas.~~Power. The ~~increase~~decreases in capacity revenues ~~was~~were primarily due to the expiration of wholesale ~~base rate increases~~contracts in December 2014 at ~~Mississippi~~Georgia Power, ~~partially offset by a decrease in capacity revenues~~unit retirements at Georgia Power, and PPA expirations at Southern Power.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Other Electric Revenues~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$3 1.8 $26 5.5

For year-to-date 2014, other electric revenues were $503 million compared to $477 million for the corresponding period in 2013. The increase was primarily due to a $19 million increase in open access transmission tariff revenues at Alabama Power and Georgia Power and a $6 million increase in solar application fee revenue at Georgia Power.

Fuel and Purchased Power Expenses


	Third Quarter 2014 vs. Third Quarter 2013			Year-to-Date 2014 vs. Year-to-Date 2013			Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)		(% change)	(change in millions)		(% change)	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	76	4.8	$	549	13.0	$	(262	)	(17.9)	$	(697	)	(22.4)
Purchased power	49		33.8	147		40.1	38			28.6	(5		)	(1.6)
Total fuel and purchased power expenses	$	125		$	696		$	(224	)		$	(702	)

In the ~~third~~second quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$1.9~~$1.4 billion compared to ~~$1.7~~$1.6 billion for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily the result of a ~~$139~~$337 million increase in the volume of KWHs generated primarily due to increased demand resulting from warmer weather in the third quarter 2014 compared to the corresponding period in 2013, a $41 million increase in the average cost of purchased power, and a $16 million increase in the volume of KWHs purchased, partially offset by a $71 million decrease ~~in the average cost of fuel primarily due to lower coal prices.~~

For year-to-date 2014, total fuel and purchased power expenses were $5.3 billion compared to $4.6 billion for the corresponding period in 2013. The increase was primarily the result of a $439 million increase in the volume of KWHs generated primarily due to increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 compared to the corresponding periods in 2013 and a $298 million increase in the average cost of fuel and purchased power primarily due to ~~higher~~lower coal and natural gas ~~prices. These increases were~~prices, partially offset by a ~~$41~~$113 million ~~decrease~~increase in the volume of KWHs generated and purchased primarily due to increased demand resulting from warmer weather in the second quarter 2015 as compared to the ~~marginal~~corresponding period in 2014.

For year-to-date 2015, total fuel and purchased power expenses were $2.7 billion compared to $3.4 billion for the corresponding period in 2014. The decrease was primarily the result of a $792 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $90 million increase in the ~~Southern Company system's generation available was lower than the market cost~~volume of ~~available energy.~~KWHs generated and purchased.

Fuel and purchased power energy transactions at the traditional operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – ~~"PSC~~"Retail Regulatory Matters – Retail Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

Details of the Southern Company system's generation and purchased power were as follows:



	Second Quarter 2015	Second Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (billions of KWHs)	46	47	92	94
Total purchased power (billions of KWHs)	4	2	6	5
Sources of generation (percent) —
Coal	39	44	36	45
Nuclear	15	17	16	16
Gas	42	36	44	35
Hydro	3	3	3	4
Renewables	1	—	1	—
Cost of fuel, generated (cents per net KWH) —
Coal	3.37	3.79	3.52	4.00
Nuclear	0.84	0.89	0.75	0.89
Gas	2.76	3.82	2.73	4.00
Average cost of fuel, generated (cents per net KWH)	2.70	3.28	2.70	3.46
Average cost of purchased power (cents per net KWH)^(*)	5.63	7.41	6.26	8.20


(*)	Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Details of the Southern Company system's generation and purchased power were as follows:~~

Third Quarter
2014 Third Quarter
2013 Year-to-Date 2014 Year-to-Date 2013
Total generation (billions of KWHs)
54 50 147 136
Total purchased power (billions of KWHs)
3 3 9 10
Sources of generation (percent) —

Coal 44 44 45 40
Nuclear 15 16 16 17
Gas 40 37 36 39
Hydro 1 3 3 4
Cost of fuel, generated (cents per net KWH) —

Coal 3.63 4.06 3.87 4.08
Nuclear 0.84 0.87 0.87 0.87
Gas 3.42 3.27 3.77 3.30
Average cost of fuel, generated (cents per net KWH)
3.13 3.24 3.34 3.21
Average cost of purchased power (cents per net KWH)^(a)
6.77 5.66 7.60 5.22


~~(a)~~	~~Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.~~

Fuel

In the ~~third~~second quarter ~~2014,~~2015, fuel expense was ~~$1.7~~$1.2 billion compared to ~~$1.6~~$1.5 billion for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~68.3%~~27.8% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall and a 9.9% increase in the volume of KWHs generated by fossil fuel, partially offset by a 10.6% decrease in the average cost of coal per KWH generated.

For year-to-date 2014, fuel expense was $4.8 billion compared to $4.2 billion for the corresponding period in 2013. The increase was primarily due to a 21.6% increase in the volume of KWHs generated by coal, a 14.2% increase in the average cost of natural gas per KWH generated, an 11.1% decrease in the average cost of coal per KWH generated, and a ~~31.5%~~10.6% decrease in the volume of KWHs generated by ~~hydro facilities resulting from less rainfall.~~coal, partially offset by a 19.7% increase in the volume of KWHs generated by natural gas.

For year-to-date 2015, fuel expense was $2.4 billion compared to $3.1 billion for the corresponding period in 2014. The decrease was primarily due to a 31.8% decrease in the average cost of natural gas per KWH generated, a 21.2% decrease in the volume of KWHs generated by coal, and a 12.0% decrease in the average cost of coal per KWH generated, partially offset by a 32.3% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the ~~third~~second quarter ~~2014,~~2015, purchased power expense was ~~$194~~$171 million compared to ~~$145~~$133 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to a ~~19.6% increase in the average cost per KWH purchased primarily as a result of higher natural gas prices and an 8.3%~~50.0% increase in the volume of KWHs purchased primarily as a result of increased demand from warmer weather in the ~~third~~second quarter ~~2014~~2015 as compared to the corresponding period in ~~2013.~~2014, partially offset by a 24.0% decrease in the average cost per KWH purchased.

For year-to-date ~~2014,~~2015, purchased power expense was ~~$514~~$315 million compared to ~~$367~~$320 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~45.6% increase~~23.7% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by an ~~8.3% decrease~~18.0% increase in the volume of KWHs ~~purchased as the marginal cost of the Southern Company system's generation available was lower than the market cost of available energy primarily due to higher natural gas prices.~~purchased.

Energy purchases will vary depending on demand for energy within the Southern Company system's service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.

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~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$93 10.0 $177 6.2

In the ~~third~~second quarter ~~2014,~~2015, other operations and maintenance expenses were ~~$1.0~~$1.1 billion compared to ~~$928 million~~$1.0 billion for the corresponding period in ~~2013.~~2014. The increase was primarily due to a ~~$30~~$32 million increase in ~~transmission and distribution costs~~generation expenses primarily related to ~~overhead line~~non-outage operations and maintenance, a ~~$29~~$23 million ~~increase in scheduled outage and maintenance costs at generation facilities, a $14 million increase in commodity and contract labor costs, a $12 million net~~ increase in employee compensation and benefits including pension costs, and a $6 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management ~~programs. The increase in scheduled outage and maintenance costs was~~programs, partially offset by a $7 million decrease in transmission and distribution costs primarily related to overhead line maintenance. In addition, in the second quarter 2014, Alabama Power deferred approximately $16 million ~~deferral~~ of certain non-nuclear outage expenditures under an accounting ~~order at Alabama Power.~~order.

For year-to-date ~~2014,~~2015, other operations and maintenance expenses were ~~$3.0~~$2.2 billion compared to ~~$2.8~~$2.0 billion for the corresponding period in ~~2013.~~2014. The increase was primarily due to ~~an $80~~a $58 million increase in employee compensation and benefits including pension costs, a $41 million increase in generation expenses primarily related to non-outage operations and maintenance, a $30 million increase in scheduled outage and maintenance costs at generation facilities, and a $53 million increase in transmission and distribution costs primarily related to overhead line maintenance, a $29 million increase in commodity and contract labor costs, a $15 million net increase in employee compensation and benefits including pension costs, a $10$22 million increase in customer accounts, service, and sales costs primarily related to customer incentive and ~~demand-side~~demand side management ~~programs, and a $7~~programs. In addition, in the first half of 2014, Alabama Power deferred approximately $41 million ~~increase in litigation expense. The increase in scheduled outage and maintenance costs was partially offset by a $57 million deferral~~ of certain non-nuclear outage expenditures under an accounting ~~order at Alabama Power.~~order.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Non-Nuclear Outage Accounting Order" in Item 8 of the Form 10-K for additional information related to non-nuclear outage expenditures. Also see Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

~~Depreciation and Amortization~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$34 7.1 $93 6.5

In the third quarter 2014, depreciation and amortization was $514 million compared to $480 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $1.5 billion compared to $1.4 billion for the corresponding period in 2013. The increases were primarily due to an increase in plant in service at Southern Power related to the additions of solar facilities in 2013 and 2014 and additional component depreciation at Southern Power as a result of production being greater during the summer months, as well as the completion of amortization of a regulatory liability related to state income tax credits in December 2013 at Georgia Power. Also contributing to the year-to-date increase was an increase in depreciation rates related to environmental assets at Alabama Power. These increases were partially offset by a decrease in depreciation and amortization at Georgia Power, as authorized in the 2013 ARP. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate CNP" of Southern Company in Item 7 of the Form 10-K for additional information regarding Alabama Power's revision to Rate CNP Environmental. Also see Note (A) to the Condensed Financial Statements under "Depreciation" herein for additional information related to component depreciation at Southern Power.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Taxes Other Than Income Taxes~~Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$15 6.2 $41 5.8

~~In the third quarter 2014, taxes other than income taxes were $258~~For year-to-date 2015, depreciation and amortization was $987 million compared to ~~$243 million~~$1.0 billion for the corresponding period in ~~2013. For year-to-date 2014, taxes~~2014. The decrease was primarily due to a $49 million reduction in depreciation rates at Alabama Power, a $14 million reduction in depreciation at Gulf Power, as approved by the Florida PSC, and a $9 million reduction in other ~~than income taxes were $751~~cost of removal at Georgia Power, partially offset by a $49 million ~~compared to $710 million for the corresponding period in 2013. The increases were primarily the~~increase as a result of ~~increases~~additional plant in service at the traditional operating companies and Southern Power. See Note 3 to the financial statements of ~~$7 million~~Southern Company under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" in Item 8 of the Form 10-K and ~~$29 million in municipal franchise fees related~~Note (B) to ~~higher retail revenues in 2014 and $5 million and $9 million in payroll taxes primarily related to higher employee benefits in~~ the ~~third quarter and year-to-date 2014, respectively.~~Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" herein for additional information.

Estimated Loss on Kemper IGCC

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$268 N/M $(342) (30.0)

N/M – Not meaningful

In the ~~third~~second quarter ~~2014~~2015, an estimated probable loss on the Kemper IGCC of $23 million was recorded at Southern Company. For year-to-date 2015 and ~~2013,~~2014, estimated probable losses on the Kemper IGCC of ~~$418~~$32 million and ~~$150~~$380 million, ~~respectively, were recorded at Southern Company. For year-to-date 2014 and 2013, estimated probable losses on the Kemper IGCC of $798 million and $1.1 billion,~~ respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). See FUTURE EARNINGS POTENTIAL – "Construction ~~Program"~~Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$10 18.9 $43 30.9

In the ~~third~~second quarter ~~2014,~~2015, AFUDC equity was ~~$63~~$39 million compared to ~~$53~~$62 million for the corresponding period in ~~2013. The increase was primarily related to additional capital expenditures at Alabama Power.~~

2014. For year-to-date ~~2014,~~2015, AFUDC equity was ~~$182~~$102 million compared to ~~$139~~$119 million for the corresponding period in ~~2013.~~2014. The ~~increase was~~decreases were primarily due to ~~an increase in CWIP related to~~ Mississippi ~~Power's~~Power placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and ~~additional capital expenditures~~lower AFUDC equity at ~~Alabama~~Georgia Power. Additionally, for year-to-date 2015, the decrease in AFUDC equity was partially offset by environmental and transmission projects at the traditional operating companies. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

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Interest Expense, Net of Amounts Capitalized

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$5 2.5 $(5) (0.8)

In the ~~third~~second quarter ~~2014,~~2015, interest expense, net of amounts capitalized was ~~$207~~$180 million compared to ~~$202~~$210 million in the corresponding period in 2013. The increase was primarily due to a $17 million increase related to a higher amount of outstanding long-term debt, partially offset by a $12 million decrease related to the refinancing of long-term debt at lower rates.

2014. For year-to-date ~~2014,~~2015, interest expense, net of amounts capitalized was ~~$623~~$393 million compared to ~~$628~~$416 million in the corresponding period in ~~2013.~~2014. The ~~decrease was~~decreases were primarily due to a ~~$30~~$41 million decrease related to the ~~refinancing~~termination of the asset purchase agreement (APA) between Mississippi Power and SMEPA which required the return of SMEPA's deposits at a lower rate of interest than accrued, partially offset by an increase in outstanding long-term ~~debt at lower rates and a $13 million~~debt. Also contributing to the year-to-date decrease was an increase in capitalized interest ~~partially offset by a $34 million increase~~primarily resulting from AFUDC debt and carrying costs related to a higher amount of outstanding long-term debt and a $7 million increase in interest expense resulting from the deposit received by Mississippi Power in January 2014 related to SMEPA's pending purchase of an undivided interest in the Kemper IGCC. See Note (E) to the Condensed Financial Statements herein for additional information. Also see Note (B) "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

~~Other~~ Income ~~(Expense), Net~~

Taxes

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$(2) N/M $11 35.5

~~N/M – Not meaningful~~

~~For year-to-date 2014, other~~In the second quarter 2015, income ~~(expense), net was $(20)~~taxes were $302 million compared to ~~$(31)~~$321 million for the corresponding period in ~~2013.~~2014. The decrease ~~in expense was~~is primarily due to ~~a $26 million charge~~state income tax benefits realized in 2015 and increased federal income tax benefits related to ~~the restructuring of a leveraged lease investment~~ITCs in ~~the first quarter 2013,~~2015 at Southern Power, partially offset by a ~~$7 million charge related to a settlement with the Sierra Club at Mississippi Power~~decrease in ~~2014. See Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.~~non-taxable AFUDC equity, higher pre-tax earnings, and beneficial changes that impacted 2014 state income taxes.

~~Income Taxes~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$(76) (16.2) $232 35.3

~~In the third quarter 2014,~~For year-to-date 2015, income taxes were ~~$392~~$576 million compared to ~~$468~~$497 million for the corresponding period in ~~2013.~~2014. The ~~decrease was~~increase primarily ~~due to higher~~reflects a reduction in tax benefits ~~in 2014~~ related to the estimated probable losses ~~recorded~~ on Mississippi Power's construction of the Kemper IGCC recorded in 2014, beneficial changes that impacted 2014 state income taxes, and a decrease in non-taxable AFUDC equity, partially offset by ~~higher pre-tax earnings.~~

~~For year-to-date 2014, income taxes were $889 million compared to $657 million for the corresponding period in 2013. The increase was primarily due to higher~~otherwise lower pre-tax earnings ~~and lower~~in 2015, state income tax benefits realized in ~~2014~~2015, and increased federal income tax benefits related to ITCs in 2015 at Southern Power.

See Note (G) to the ~~estimated probable losses recorded on Mississippi Power's construction of the Kemper IGCC.~~Condensed Financial Statements herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary business of selling electricity. These factors include the traditional operating companies' ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and the

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~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

construction of generating facilities, including the impact of ITCs, and the successful remarketing of capacity as current contracts expire. Changes in regional and global economic conditions may impact sales for the traditional operating companies and Southern Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely ~~basis.~~basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

New Source Review Actions

See Note 3 to the financial statements of Southern Company under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations," – ~~"PSC~~"Retail Regulatory Matters – Alabama Power – Environmental Accounting Order," and – ~~"PSC~~"Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K ~~and "PSC Matters~~ – ~~Alabama Power~~ – ~~Environmental Accounting Order" and~~ – ~~"PSC Matters~~ – ~~Georgia Power~~ – ~~Integrated Resource Plan" herein~~ for additional information ~~regarding the plans of~~on planned unit retirements and fuel conversions at Alabama Power, ~~and~~ Georgia Power, ~~for compliance with environmental statutes~~ and ~~regulations.~~Mississippi Power.

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR).

On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, Mississippi, North Carolina, and ~~the EPA's proposed rules~~Texas) to revise or remove state implementation plan (SIP) provisions regarding ~~the regulation of~~ excess emissions that occur during periods of ~~startup, shutdown, or malfunction (SSM).~~

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR.SSM by no later than November 22, 2016. The ultimate ~~financial and unit operational~~ impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

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On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama, Florida, Georgia, Mississippi, and North Carolina) to revise their SSM provisions within 18 months after issuance of the final ~~rule. The ultimate impact of the proposed SSM~~ rule will depend on ~~the specific provisions of the final rule, the development and implementation of rules at the state level, and~~ the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.

On June 29, 2015, the U.S. Supreme Court issued a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate ~~outcome~~impact of ~~these matters~~this decision cannot be determined at this time.

On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, Florida, Georgia, North Carolina, and Texas. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).

On ~~April 21, 2014,~~June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a ~~proposed~~final rule ~~to revise~~revising the regulatory definition of waters of the U.S. for all ~~Clean Water Act (CWA) programs,~~CWA programs. The final rule significantly ~~expanding~~expands the scope of federal jurisdiction under the ~~CWA. If finalized as proposed,~~CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. ~~In addition, the~~The rule ~~as proposed could have significant impacts on economic development projects which could affect customer demand growth.~~becomes effective August 28, 2015. The ultimate impact of the ~~proposed~~final rule will depend on ~~the specific requirements of the final rule and~~ the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – ~~Environmental Statutes and Regulations – Water Quality"~~ Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's ~~rulemaking for cooling water intake structures.~~regulation of CCR.

On ~~August 15, 2014,~~April 17, 2015, the EPA published athe Disposal of Coal Combustion Residuals from Electric Utilities final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became(CCR Rule) in the Federal Register, setting October 19, 2015 as the effective ~~October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation~~date of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units.CCR Rule. The ultimate impact of ~~this rule will depend on~~ the ~~outcome of any legal challenges and~~CCR Rule cannot be determined at this ~~time.~~timeand will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Southern Company recorded incremental asset retirement obligations (ARO) of approximately $700 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding these AROs.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's ~~current and~~ proposed regulation of ~~GHG emissions under the Clean Air Act.~~

~~On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address~~ CO₂ ~~emissions~~ from ~~existing fossil fuel-fired~~fossil-fuel-fired electric generating units. ~~The EPA's proposed guidelines establish state-specific interim and final CO~~₂ ~~emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposed CO~~₂ performance standards for modified and reconstructed fossil fuel-fired electric generating units. The proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, that could impact unit retirement and replacement decisions. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through market-based contracts. Further, any resulting higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO₂ emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO₂ emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO₂ performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market-based contracts. However, the ultimate financial and operational impact of the ~~Clean Power Plan proposed guidelines~~final rules on the Southern Company system cannot be determined at this time and will ~~be dependent upon~~depend on numerous ~~factors. These~~ factors ~~include:~~including the ~~structure, timing, and content~~Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final ~~guidelines; individual state implementation of these~~ guidelines, including the potential that state ~~implementation~~ plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and ~~emissions-related~~emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

FERC Matters

The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On ~~June 23, 2014,~~April 27, 2015, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit andFERC issued an order finding that the ~~EPA did~~traditional operating companies' and Southern Power's existing tailored mitigation may not ~~have~~effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to ~~tailor~~show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the ~~statutory permitting thresholds.~~FERC. The ultimate ~~impact~~outcome of ~~the U.S. Supreme Court's decision~~this matter cannot be determined at this time.

~~PSC~~Retail Regulatory Matters

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional operating companies continuously monitor their under or over recovered fuel cost balances. ~~At September 30, 2014,~~ Georgia Power ~~Gulf Power, and Mississippi Power had total under recovered~~expects to file its next fuel ~~costs included on Southern Company's Condensed Balance Sheet herein~~case in September 2015. The ultimate outcome of approximately $230 million. At December 31, 2013, Gulf Power had under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $21 million. The total over recovered fuel balancethis matter cannot be determined at Alabama Power included on Southern Company's Condensed Balance Sheet herein was approximately $44 million at September 30, 2014 compared to the total over recovered fuel balance at Alabama Power, Georgia Power, and Mississippi Power at December 31, 2013 of approximately $115 million.this time.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – ~~Retail Energy Cost Recovery"~~Rate ECR" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Alabama Power

~~Environmental Accounting Order~~Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business

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~~See~~ SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS ~~– FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes~~OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

primarily through its Rate RSE, Rate CNP, rate energy cost recovery, and ~~Regulations" and – "PSC~~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 – Environmental Accounting Order" of Southern Company~~Power" in Item 78 of the Form 10-K for additional information regarding Alabama Power's ~~plan~~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

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism and the normal purchases and normal sales (NPNS) exception for wind PPAs.

On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with ~~environmental statutes~~the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $30 million of non-environmental compliance costs during the first six months of 2015 and ~~regulations.~~will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under recovered position for Rate CNP Compliance during 2015.

AsIn April 2015, the Financial Accounting Standards Board (FASB) proposed new accounting guidance to allow the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power currently accounts for its two wind PPAs. On July 9, 2015, the FASB ratified the consensus reached by the Emerging Issues Task Force to allow the exception in such cases and voted to issue a final accounting standard.

Environmental Accounting Order

In April 2015, as part of its environmental compliance strategy, Alabama Power ~~plans to retire~~retired Plant Gorgas Units 6 and 7. These units ~~represent~~represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ~~also plans to cease~~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. ~~Additionally,~~No later than April 2016, Alabama Power expects to cease using coal at ~~Plant Barry Unit 3 (225 MWs) and~~ Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. ~~These plans are expected~~Subject to ~~be effective no later than April 2016.~~the final approval of the New Source Review stipulation, Alabama Power will also retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See Note (B) to the Condensed Financial Statements herein for additional information regarding the New Source Review actions.

In accordance with an accounting order from the Alabama PSC, Alabama Power ~~will transfer~~transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements.

Renewable Energy

On June 25, 2015, Alabama Power filed a petition with the Alabama PSC for a Renewable Generation Certificate (RGC). The RGC would develop a process that allows Alabama Power to build its own renewable projects each less than 80 MWs or purchase power from other renewable-generated sources up to 500 MWs. The Alabama PSC is expected to rule on this matter in August 2015. The ultimate outcome of this matter cannot be determined at this time.

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~~Nuclear Waste Fund Accounting Order~~Georgia Power

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K and "Other Matters" herein for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero.

~~On August 5, 2014, the Alabama PSC issued an order to provide for the continued recovery~~Georgia Power's revenues from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power is authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customersregulated retail operations are collected through various rate mechanisms subject to the ~~approval~~oversight of the ~~Alabama~~Georgia PSC.~~The ultimate outcome of this matter cannot be determined at this time.~~

~~Cost of Removal Accounting Order~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power" of Southern Company in Item 7 of the Form 10-K regarding the previously approved compliance and pension costs accounting order and non-nuclear outage accounting order.

On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, projected to be $120 million at December 31, 2014. This amortization expense will be offset by the amortization of up to $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances to be fully amortized as of December 31, 2014 represent costs deferred under the compliance and pension cost accounting order as well as the non-nuclear outage accounting order, which were approved by the Alabama PSC in November 2012 and August 2013, respectively. This accounting order also requires Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order and the non-nuclear outage accounting order. Consequently, Alabama Power will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders.

~~Georgia Power~~

~~Rate Plans~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters –~~ Georgia Power ~~– Rate Plans" of Southern Company in Item 7 and Note 3 to~~currently recovers its costs from the ~~financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information on Georgia Power's 2013 ARP.~~

~~In accordance with the terms of~~regulated retail business through the 2013 ARP, ~~on October 3, 2014, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2015 pending its approval:~~

~~Increase the~~which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, ~~by approximately $107 million~~Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to ~~cover additional capacity costs;~~

~~Increase~~ the ~~environmental compliance~~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 ~~tariff by approximately $32 million;~~

~~Increase the demand-side management tariffs by approximately $3 million; and~~

~~Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.~~

tariffs. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia ~~Power – Nuclear Construction"~~Power" in Item 8 of the Form 10-K for additional ~~information~~information.

Renewables Development

As part of the Georgia Power Advanced Solar Initiative program, Georgia Power executed ten PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. These PPAs are expected to commence in December 2015 and 2016 and have terms ranging from 20 to 30 years. As a result of certain acquisitions by Southern Power, Georgia Power expects that 249 MWs of the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.

On June 15, 2015, Georgia Power executed a PPA to purchase a total of 58 MWs of biomass capacity and energy from a 79-MW facility in Georgia that will begin in 2017 and end in 2047. This PPA was approved by the Georgia PSC on April 15, 2015. Georgia Power also entered into an energy-only PPA for the remaining 21 MWs from the same facility.

On July 21, 2015, the Georgia PSC approved Georgia Power's ~~NCCR tariff.~~ request to build, own, and operate a 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia by the end of 2016.

Integrated Resource Plan

To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) and its decertification will be requested in connection with the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Units 7 and 6 and the units were returned to service on May 4, 2015 and June 27, 2015, respectively.

Gulf Power

Renewables

On ~~October 31, 2014, Georgia~~April 16, 2015, the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. On May 5, 2015, the Florida PSC approved an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma. Purchases under these agreements will be for energy only and will be recovered through Gulf Power's fuel cost recovery mechanism.

Mississippi Power

2015 Rate Case

On May 15, 2015 and July 10, 2015, Mississippi Power filed alternative rate proposals related to ~~increase~~recovery of Kemper IGCC-related costs with the ~~NCCR tariff by approximately $27 million effective January~~Mississippi PSC. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.

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1,Renewables

In April and May 2015, ~~pending Georgia~~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, ~~approval. See Note (B)~~the projects are expected to be in service by the ~~Condensed Financial Statements under "Retail Regulatory Matters~~ – ~~Georgia Power~~ – ~~Nuclear Construction" herein for additional information.~~

end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of ~~these matters~~this matter cannot be determined at this time.

~~Renewables Development~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Renewables Development" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Renewables Development" in Item 8 of the Form 10-K for additional information.

On May 20, 2014, the Georgia PSC approved Georgia Power's application for the certification of two PPAs executed in April 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.

As a result of biomass PPA amendments executed by Georgia Power during 2014, total estimated purchased power contractual obligations decreased $392 million from December 31, 2013. Estimated purchased power contractual obligations have been updated for Southern Company to $669million for 2015 and 2016, $757 million for 2017 and 2018, and $3.9 billion after 2018. Estimated purchased power contractual obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations – Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for additional information.

On October 8, 2014, Georgia Power executed PPAs to purchase energy from 515 MWs of solar capacity as part of the Georgia Power Advanced Solar Initiative program. These PPAs are expected to commence in 2015 and 2016, have terms ranging from 20 to 30 years, and are subject to Georgia PSC approval.

On October 23, 2014, the Georgia PSC approved Georgia Power's request to build, own, and operate three 30-MW solar generation facilities at three U.S. Army bases by the end of 2016. In addition, Georgia Power has entered into a memorandum of understanding with the U.S. Navy to pursue a similar solar project pending Georgia PSC review.

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Integrated Resource Plan~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Integrated Resource Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information.

Georgia Power filed a request with the Georgia PSC on January 10, 2014 to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan in 2016. Georgia Power plans to continue to operate the unit as needed until the Mercury and Air Toxics Standards rule becomes effective in April 2015.

~~Storm Damage Recovery~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Storm Damage Recovery" of Southern Company in Item 7 of the Form 10-K for additional information.

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was $105 million and $37 million, respectively. The increase was primarily the result of an ice storm in February 2014. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Southern Company's financial statements.

~~Income Tax Matters~~

See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information about the Kemper IGCC. The ultimate outcome of these tax matters cannot be determined at this time.

~~Bonus Depreciation~~

In January 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which will apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million.

~~Investment Tax Credits~~

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through September 30, 2014, Southern Company had recorded tax benefits totaling $276.4 million for the Phase II credits, of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%~~of the CO~~₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's purchase of an undivided interest in the Kemper IGCC.

~~Section 174 Research and Experimental Deduction~~

For the 2013 tax year, Southern Company included in its consolidated federal income tax return a deduction for research and experimental (R&E) expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Southern Company recorded an unrecognized tax benefit of approximately $100 million as of September 30, 2014. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits" herein for additional information.

Construction Program

Overview

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new generating facilities, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC ~~approvals~~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 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and ~~the~~Mississippi Power's 582-MW Kemper ~~IGCC (in which Mississippi Power is ultimately expected to hold an 85% ownership interest).~~IGCC. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for the cost estimate of the Southern Company system's construction program, which includes the revised construction cost estimate to complete the Kemper IGCC. Also see Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined

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Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of ~~solar~~renewable energy facilities, see Note (I) to the Condensed Financial Statements herein.

Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.

Integrated Coal Gasification Combined Cycle

From 2013 through ~~September~~June 30, ~~2014,~~2015, Southern Company ~~has~~ recorded pre-tax charges totaling ~~$1.98~~$2.08 billion ($~~1.22~~1.28 billion after tax) for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

On February 12, 2015, the Mississippi Supreme Court issued its decision in a legal challenge with respect to the Mississippi PSC's March 2013 order that authorized Mississippi Power's collection of $156 million annually to be recorded as Mirror CWIP. Among other things, the Mississippi Supreme Court reversed this order and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts collected. As of June 30, 2015, $331 million had been collected by Mississippi Power. The Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015.

On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.

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The return of approximately $301 million to SMEPA in June 2015 in connection with the termination of the APA, the required refund of the approximately $353 million of Mirror CWIP rate collections, including associated carrying costs, and the termination of the Mirror CWIP rates have adversely impacted Mississippi Power's ability to obtain financing needed for its business operations. As a result, on July 10, 2015, Mississippi Power submitted a request for interim rates designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. These interim rates are designed to collect approximately $159 million annually. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015. The ultimate outcome of these matters cannot be determined at this time.

Nuclear Construction

On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).

While Georgia Power has not agreed to any change to the guaranteed substantial completion dates (April 2016 for Unit 3 and April 2017 for Unit 4) included in the engineering, procurement, and construction agreement relating to Plant Vogtle Units 3 and 4, Georgia Power's twelfth Vogtle Construction Monitoring (VCM) report, filed February 27, 2015, included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month Contractor delay, and to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $5.0 billion. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3. The Georgia PSC recognized that the certified cost does not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

Additionally, there are certain risks associated with the construction program in general and certain risks associated with the licensing, construction, and operation of nuclear generating units in particular, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K for additional information.

Section 174 Research and Experimental Deduction

Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Southern Company under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax

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Benefits – Section 174 Research and Experimental Deduction," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has ~~increased generally~~occurred throughout the U.S. ~~In particular, personal injury, property damage, and other~~This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, ~~coal combustion residuals,~~CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such ~~matters, have become more frequent.~~matters.

The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See ~~the Notes~~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.

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011.

Additionally, there are certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On June 17, 2014, the Georgia PSC approved Georgia Power's request to credit customers the portion of fuel cost related to the nuclear waste fund fee. The nuclear waste fund rider became effective July 1, 2014. See "PSC Matters – Alabama Power – Nuclear Waste Fund Accounting Order" herein for information regarding an accounting order issued by the Alabama PSC which provides for continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. The ultimate outcome of this matter cannot be determined at this time.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Pension and Other Postretirement Benefits.

Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery

During ~~2014,~~2015, Mississippi Power further ~~extended the scheduled in-service date for the Kemper IGCC to the first half of 2016 and~~ revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery ~~or any joint owner contributions~~ for any costs related ~~costs~~to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.

As a result of the revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of ~~$418.0~~$23 million ($~~258.1~~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, ~~$380.0~~$380 million ($~~234.7~~235 million after tax) in the first quarter 2014, ~~$40.0~~$40 million ($~~24.7~~25 million after tax) in the fourth quarter 2013, ~~$150.0~~$150 million ($~~92.6~~93 million after tax) in the third quarter 2013, ~~$450.0~~$450 million ($~~277.9~~278 million after tax) in the second quarter 2013, and ~~$540.0~~$540 million ($~~333.5~~333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of ~~$1.98~~$2.08 billion ($~~1.22~~1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through ~~September~~June 30, ~~2014.~~2015.

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Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions will be reflected in Southern Company's statements of income and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational ~~performance, operational~~ readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or ~~operations.~~operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately ~~$20~~$25 million to $30 million per month, w~~hich~~which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

Asset Retirement Obligations

AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.

The liability for AROs primarily relates to the decommissioning of the nuclear facilities - Alabama Power's Plant Farley and Georgia Power's ownership interests in Plants Hatch and Vogtle - and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based

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on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates. Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.

See Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Recently Issued Accounting Standards

~~On May 28, 2014, the Financial Accounting Standards Board issued~~The FASB's ASC 606, Revenue from Contracts with Customers~~. ASC 606~~, revises the accounting for revenue recognition ~~and is~~ effective for fiscal years beginning after December 15, ~~2016.~~2017. Southern Company ~~is currently evaluating~~continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Company.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. ~~Although earnings for the nine months ended September 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC,~~ Southern Company's financial condition remained stable at ~~September~~June 30, ~~2014.~~2015. Through ~~September~~June 30, ~~2014,~~2015, Southern Company has incurred non-recoverable cash expenditures of ~~$1.18~~$1.62 billion and is expected to incur approximately ~~$0.8~~$0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as ~~its~~ bank credit ~~arrangements~~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 ~~$4.7~~$2.1 billion for the first ~~nine~~six months of ~~2014,~~2015, an increase of ~~$276~~$37 million from the corresponding period in ~~2013.~~2014. The increase in net cash provided from operating activities was primarily due to an increase in ~~revenue due to rate increases and the effects of weather and a reduction in fossil~~ fuel ~~stock resulting from an increase in KWH generation,~~cost recovery, partially offset by ~~a decrease in receivables due to under recovered fuel costs.~~timing of accounts payable. Net cash used for investing activities totaled ~~$4.2~~$2.8 billion for the first ~~nine~~six months of ~~2014~~2015 primarily due to gross property additions for installation of equipment to ~~utility plant.~~comply with environmental standards, construction of generation, transmission, and distribution facilities, and acquisitions of solar facilities. Net cash provided from financing activities totaled ~~$225~~$762 million for the first ~~nine~~six months of ~~2014.~~2015. This was primarily due to issuances of long-term debt, ~~and common stock,~~ partially offset by common stock dividend payments and ~~a reduction in short-term debt.~~redemptions of long-term debt and preferred and preference stock. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first ~~nine~~six months of ~~2014~~2015 include an increase of ~~$2.0~~$2.1 billion in total property, plant, and equipment ~~for~~to comply with environmental standards and construction of generation, transmission, and distribution facilities, a $444 million increase in income taxes receivable, non-current associated with federal income tax benefits for deductions primarily related to R&E expenditures for the Kemper IGCC, and an increase of ~~$755~~$406 million in ~~cash and cash equivalents.~~accounts receivable primarily related to increases in customer billings as compared to

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December 31, 2014. Other significant changes include a ~~$1.2~~$2.1 billion increase in short-term and long-term debt to fund the Southern Company subsidiaries' continuous construction programs and for other general corporate purposes, ~~and an $849~~a $692 million increase in ~~total stockholders' equity.~~AROs primarily related to the CCR Rule, and a $619 million increase in accumulated deferred income taxes for deductions primarily related to R&E expenditures for the Kemper IGCC. See Notes (A), (B), and (G) to the Condensed Financial Statements herein for additional information regarding AROs, the Kemper IGCC, and R&E expenditures, respectively.

At the end of the ~~third~~second quarter ~~2014,~~2015, the market price of Southern Company's common stock was ~~$43.65~~$41.90 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was ~~$22.07~~$22.22 per share, representing a market-to-book ratio of ~~198%~~189%, compared to ~~$41.11, $21.43,~~$49.11, $21.98, and ~~192%~~223%, respectively, at the end of ~~2013.~~2014. Southern Company's common stock dividend for the ~~third~~second quarter ~~2014~~2015 was ~~$0.5250~~$0.5425 per share compared to ~~$0.5075~~$0.5250 per share in the ~~third~~second quarter ~~2013.~~2014.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately ~~$2.4~~$3.7 billion will be required through ~~September~~June 30, ~~2015~~2016 to fund maturities and announced redemptions of long-term debt. See ~~FUTURE EARNINGS POTENTIAL~~ – ~~"PSC Matters~~ – ~~Georgia Power~~ –

~~Table~~"Sources of ~~Contents~~

~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Renewables Development"~~Capital" herein for additional ~~information regarding estimated purchased power contractual obligations.~~

The Southern Company system's construction program is currently estimated to be $7.2 billion for 2014, $5.8 billion for 2015, and $4.4 billion for 2016, which includes expenditures related to construction and start-up of the Kemper IGCC of $1.3 billion for 2014, $551 million for 2015, and $75 million for 2016 and expenditures related to Southern Power's acquisition of a solar facility of $508 million for 2014. The amounts related to the construction and start-up of the Kemper IGCC exclude SMEPA's proposed acquisition of a 15% ownership share of the Kemper IGCC for approximately $569 million (including construction costs for all prior periods relating to its proposed ownership interest). The Southern Company system's amounts include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements.

Southern Company anticipates that the Southern Company system's capital expenditure requirements will continue to decline through the middle of the decade, before rising again to meet additional requirements for environmental compliance and new generation.information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.

Sources of Capital

Southern Company intends to meet its future capital needs through ~~internal~~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 ~~any~~ additional equity capital and debt to be raised in ~~2014,~~2015, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements.

Except as described herein, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.

On February 20, 2014, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement), pursuant to which the DOE agreed to guarantee borrowings to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and also are secured by a first priority lien on (i) Georgia Power's 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit

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~~Facility,~~In addition, Georgia Power may make ~~term loan~~ borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the ~~FFB. Proceeds~~DOE, the proceeds of ~~borrowings made under the FFB Credit Facility will~~which may be used to reimburse Georgia Power for ~~a portion~~Eligible Project Costs incurred in connection with its construction of ~~certain costs of construction relating to~~ Plant Vogtle Units 3 and ~~4 that are eligible for financing under~~4. Under the Loan Guarantee Agreement, ~~(Eligible~~the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs)~~. Aggregate~~ to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through June 30, 2015 would allow for borrowings of up to $2.2 billion under the FFB Credit Facility, ~~may not exceed the lesser~~ of ~~(i) 70% of Eligible Project Costs or (ii) approximately $3.46~~which Georgia Power has borrowed $1.8 billion. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

Eligible Project Costs incurred through September 30, 2014 would allow for borrowings of up to $2.0 billion under the FFB Credit Facility. Through September 30, 2014, Georgia Power has borrowed $1.0 billion under the FFB Credit Facility, leaving $1.0 billion of available borrowing ability.

Mississippi Power ~~has~~ received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

As of June 30, 2015, Southern Company's current liabilities ~~frequently exceed~~exceeded current assets by $2.1 billion, primarily due to long-term debt that is due within one year ~~as well as cash needs, which can fluctuate significantly due to the seasonality~~ of ~~the business of the~~$3.6 billion, including approximately $0.4 billion at Southern Company, ~~system.~~$0.6 billion at Alabama Power, $1.7 billion at Georgia Power, $0.4 billion at Mississippi Power, and $0.5 billion at Southern Power. In addition, Mississippi Power has $0.5 billion in short-term bank loans scheduled to mature on April 1, 2016. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets ~~including~~and financial institutions. Southern Company, the traditional operating companies, and Southern Power intend to utilize operating cash flows, as well as commercial paper, ~~programs which are backed~~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, for the remainder of 2015, Georgia Power expects to utilize borrowings through the FFB Credit Facility as its primary source of long-term borrowed funds.

The financial condition of Mississippi Power was adversely affected by ~~bank~~the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC. Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows and lines of credit ~~facilities.~~(to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

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At ~~September~~June 30, ~~2014,~~2015, Southern Company and its subsidiaries had approximately ~~$1.4~~$0.8 billion of cash and cash equivalents. Committed credit arrangements with banks at ~~September~~June 30, ~~2014~~2015 were as follows:


	Expires														Executable Term Loans				Due Within One Year				Expires												Executable Term Loans				Due Within One Year
Company	2014		2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out		2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)										(in millions)				(in millions)				(in millions)				(in millions)								(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	70		158		50		—		1,030		1,308		1,308		58		—		58		170		154		124		—		1,030		1,308		1,307		58		—		58		170
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—		—		150		—		1,600		1,750		1,737		—		—		—		150
Gulf Power	20		60		165		30		—		275		275		50		—		50		30		20		225		30		—		275		275		50		—		50		195
Mississippi Power	15		120		165		—		—		300		300		25		40		65		70		40		255		—		—		295		265		30		40		70		225
Southern Power	—		—		—		—		500		500		499		—		—		—		—		—		—		—		500		500		466		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		50		25		45		—		—		70		70		20		—		20		50
Total	$	105	$	408	$	530	$	30	$	4,130	$	5,203	$	5,188	$	153	$	40	$	193	$	320	$	239	$	799	$	30	$	4,130	$	5,198	$	5,120	$	158	$	40	$	198	$	790

See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies' variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of ~~September~~June 30, ~~2014~~2015 was approximately ~~$1.8~~$1.9 billion. In addition, at ~~September~~June 30, ~~2014,~~2015, the traditional operating companies had ~~$423~~$368 million of fixed rate pollution control revenue bonds outstanding that were required to be ~~remarketed~~reoffered within the next 12 months.

~~Southern Company and its subsidiaries expect to renew their bank credit arrangements as needed, prior to expiration.~~

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~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Southern Company, the traditional operating companies, and Southern Power are currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements, as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.

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Details of short-term borrowings were as follows:


	Short-term Debt at September 30, 2014			Short-term Debt During the Period^(a)					Short-term Debt at June 30, 2015				Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding		Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)		(in millions)				(in millions)				(in millions)
Commercial paper	$	361	0.3%	$	848	0.2%	$	1,528	$	512	0.3	%	$	1,155	0.3	%	$	1,563
Short-term bank debt	—		—	150		0.8%	250		545		1.3	%	717		1.2	%	795
Total	$	361	0.3%	$	998	0.3%			$	1,057	0.7	%	$	1,872	0.7	%


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.

~~(a) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2014.~~

~~Management~~Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank notes, and ~~cash.~~operating cash flows.

Credit Rating Risk

Southern Company and its subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, interest rate derivatives, and construction of new generation at ~~Georgia Power's~~ Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at ~~September~~June 30, ~~2014~~2015 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB and Baa2	$	9	$	9
At BBB- and/or Baa3	454		488
Below BBB- and/or Baa3	2,289		2,407

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

On June 5, 2015, Fitch downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power and revised the ratings outlook for Southern Company from stable to negative.

Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies on CreditWatch with negative implications.

Financing Activities

During the first six months of 2015, Southern Company issued approximately 3.2 million shares of common stock primarily through the employee equity compensation plan and received proceeds of approximately $116 million. Southern Company is not currently issuing shares of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by independent plan administrators.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Financing Activities~~

~~During the first nine months of 2014,~~On March 2, 2015, Southern Company ~~issued approximately 7.8~~announced a program to repurchase up to 20 million shares of Southern Company common stock ~~for approximately $295.5 million through~~to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock ~~plans,~~option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through June 30, 2015 at a total cost of ~~which 150,000 shares related~~approximately $115 million. Pursuant to ~~Southern Company's performance share plan.~~

~~Since August 2013,~~board approval, Southern Company ~~has used~~may repurchase shares ~~held~~through open market purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in treasury, to the extent available, to satisfy the requirements under the Southern Investment Plan and the employee savings plan and during the first nine months of 2014, issued approximately 5.0 million treasury shares for approximately $215.5 million. Beginning in June 2014, Southern Company used newly issued shares, as necessary, to satisfy the requirements.accordance with applicable securities laws.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first ~~nine~~six months of ~~2014:~~2015:


Company(a)	Senior Note Issuances		Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds^(a)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions^(b)			Senior Note Issuances		Senior Note Redemptions		Revenue Bond Issuances and Reofferings of Purchased Bonds^(b)		Revenue Bond Maturities and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(c)
	(in millions)														(in millions)
Southern Company	$	750	$	350	$	—	$	—	$	—		$	—		$	600	$	—	$	—	$	—	$	—	$	—
Alabama Power	400		—		—		—		—			—			975		250		80		134		—		—
Georgia Power	—		—		40		37		1,000			4			—		125		170		65		600		5
Gulf Power	200		—		42		29		—			—
Mississippi Power	—		—		—		—		493			222			—		—		—		—		—		351
Southern Power	—		—		—		—		10			1			650		—		—		—		—		—
Other	—		—		—		—		—			15			—		—		—		—		—		9
Elimination^(c)	—		—		—		—		(220		)	(220		)
Total	$	1,350	$	350	$	82	$	66	$	1,283		$	22		$	2,225	$	375	$	250	$	199	$	600	$	365


(a)	~~Includes remarketing by~~ Gulf Power did not issue or redeem any long-term debt during the first six months of ~~$13~~2015.

(b)

Includes reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds previously purchased and held by ~~Gulf~~Alabama Power since ~~December 2013~~April 2015 and ~~remarketing~~reofferings by Georgia Power of ~~$40~~$104.6 million and $65 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since ~~2010.~~2013 and April 2015, respectively.


~~(b)~~(c)	Includes reductions in capital lease obligations resulting from cash payments under capital leases.


~~(c)~~	~~Intercompany loan from Southern Company to Mississippi Power eliminated in Southern Company's Condensed Consolidated Financial Statements. This loan was repaid on September 29, 2014.~~

In ~~August 2014,~~June 2015, Southern Company issued ~~$400~~$600 million aggregate principal amount of Series ~~2014A 1.30%~~2015A 2.750% Senior Notes due ~~August~~June 15, ~~2017 and $350 million aggregate principal amount of Series 2014B 2.15% Senior Notes due September 1, 2019.~~2020. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.

Southern Company's subsidiaries used the proceeds of the debt ~~issuances~~issuance shown in the table above for their ~~respective~~ redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their ~~respective~~ continuous construction ~~programs.~~programs and, for Southern Power, its growth strategy.

~~In addition to the amounts~~Alabama Power's "Senior Note Issuances" reflected in the table above includes issuances in ~~June 2014, Southern Company entered into a 90-day floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for~~April 2015 of $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used to redeem in May 2015 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for ~~working capital and other~~ general corporate purposes, including ~~the investment by Southern Company in its subsidiaries. This bank loan was repaid in August 2014.~~

In addition to the amounts reflected in the table above, in January 2014 and subsequent to September 30, 2014, Mississippi Power received an additional $75 million and $50 million, respectively, of interest-bearing refundableAlabama Power's continuous construction program.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" for additional information.

Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include ~~initial~~ borrowings under the FFB Credit Facility in an aggregate principal amount of ~~$1.0 billion~~$600 million in ~~February 2014.~~June 2015. The interest rate applicable to ~~$500~~the $600 million ~~of the initial advance under the FFB Credit Facility~~principal amount is ~~3.860%~~3.283% for an interest period that extends to ~~2044 and~~ the ~~interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029 and is expected to be reset from time to time thereafter through 2044. The~~ final maturity date ~~for all advances under the FFB Credit Facility is~~of February 20, 2044. The proceeds ~~of the initial borrowings under the FFB Credit Facility~~ were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. ~~In connection with its entry into the agreements with the DOE and the FFB,~~ Georgia Power ~~incurred issuance costs~~settled $350 million of interest rate swaps related to this borrowing for approximately ~~$66~~$6 million, which will be amortized to interest expense over ~~the life of the borrowings under the FFB Credit Facility.~~10 years.

~~Under the Loan Guarantee Agreement,~~In March 2015, Georgia Power is subject to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of Georgia Power or Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. See Note 6 to the financial statements of Southern Company in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.

~~In February 2014, Georgia Power repaid three four-month~~entered into a $250 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes and the loan was repaid at maturity.

In June 2015, Gulf Power entered into a three-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $40 million aggregate principal amount and the proceeds were used for credit support, working capital, and other general corporate purposes.

In addition to the amounts reflected in the table above, Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month floating rate promissory note to Southern Company in an aggregate principal amount of approximately $301 million bearing interest based on one-month LIBOR. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

Subsequent to ~~September~~June 30, ~~2014, Gulf Power's $75~~2015, Southern Power Company repaid at maturity $525 million aggregate principal amount of ~~Series K 4.90%~~its 4.875% Senior Notes ~~was paid at maturity.~~on July 15, 2015.

~~Subsequent~~Also subsequent to ~~September~~June 30, ~~2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional~~2015, $97.925 million aggregate principal amount of the ~~swaps totaled $100 million.~~Development Authority of Putnam County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Branch Project), First Series 1996, First Series 1997, Second Series 1997, and First Series 1998 were redeemed.

~~Subsequent~~Also subsequent to June 30, 2015, Gulf Power announced the redemption in September ~~30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional~~2015 of $60 million aggregate principal amount of ~~the swaps totaled $900 million.~~its Series L 5.65% Senior Notes due September 1, 2035.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

3637

Table of Contents

PART I

Item 3. Quantitative ~~And~~and Qualitative Disclosures About Market Risk.

During the ~~nine~~six months ended ~~September~~June 30, ~~2014,~~2015, there were no material changes to each registrant's disclosures about market risk. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power and Mississippi Power, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.


(a)	Evaluation of disclosure controls and procedures.

As of the end of the period covered by this quarterly report, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.


(b)	Changes in internal controls.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the ~~third~~second quarter ~~2014~~2015 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power Company's internal control over financial reporting.

3738

Table of Contents

ALABAMA POWER COMPANY

3839

Table of Contents

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in millions)						(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,512		$	1,438		$	4,058		$	3,800		$	1,326		$	1,249		$	2,594		$	2,546
Wholesale revenues, non-affiliates	72			66			222			186			57			65			123			150
Wholesale revenues, affiliates	31			47			168			163			20			68			35			137
Other revenues	54			53			166			155			52			55			104			112
Total operating revenues	1,669			1,604			4,614			4,304			1,455			1,437			2,856			2,945
Operating Expenses:
Fuel	442			467			1,288			1,240			343			414			653			846
Purchased power, non-affiliates	57			36			153			84			45			39			86			96
Purchased power, affiliates	54			30			140			102			49			37			103			86
Other operations and maintenance	334			316			989			965			370			330			768			655
Depreciation and amortization	174			170			521			487			160			172			318			347
Taxes other than income taxes	88			85			265			262			90			88			184			177
Total operating expenses	1,149			1,104			3,356			3,140			1,057			1,080			2,112			2,207
Operating Income	520			500			1,258			1,164			398			357			744			738
Other Income and (Expense):
Allowance for equity funds used during construction	15			7			36			23			14			11			29			21
Interest expense, net of amounts capitalized	(63		)	(65		)	(188		)	(196		)	(69		)	(63		)	(134		)	(125		)
Other income (expense), net	3			—			(5		)	1			(14		)	(3		)	(18		)	(8		)
Total other income and (expense)	(45		)	(58		)	(157		)	(172		)	(69		)	(55		)	(123		)	(112		)
Earnings Before Income Taxes	475			442			1,101			992			329			302			621			626
Income taxes	183			174			429			390			122			119			235			246
Net Income	292			268			672			602			207			183			386			380
Dividends on Preferred and Preference Stock	10			10			30			30			7			10			17			20
Net Income After Dividends on Preferred and Preference Stock	$	282		$	258		$	642		$	572		$	200		$	173		$	369		$	360

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

For the Three Months
Ended September 30, For the Nine Months
Ended September 30,
2014 2013 2014 2013
(in millions) (in millions)
Net Income $ 292
$ 268
$ 672
$ 602
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $1 and $1, respectively —
—
1
1
Total other comprehensive income (loss) —
—
1
1
Comprehensive Income $ 292
$ 268
$ 673
$ 603

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

~~Table of Contents~~

~~ALABAMA POWER COMPANY~~

~~CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)~~

For the Nine Months
Ended September 30,
2014 2013
(in millions)
Operating Activities:
Net income $ 672
$ 602
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total 631
616
Deferred income taxes 68
200
Allowance for equity funds used during construction (36 ) (23 )
Regulatory deferrals (62 ) (14 )
Other, net 29
15
Changes in certain current assets and liabilities —
-Receivables (139 ) (98 )
-Fossil fuel stock 106
173
-Materials and supplies (8 ) 16
-Other current assets (32 ) (18 )
-Accounts payable (64 ) (109 )
-Accrued taxes 210
105
-Accrued compensation 18
(36 )
-Retail fuel cost over recovery 2
42
-Other current liabilities 3
(2 )
Net cash provided from operating activities 1,398
1,469
Investing Activities:
Property additions (966 ) (779 )
Nuclear decommissioning trust fund purchases (178 ) (162 )
Nuclear decommissioning trust fund sales 178
162
Cost of removal, net of salvage (50 ) (29 )
Change in construction payables 39
12
Other investing activities (26 ) 35
Net cash used for investing activities (1,003 ) (761 )
Financing Activities:
Proceeds —
Senior note issuances 400
—
Capital contributions from parent company 20
18
Payment of preferred and preference stock dividends (30 ) (30 )
Payment of common stock dividends (412 ) (397 )
Other financing activities (6 ) —
Net cash used for financing activities (28 ) (409 )
Net Change in Cash and Cash Equivalents 367
299
Cash and Cash Equivalents at Beginning of Period 295
137
Cash and Cash Equivalents at End of Period $ 662
$ 436
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $13 and $8 capitalized for 2014 and 2013, respectively) $ 174
$ 182
Income taxes, net 227
154
Noncash transactions — accrued property additions at end of period 57
43



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income	$	207	$	183	$	386	$	380
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $3, $-, $- and $-, respectively	5		—		1		—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $-, respectively	—		—		1		1
Total other comprehensive income (loss)	5		—		2		1
Comprehensive Income	$	212	$	183	$	388	$	381

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

Table of Contents

ALABAMA POWER COMPANY

CONDENSED ~~BALANCE SHEETS~~STATEMENTS OF CASH FLOWS (UNAUDITED)

Assets At September 30,
2014 At December 31,
2013
(in millions)
Current Assets:
Cash and cash equivalents $ 662
$ 295
Receivables —
Customer accounts receivable 442
341
Unbilled revenues 133
142
Under recovered regulatory clause revenues 34
—
Other accounts and notes receivable 38
30
Affiliated companies 36
54
Accumulated provision for uncollectible accounts (9 ) (8 )
Fossil fuel stock, at average cost 223
329
Materials and supplies, at average cost 397
375
Vacation pay 63
63
Prepaid expenses 83
57
Other regulatory assets, current 8
7
Other current assets 9
6
Total current assets 2,119
1,691
Property, Plant, and Equipment:
In service 22,688
22,092
Less accumulated provision for depreciation 8,430
8,114
Plant in service, net of depreciation 14,258
13,978
Nuclear fuel, at amortized cost 324
332
Construction work in progress 995
748
Total property, plant, and equipment 15,577
15,058
Other Property and Investments:
Equity investments in unconsolidated subsidiaries 67
54
Nuclear decommissioning trusts, at fair value 738
714
Miscellaneous property and investments 83
80
Total other property and investments 888
848
Deferred Charges and Other Assets:
Deferred charges related to income taxes 528
519
Prepaid pension costs 290
276
Deferred under recovered regulatory clause revenues 46
25
Other regulatory assets, deferred 703
692
Other deferred charges and assets 142
142
Total deferred charges and other assets 1,709
1,654
Total Assets $ 20,293
$ 19,251



	For the Six Months Ended June 30,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	386		$	380
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	387			416
Deferred income taxes	60			49
Allowance for equity funds used during construction	(29		)	(21		)
Other, net	(23		)	(40		)
Changes in certain current assets and liabilities —
-Receivables	(115		)	(120		)
-Fossil fuel stock	19			94
-Materials and supplies	3			(2		)
-Other current assets	(55		)	(57		)
-Accounts payable	(212		)	(94		)
-Accrued taxes	177			104
-Accrued compensation	(66		)	(17		)
-Retail fuel cost over recovery	25			(23		)
-Other current liabilities	40			5
Net cash provided from operating activities	597			674
Investing Activities:
Property additions	(612		)	(637		)
Nuclear decommissioning trust fund purchases	(278		)	(121		)
Nuclear decommissioning trust fund sales	278			121
Cost of removal, net of salvage	(28		)	(30		)
Change in construction payables	28			71
Other investing activities	(14		)	(13		)
Net cash used for investing activities	(626		)	(609		)
Financing Activities:
Increase in notes payable, net	—			27
Proceeds —
Senior notes issuances	975			—
Capital contributions from parent company	10			12
Pollution control revenue bonds	80			—
Redemptions and repurchases —
Preferred and preference stock	(412		)	—
Pollution control revenue bonds	(134		)	—
Senior notes	(250		)	—
Payment of preferred and preference stock dividends	(22		)	(20		)
Payment of common stock dividends	(286		)	(275		)
Other financing activities	(10		)	1
Net cash used for financing activities	(49		)	(255		)
Net Change in Cash and Cash Equivalents	(78		)	(190		)
Cash and Cash Equivalents at Beginning of Period	273			295
Cash and Cash Equivalents at End of Period	$	195		$	105
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $10 and $8 capitalized for 2015 and 2014, respectively)	$	118		$	114
Income taxes, net	47			141
Noncash transactions — Accrued property additions at end of period	35			89

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

Table of Contents

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity At September 30,
2014 At December 31,
2013
(in millions)
Current Liabilities:
Securities due within one year $ 54
$ —
Accounts payable —
Affiliated 245
198
Other 273
339
Customer deposits 86
85
Accrued taxes —
Accrued income taxes 146
11
Other accrued taxes 114
33
Accrued interest 62
61
Accrued vacation pay 53
53
Accrued compensation 98
74
Other regulatory liabilities, current 49
37
Other current liabilities 44
41
Total current liabilities 1,224
932
Long-term Debt 6,577
6,233
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 3,670
3,603
Deferred credits related to income taxes 72
75
Accumulated deferred investment tax credits 127
133
Employee benefit obligations 203
195
Asset retirement obligations 813
730
Other cost of removal obligations 864
828
Other regulatory liabilities, deferred 242
259
Deferred over recovered regulatory clause revenues —
15
Other deferred credits and liabilities 54
61
Total deferred credits and other liabilities 6,045
5,899
Total Liabilities 13,846
13,064
Redeemable Preferred Stock 342
342
Preference Stock 343
343
Common Stockholder's Equity:
Common stock, par value $40 per share —
Authorized — 40,000,000 shares
Outstanding — 30,537,500 shares 1,222
1,222
Paid-in capital 2,292
2,262
Retained earnings 2,273
2,044
Accumulated other comprehensive loss (25 ) (26 )
Total common stockholder's equity 5,762
5,502
Total Liabilities and Stockholder's Equity $ 20,293
$ 19,251



Assets	At June 30, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	195		$	273
Receivables —
Customer accounts receivable	393			345
Unbilled revenues	170			138
Under recovered regulatory clause revenues	28			74
Other accounts and notes receivable	31			23
Affiliated companies	41			37
Accumulated provision for uncollectible accounts	(9		)	(9		)
Fossil fuel stock, at average cost	249			268
Materials and supplies, at average cost	415			406
Vacation pay	65			65
Prepaid expenses	168			244
Other regulatory assets, current	115			84
Other current assets	10			5
Total current assets	1,871			1,953
Property, Plant, and Equipment:
In service	23,812			23,080
Less accumulated provision for depreciation	8,565			8,522
Plant in service, net of depreciation	15,247			14,558
Nuclear fuel, at amortized cost	338			348
Construction work in progress	1,017			1,006
Total property, plant, and equipment	16,602			15,912
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	68			66
Nuclear decommissioning trusts, at fair value	758			756
Miscellaneous property and investments	88			84
Total other property and investments	914			906
Deferred Charges and Other Assets:
Deferred charges related to income taxes	526			525
Deferred under recovered regulatory clause revenues	97			31
Other regulatory assets, deferred	1,054			1,063
Other deferred charges and assets	156			162
Total deferred charges and other assets	1,833			1,781
Total Assets	$	21,220		$	20,552

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

Table of Contents

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	600		$	454
Accounts payable —
Affiliated	244			248
Other	267			443
Customer deposits	88			87
Accrued taxes —
Accrued income taxes	3			2
Other accrued taxes	88			37
Accrued interest	75			66
Accrued vacation pay	54			54
Accrued compensation	66			131
Other current liabilities	105			82
Total current liabilities	1,590			1,604
Long-term Debt	6,699			6,176
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,937			3,874
Deferred credits related to income taxes	71			72
Accumulated deferred investment tax credits	121			125
Employee benefit obligations	308			326
Asset retirement obligations	1,252			829
Other cost of removal obligations	742			744
Other regulatory liabilities, deferred	219			239
Deferred over recovered regulatory clause revenues	72			47
Other deferred credits and liabilities	79			79
Total deferred credits and other liabilities	6,801			6,335
Total Liabilities	15,090			14,115
Redeemable Preferred Stock	85			342
Preference Stock	196			343
Common Stockholder's Equity:
Common stock, par value $40 per share —
Authorized — 40,000,000 shares
Outstanding — 30,537,500 shares	1,222			1,222
Paid-in capital	2,324			2,304
Retained earnings	2,331			2,255
Accumulated other comprehensive loss	(28		)	(29		)
Total common stockholder's equity	5,849			5,752
Total Liabilities and Stockholder's Equity	$	21,220		$	20,552

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

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~~THIRD~~SECOND QUARTER ~~2014~~2015 vs. ~~THIRD~~SECOND QUARTER ~~2013~~2014

AND

YEAR-TO-DATE ~~2014~~2015 vs. YEAR-TO-DATE ~~2013~~2014

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located within the State of Alabama in addition to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Alabama Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, ~~given economic conditions,~~ and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.

Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Alabama Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013
Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change)
(change in millions)
(% change)
$24 9.3 $70 12.2

Alabama Power's net income after dividends on preferred and preference stock for the ~~third~~second quarter ~~2014~~2015 was ~~$282~~$200 million compared to ~~$258~~$173 million for the corresponding period in ~~2013.~~2014. The increase ~~in net income~~ was primarily related to an increase in ~~revenue primarily due to~~rates under rate stabilization and equalization (Rate RSE) effective January 1, 2015, warmer weather in the ~~third~~second quarter ~~2014 as~~2015 compared to the corresponding period in ~~2013~~2014, and a decrease in depreciation, partially offset by an increase in ~~AFUDC equity, partially offset by increases in operating~~non-fuel operations and maintenance expenses.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date ~~2014~~2015 was ~~$642~~$369 million compared to ~~$572~~$360 million for the corresponding period in ~~2013.~~2014. The increase ~~in net income~~ was primarily related to an increase under Rate RSE and a decrease in ~~revenue primarily due to colder weather in the first quarter 2014 and warmer weather in the second and third quarters of 2014 as compared to the corresponding periods in 2013 and~~depreciation, partially offset by an increase in ~~AFUDC equity, partially offset by increases in operating~~non-fuel operations and maintenance expenses.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$74 5.1 $258 6.8

In the ~~third~~second quarter ~~2014,~~2015, retail revenues were ~~$1.51~~$1.33 billion compared to ~~$1.44~~$1.25 billion for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, retail revenues were ~~$4.06~~$2.59 billion compared to ~~$3.80~~$2.55 billion for the corresponding period in ~~2013.~~2014.

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Details of the changes in retail revenues were as follows:


	Third Quarter 2014				Year-to-Date 2014				Second Quarter 2015				Year-to-Date 2015
	(in millions)		(% change)		(in millions)		(% change)		(in millions)		(% change)		(in millions)			(% change)
Retail – prior year	$	1,438			$	3,800			$	1,249			$	2,546
Estimated change resulting from –
Rates and pricing	8		0.5		45		1.2		56		4.5		103			4.1
Sales growth	6		0.4		2		0.1		1		0.1		10			0.4
Weather	32		2.2		91		2.4		18		1.5		(2		)	(0.1	)
Fuel and other cost recovery	28		2.0		120		3.1		2		0.1		(63		)	(2.5	)
Retail – current year	$	1,512	5.1	%	$	4,058	6.8	%	$	1,326	6.2	%	$	2,594		1.9	%

Revenues associated with changes in rates and pricing increased in the ~~third~~second quarter 2015 and year-to-date ~~2014~~2015 when compared to the corresponding periods in ~~2013~~2014 primarily due to ~~increased revenues associated with~~a Rate ~~CNP Environmental primarily resulting from~~RSE increase effective January 1, 2015. See Note 3 to the ~~inclusion of pre-2005 environmental assets. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate CNP"~~financial statements of Alabama Power under "Retail Regulatory Matters" in Item 78 of the Form 10-K for additional ~~information regarding the revision to Rate CNP Environmental.~~information.

Revenues attributable to changes in sales ~~increased~~remained relatively flat in the ~~third~~second quarter 2015 and increased slightly year-to-date ~~2014~~2015 when compared to the corresponding periods in ~~2013.~~2014. Industrial KWH energy sales slightly increased ~~6.5% in the third quarter and 4.3% for~~0.2% year-to-date ~~2014~~2015 as a result of an increase in demand resulting from changes in production levels primarily in the ~~primary metals, chemicals, forest products, automotive and plastics, and~~pipelines, stone, clay, and glass, automotive, and plastics sectors, offset by a decrease in demand in the primary metals and forest products sectors. Weather-adjusted residential ~~KWH energy sales decreased 1.7% in the third quarter~~ and ~~1.1% for year-to-date 2014 as a result of decreased customer usage. Weather-adjusted~~ commercial KWH energy sales ~~decreased 2.1% in the third quarter and 1.2%~~were relatively flat for year-to-date ~~2014 as a result of decreased customer usage. Household income, one of the primary drivers of residential customer usage, has been flat in 2014.~~2015.

Revenues resulting from changes in weather increased in the ~~third~~second quarter ~~2014~~2015 due to warmer weather experienced in Alabama Power's service territory in the second quarter 2015 as compared to the corresponding period in ~~2013.~~2014. For the ~~third~~second quarter ~~2014,~~2015, the resulting increases were ~~3.8%~~2.6% and ~~1.9%~~1.5% for residential and commercial sales ~~revenue,~~revenues, respectively.

Revenues resulting from changes in weather ~~increased~~remained relatively flat year-to-date ~~2014~~2015 primarily due to ~~colder~~milder weather experienced in Alabama Power's service territory in the first quarter ~~2014 and~~2015 offset by warmer weather in the second ~~and third quarters 2014 when~~quarter 2015 as compared to the corresponding periods in ~~2013. For year-to-date 2014, the resulting increases were 4.1% and 2.2% for residential and commercial sales revenue, respectively.~~2014.

Fuel and other cost recovery revenues increased in the ~~third~~second quarter ~~and year-to-date 2014~~2015 when compared to the corresponding ~~periods~~period in ~~2013~~2014 primarily due to an increase in ~~fuel costs associated with an increase~~purchased power partially offset by a decrease in the average cost of fuel. Fuel and other cost recovery revenues decreased year-to-date 2015 when compared to the corresponding period in 2014 primarily due to a decrease in KWH generation and a decrease in the average cost of ~~natural gas.~~ fuel.

Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the ~~Natural Disaster Reserve.~~natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income.

Wholesale Revenues – Non-Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$6 9.1 $36 19.4

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of ~~available~~ wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by

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~~system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by~~ an increase or decrease in fuel costs and do not have a significant impact on net income.

In the ~~third~~second quarter ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$72~~$57 million compared to ~~$66~~$65 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to ~~an 11.2% increase~~a 12.0% decrease in KWH ~~sales primarily due to the availability of Alabama Power's lower cost generation partially offset by a 2.3% decrease in the price of energy primarily due to the lower cost of coal.~~

sales. For year-to-date ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$222~~$123 million compared to ~~$186~~$150 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~16.4% increase~~10.3% decrease in KWH sales ~~primarily due to the availability of Alabama Power's lower cost generation~~ and an ~~increase of 2.2%~~8.7% decrease in the price of ~~energy primarily~~energy.

In 2014, Alabama Power's fuel diversity led to increased sales to non-affiliates due to higher natural gas prices. In 2015, lower natural gas prices ~~during the winter months~~and decreased availability of ~~2014.~~hydro generation, due to less rainfall, resulted in lower sales of Alabama Power's generation to non-affiliates.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$(16) (34.0) $5 3.1

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 ~~third~~second quarter ~~2014,~~2015, wholesale revenues from sales to affiliates were ~~$31~~$20 million compared to ~~$47~~$68 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to a ~~38.8%~~57.4% decrease in KWH sales and a 31.1% decrease in the price of energy. For year-to-date 2015, wholesale revenues from sales to affiliates were $35 million compared to $137 million for the corresponding period in 2014. The decrease was primarily due to a 63.0% decrease in KWH sales and a 31.4% decrease in the price of energy.

In 2014, Alabama Power's fuel diversity led to increased sales to affiliates due to higher natural gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation, due to less rainfall, resulted in ~~the third quarter 2014 as compared~~lower sales of Alabama Power's generation to the corresponding period in 2013 as well as the addition of new generation in the Southern Company system. This decrease was partially offset by a 4.1% increase in the price of energy primarily due to higher natural gas prices.

~~Other Revenues~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1 1.9 $11 7.1

For year-to-date 2014, other revenues were $166 million compared to $155 million for the corresponding period in 2013. The increase was primarily due to increases in co-generation steam revenues, open access transmission tariff revenues, and transmission service agreement revenues.affiliates.

Fuel and Purchased Power Expenses


	Third Quarter 2014 vs. Third Quarter 2013				Year-to-Date 2014 vs. Year-to-Date 2013			Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)		(% change)	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(25	)	(5.4)	$	48	3.9	$	(71	)	(17.1)	$	(193	)	(22.8	)
Purchased power – non-affiliates	21			58.3	69		82.1	6			15.4	(10		)	(10.4	)
Purchased power – affiliates	24			80.0	38		37.3	12			32.4	17			19.8
Total fuel and purchased power expenses	$	20			$	155		$	(53	)		$	(186	)

In the ~~third~~second quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$553~~$437 million compared to ~~$533~~$490 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~$42~~$52 million decrease in the average cost of fuel, an $18 million decrease related to the volume of KWHs generated, and a $7 million decrease in the average cost of purchased power, partially offset by a $24 million increase in the volume of KWHs purchased.

For year-to-date 2015, fuel and purchased power expenses were $842 million compared to $1.03 billion for the corresponding period in 2014. The decrease was primarily due to a $120 million decrease in the average cost of fuel, a $72 million decrease related to the volume of KWHs generated, and a $44 million decrease in the average cost of purchased power, partially offset by a $50 million increase in the volume of KWHs purchased.

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purchased, a $6 million increase related to the volume of KWHs generated, and a $3 million increase in the average cost of purchased power, partially offset by a $31 million decrease in the average cost of fuel.

For year-to-date 2014, total fuel and purchased power expenses were $1.58 billion compared to $1.43 billion for the corresponding period in 2013. The increase was primarily due to a $65 million increase related to the volume of KWHs purchased, a $48 million increase in the volume of KWHs generated, and a $42 million increase in the average cost of purchased power.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery ~~clauses.~~clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to ~~billings~~billing rates are required. See ~~FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Energy Cost Recovery"~~Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 78 of the Form 10-K for additional information.

Details of Alabama Power's generation and purchased power were as follows:


	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013	Second Quarter 2015	Second Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (billions of KWHs)	17	18	50	49	15	16	29	33
Total purchased power (billions of KWHs)	2	1	5	3	2	1	4	3
Sources of generation (percent) —
Coal	59	57	55	53	59	53	53	53
Nuclear	23	21	23	22	20	24	23	23
Gas	16	16	16	16	15	16	17	16
Hydro	2	6	6	9	6	7	7	8
Cost of fuel, generated (cents per net KWH) —
Coal	3.04	3.41	3.24	3.37	2.89	3.30	2.89	3.35
Nuclear	0.81	0.84	0.84	0.83	0.82	0.85	0.81	0.86
Gas	3.54	3.27	3.83	3.38	3.10	3.80	3.06	3.99
Average cost of fuel, generated (cents per net KWH)^(a)	2.61	2.80	2.75	2.76	2.50	2.76	2.41	2.83
Average cost of purchased power (cents per net KWH)^(b)	6.56	6.44	6.32	5.44	5.48	5.88	5.00	6.18


(a)	KWHs generated by hydro are excluded from the average cost of fuel, generated.


(b)	Average cost of purchased power includes fuel purchased by Alabama Power for tolling agreements where power is generated by the provider.

Fuel

In the ~~third~~second quarter ~~2014,~~2015, fuel expense was ~~$442~~$343 million compared to ~~$467~~$414 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to ~~a 10.8%~~an 18.4% decrease in the average cost of coal generation. This was partially offset by a 66.7% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall and an 8.3% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.

For year-to-date 2014, fuel expense was $1.29 billion compared to $1.24 billion for the corresponding period in 2013. The increase was primarily due to a 32.9% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall, a 13.3% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a ~~6.9% increase in KWHs generated by nuclear fuel due to an outage in the second quarter 2013, and a 5.3% increase~~14.6% decrease in the volume of KWHs generated by natural gas, and a 12.3% decrease in the average cost of coal per KWH generated. The decrease was partially offset by a 21.4% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall.

For year-to-date 2015, fuel expense was $653 million compared to $846 million for the corresponding period in 2014. The decrease was primarily due to a 23.3% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 13.7% decrease in the average cost of coal per KWH generated, and a 9.6% decrease in the volume of KWHs generated by coal. The decrease was partially offset by a 22.1% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall.

Purchased Power – Non-Affiliates

In the second quarter 2015, purchased power expense from non-affiliates was $45 million compared to $39 million for the corresponding period in 2014. The increase was related to a 20.7% increase in the amount of energy purchased due to the availability of lower cost generation resulting from lower natural gas prices, decreased availability of hydro generation as a result of less rainfall, and increased customer demand due to warmer weather in the second quarter 2015 as compared to the corresponding period during 2014. The increase was partially offset by a 5.7% decrease in the average cost per KWH purchased as a result of lower natural gas prices.

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~~Purchased Power – Non-Affiliates~~

~~In the third quarter 2014,~~For year-to-date 2015, purchased power expense from non-affiliates was ~~$57~~$86 million compared to ~~$36~~$96 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was related to a ~~48.3% increase~~21.9% decrease in the average cost per KWH purchased ~~and~~as a ~~3.4%~~result of lower natural gas prices partially offset by a 13.6% increase in the amount of energy purchased due to the ~~addition~~availability of lower cost generation as a ~~new PPA in 2014.~~

For year-to-date 2014, purchased power expense from non-affiliates was $153 million compared to $84 million for the corresponding period in 2013. The increase was related to a 65.9% increase in the average cost per KWH purchased primarily due to demand during peak periods and the additionresult of ~~a new PPA in 2014 and a 7.2% increase in the volume of KWHs purchased to meet the demand created by colder weather in the first quarter 2014 compared to the corresponding period in 2013.~~lower natural gas prices.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

In the ~~third~~second quarter ~~2014,~~2015, purchased power expense from affiliates was ~~$54~~$49 million compared to ~~$30~~$37 million for the corresponding period in ~~2013.~~2014. The increase was related to a ~~130.0%~~45.2% increase in the amount of energy purchased primarily due to the availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation ~~due to~~as a result of less ~~rainfall during the third quarter 2014 compared to the corresponding period in 2013 as well as the addition of new capacity in the Southern Company system during the third quarter 2014. This~~rainfall. The increase was partially offset by a ~~23.6%~~7.0% decrease in the average cost per KWH purchased due to ~~availability of~~ lower ~~cost Southern Company system generation at the time of purchase.~~natural gas prices.

For year-to-date ~~2014,~~2015, purchased power expense from affiliates was ~~$140~~$103 million compared to ~~$102~~$86 million for the corresponding period in ~~2013.~~2014. The increase was related to a ~~63.1%~~39.5% increase in the ~~volume~~amount of ~~KWHs~~energy purchased ~~to meet the demand created by colder weather in the first quarter 2014 compared~~primarily due to the ~~corresponding period in 2013~~availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation as a result of less rainfall. The increase was partially offset by a ~~16.5%~~14.2% decrease in the average cost per KWH purchased due to ~~the availability of~~ lower ~~cost Southern Company system generation at the time of purchase.~~natural gas prices.

Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$18 5.7 $24 2.5

In the ~~third~~second quarter ~~2014,~~2015, other operations and maintenance expenses were ~~$334~~$370 million compared to ~~$316~~$330 million for the corresponding period in ~~2013. For year-to-date 2014, other operations and maintenance expenses were $989 million compared to $965 million for the corresponding period in 2013.~~2014. The ~~increases were~~increase was primarily due to ~~increases in labor and contract labor costs. These increases were partially offset by~~ the implementation of an accounting order in 2014 allowing the deferral of non-nuclear outage costs. Alabama Power deferred approximately $16 million of non-nuclear outage expenditures in the second quarter 2014. In addition, employee benefits including pension costs increased $11 million and ~~$57~~steam generation costs increased $5 million primarily due to non-outage and maintenance costs.

For year-to-date 2015, other operations and maintenance expenses were $768 million compared to $655 million for the corresponding period in 2014. Alabama Power deferred approximately $41 million of non-nuclear outage expenditures in the ~~third quarter~~first half of 2014. In addition, steam generation costs increased $28 million primarily due to scheduled outage costs and ~~year-to-date 2014, respectively.~~ employee benefits including pension costs increased $21 million.

See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Non-Nuclear Outage Accounting Order"~~Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Cost of Removal Accounting Order" in Item 78 of the Form 10-K for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

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Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$4 2.4 $34 7.0

~~For year-to-date 2014,~~In the second quarter 2015, depreciation and amortization was ~~$521~~$160 million compared to ~~$487~~$172 million for the corresponding period in ~~2013. The increase~~2014. For year-to-date 2015, depreciation and amortization was $318 million compared to $347 million for the corresponding period in 2014. These decreases were primarily due to ~~an increase~~a decrease in depreciation rates related to environmental, steam generation, transmission, and distribution assets ~~and~~effective January 1, 2015, as authorized by the ~~deferral in 2013 of certain costs under an accounting order. Depreciation related to environmental assets is~~FERC, partially offset by ~~revenues associated with Rate CNP Environmental. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate CNP" of Alabama Power~~increases in Item 7 of the Form 10-K for additional information regarding Alabama Power's revision to Rate CNP Environmental. See also MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Compliance and Pension Cost Accounting Order" of Alabama Powerplant in ~~Item 7 of the Form 10-K for additional information regarding Alabama Power's deferral of costs under this accounting order.~~service.

Allowance for Equity Funds Used During Construction

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$8 114.3 $13 56.5

In the ~~third~~second quarter ~~2014,~~2015, AFUDC equity was ~~$15~~$14 million compared to $7$11 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, AFUDC equity was ~~$36~~$29 million compared to ~~$23~~$21 million for the corresponding period in ~~2013. The~~2014. These increases were primarily due to additional capital expenditures for steam power environmental ~~and steam generation. Also contributing to the third quarter increase was an increase in capital expenditures for nuclear fuel.~~projects.

~~Income Taxes~~

Interest Expense, Net of Amounts Capitalized

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$9 5.2 $39 10.0

In the ~~third~~second quarter ~~2014, income taxes were $183~~2015, interest expense, net of amounts capitalized was $69 million compared to ~~$174~~$63 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014, income taxes were $429~~2015, interest expense, net of amounts capitalized was $134 million compared to ~~$390~~$125 million for the corresponding period in ~~2013. The~~2014. These increases were primarily due to new debt issuances, which include issuances to redeem long-term debt, preferred stock, and preference stock.

Other Income (Expense), Net

N/M - Not meaningful

In the second quarter 2015, other income (expense), net was $(14) million compared to $(3) million for the corresponding period in 2014. For year-to-date 2015, other income (expense), net was $(18) million compared to $(8) million for the corresponding period in 2014. The changes were primarily due to increases in donations.

Income Taxes

In the second quarter 2015, income taxes were $122 million compared to $119 million for the corresponding period in 2014. The increase was primarily due to higher pre-tax ~~earnings.~~earnings, partially offset by state income tax credits.

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For year-to-date 2015, income taxes were $235 million compared to $246 million for the corresponding period in 2014. The decrease was primarily due to state income tax credits in the second quarter 2015.

FUTURE EARNINGS POTENTIAL

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

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~~ALABAMA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

New Source Review Actions

See Note 3 to the financial statements of Alabama Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and – ~~"PSC~~"Retail Regulatory Matters – Environmental Accounting Order" of Alabama Power in Item 7 of the Form 10-K and ~~"PSC~~"Retail Regulatory Matters – Environmental Accounting Order" herein for additional information regarding Alabama Power's plan for compliance with environmental statutes and regulations.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR) ~~and~~.

On June 12, 2015, the ~~EPA's proposed rules~~EPA published a final rule requiring affected states (including Alabama) to revise or remove state implementation plan (SIP) provisions regarding ~~the regulation of~~ excess emissions that occur during periods of ~~startup, shutdown, or malfunction (SSM).~~SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.

On ~~April~~June 29, ~~2014,~~2015, the U.S. Supreme Court ~~overturned~~issued a decision finding that the ~~U.S. Court of Appeals for the District of Columbia Circuit's August 2012~~EPA had failed to properly consider costs in its decision to ~~vacate CSAPR~~regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case ~~back~~ to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. ~~On October 23, 2014,~~The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit ~~granted the EPA's motion to lift the stay on CSAPR implementation~~ and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA ~~and the states implement the final rule, and the development of related emissions allowance markets.~~

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subjectrespond to the ~~rule, including Alabama, to revise their SSM provisions within 18 months after issuance of the final rule.~~decision. The ultimate impact of ~~the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and~~this decision cannot be determined at this time.

On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate ~~outcome~~impact of ~~these matters~~this decision will depend on additional rulemaking and cannot be determined at this time.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).

On ~~April 21, 2014,~~June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a ~~proposed~~final rule ~~to revise~~revising the regulatory definition of waters of the U.S. for all ~~Clean Water Act (CWA) programs,~~CWA programs. The final rule significantly ~~expanding~~expands the scope of federal jurisdiction under the ~~CWA. If finalized as proposed,~~CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. ~~In addition,~~The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as ~~proposed could have significant impacts on economic development projects which could affect customer demand growth.~~the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Alabama Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Alabama Power recorded incremental asset retirement obligations (ARO) of approximately $401 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Alabama Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's AROs.

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~~impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.~~Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – ~~Environmental Statutes and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.~~

On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

~~Global Climate Issues~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters –~~ Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's ~~current and~~ proposed regulation of ~~GHG emissions under the Clean Air Act.~~CO₂ from fossil-fuel-fired electric generating units.

On ~~June 18, 2014,~~August 3, 2015, the EPA ~~published~~released pre-publication versions of two final rules that would limit CO₂ emissions from fossil fuel-fired electric generating units. One of the ~~proposed Clean Power Plan, setting forth~~final rules contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to ~~address CO~~₂ ~~emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final~~meet EPA-mandated CO₂ emission ~~rate goals~~rates for existing units. The EPA's final guidelines require state plans to ~~be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposed~~meet interim CO₂ performance ~~standards for modified~~rates between 2022 and ~~reconstructed fossil fuel-fired electric generating units. The~~2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, ~~that~~which could ~~impact~~affect future unit retirement and replacement decisions. ~~Also, additional compliance costs could affect~~Alabama Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated ~~rates. Further, any resulting higher costs that are recovered~~rates or through ~~regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.~~

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system.market-based contracts. However, the ultimate financial and operational impact of the ~~Clean~~final rules on Alabama Power ~~Plan proposed guidelines on the Southern Company system~~ cannot be determined at this time and will ~~be dependent upon~~depend on numerous ~~factors. These~~ factors ~~include:~~including the ~~structure, timing, and content~~Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final ~~guidelines; individual state implementation of these~~ guidelines, including the potential that state ~~implementation~~ plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and ~~emissions-related~~emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

FERC Matters

Alabama Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Alabama Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On ~~June 23, 2014,~~April 27, 2015, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit andFERC issued an order finding that the ~~EPA did~~traditional operating companies' (including Alabama Power's) and Southern Power's existing tailored mitigation may not ~~have~~effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Alabama Power) and Southern Power to ~~tailor~~show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including Alabama Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the ~~statutory permitting thresholds.~~FERC. The ultimate ~~impact~~outcome of ~~the U.S. Supreme Court's decision~~this matter cannot be determined at this time.

See REGULATION – "Federal Power Act" of Alabama Power in Item 1 of the Form 10-K for additional information regarding Alabama Power's Warrior River Project license.

On January 30, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an order denying Smith Lake Improvement and Stakeholders Association's (SLISA) petition for en banc review of the court's dismissal of SLISA's appeal of the new Warrior River Project license. SLISA did not appeal this decision; therefore, this matter is now concluded and the FERC license is authorized as issued.

Retail Regulatory Matters

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business

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~~FERC Matters~~

primarily through its Rate RSE, Rate CNP, rate energy cost recovery, and natural disaster reserve rate. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters"~~Note 1 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and Note 3 under "Retail Regulatory Matters" in Item 7 of the Form 10-K for additional information on Alabama Power's relicensing applications for the hydroelectric developments on the Coosa River and the Warrior River. On September 26, 2014, the U.S. Court of Appeals for the District of Columbia Circuit dismissed the appeal of the Smith Lake Improvement and Stakeholders' Association from the FERC's orders related to the Warrior River relicensing proceedings for lack of jurisdiction. The ultimate outcome of this matter cannot be determined at this time.

~~PSC Matters~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters" of Alabama Power in Item 7~~8 of the Form 10-K for additional information regarding Alabama Power's ~~recovery of retail costs through various regulatory clauses~~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.

~~Environmental Accounting Order~~Rate CNP

See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and – "PSC Matters – Environmental Accounting Order"~~Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 78 of the Form 10-K for additional information regarding Alabama Power's ~~plan~~development of a revised cost recovery mechanism and the normal purchases and normal sales (NPNS) exception for wind PPAs.

Environmental Accounting Order

~~Nuclear Waste Fund Accounting Order~~Renewable Energy

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of~~On June 25, 2015, Alabama Power ~~in Item 7 of the Form 10-K and "Other Matters" herein for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero.~~

~~On August 5, 2014,~~filed a petition with the Alabama PSC ~~issued an order to provide~~ for ~~the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014,~~a Renewable Generation Certificate (RGC). The RGC would develop a process that allows Alabama Power to build its own renewable projects each less than 80 MWs or purchase power from other renewable-generated sources up to 500 MWs. The Alabama PSC is ~~authorized~~expected to ~~recover from customers an amount equal to the prior fee and to record the amounts~~rule on this matter in a regulatory liability account (approximately $14 million annually). Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customers subject to the approval of the Alabama PSC.August 2015. The ultimate outcome of this matter cannot be determined at this time.

~~Cost of Removal Accounting Order~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters" of Alabama Power in Item 7 of the Form 10-K regarding the previously approved compliance and pension costs accounting order and non-nuclear outage accounting order.

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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 ~~increased generally~~occurred throughout the U.S. ~~In particular, personal injury, property damage, and other~~This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, ~~coal combustion residuals,~~CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such ~~matters, have become more frequent.~~matters.

The ultimate outcome of such pending or potential litigation against Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Alabama Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See ~~the Notes~~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.

Additionally, there are certain risks associated with the operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. See "PSC Matters – Nuclear Waste Fund Accounting Order" herein for information regarding an accounting order issued by the Alabama PSC which provides for continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley.~~The ultimate outcome of this matter cannot be determined at this time.~~

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~~ALABAMA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Pension and Other Postretirement Benefits.

Asset Retirement Obligations

The liability for AROs primarily relates to the decommissioning of Alabama Power's nuclear facility, Plant Farley, and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Alabama Power has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. Alabama Power also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Alabama Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Alabama Power considers the liabilities for AROs to be critical accounting estimates.

See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Recently Issued Accounting Standards

~~On May 28, 2014, the Financial Accounting Standards Board issued~~The FASB's ASC 606, Revenue from Contracts with Customers~~. ASC 606~~, revises the accounting for revenue recognition ~~and is~~ effective for fiscal years beginning after December 15, ~~2016.~~2017. Alabama Power ~~is currently evaluating~~continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Alabama Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Alabama Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at ~~September~~June 30, ~~2014.~~2015. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled ~~$1.4 billion~~$597 million for the first ~~nine~~six months of ~~2014,~~2015, a decrease of ~~$71~~$77 million as compared to the first ~~nine~~six months of ~~2013.~~2014. The decrease in net cash provided from operating activities was primarily due to ~~an increase in income tax payments and changes in~~ the timing of fossil fuel stock purchases ~~as compared to~~and payments of accounts payable, partially offset by the ~~first nine months~~timing of ~~2013.~~income tax payments and refunds associated with bonus depreciation. Net cash used for investing activities totaled ~~$1.0 billion~~$626 million for the first ~~nine~~six months of ~~2014~~2015 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash used for financing activities totaled ~~$28~~$49 million for the first ~~nine~~six months of ~~2014~~2015 primarily due to the ~~payment~~redemptions and repurchases of ~~common~~long-term debt and preferred and preference stock and payments of common stock dividends, partially offset by ~~the issuance~~issuances of long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first ~~nine~~six months of ~~2014~~2015 include ~~an increase~~increases of ~~$519~~$690 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, and steam generation ~~$367~~and $423 million in ~~cash and cash equivalents, $344~~AROs associated with the CCR Rule. See Note (A) to the Condensed Financial Statements herein for additional information related to AROs. Other significant changes include decreases of $404 million in ~~long-term debt primarily~~redeemable preferred and preference stock due to redemptions in the ~~issuance of additional senior notes, and $135 million in accrued income taxes.~~second quarter 2015.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately ~~$54~~$600 million will be required through ~~September~~June 30, ~~2015~~2016 to fund maturities of long-term debt.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past. Alabama Power has primarily utilized funds from operating cash flows, short-term debt, security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.

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

At ~~September~~June 30, ~~2014,~~2015, Alabama Power had approximately ~~$662~~$195 million of cash and cash equivalents. Committed credit arrangements with banks at ~~September~~June 30, ~~2014~~2015 were as follows:


Expires^(a)	Expires^(a)											Executable Term Loans				Due Within One Year				Expires^(a)											Executable Term Loans				Due Within One Year
2014		2015		2016		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
2015																				2015	2016		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)	(in millions)							(in millions)				(in millions)				(in millions)				(in millions)					(in millions)				(in millions)				(in millions)
$	70	$	158	$	50	$	1,030	$	1,308	$	1,308	$	58	$	—	$	58	$	170	154	$	124	$	1,030	$	1,308	$	1,307	$	58	$	—	$	58	$	170


~~(a)~~	~~No credit arrangements expire in 2017.~~

See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $810 million. In addition, at June 30, 2015, Alabama Power had $200 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness or guarantee obligations over a specified threshold. Alabama Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

In addition, Alabama Power has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's variable rate pollution control revenue bonds and commercial paper borrowings. As of September 30, 2014, Alabama Power had $784 million of outstanding variable rate pollution control revenue bonds requiring liquidity support. In addition, at September 30, 2014, Alabama Power

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~~had $280 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.~~

Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:

Short-term Debt at
September 30, 2014

Short-term Debt During the Period^(a)

Amount
Outstanding

Weighted
Average
Interest
Rate

Average
Outstanding

Weighted
Average
Interest
Rate

Maximum
Amount
Outstanding
(in millions) (in millions) (in millions)
Commercial Paper $ —
—% $ 27
0.1% $ 300



	Short-term Debt at June 30, 2015			Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial Paper	$	—	—%	$	17	0.2%	$	100


~~(a)~~(*)	Average and maximum amounts are based upon daily balances during the three-month period ended ~~September~~June 30, ~~2014.~~2015.

~~Management~~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 ~~cash.~~operating cash flows.

Credit Rating Risk

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to ~~below~~ BBB- and/or ~~Baa3.~~Baa3 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At ~~September~~June 30, ~~2014, the maximum~~2015, potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 were immaterial. The maximum collateral requirements at a rating below BBB- and/or Baa3 were approximately ~~$343~~$367 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. ~~Additionally, any credit rating downgrade could impact Alabama Power's ability~~

Subsequent to ~~access capital markets, particularly the short-term debt market~~June 30, 2015, S&P placed its ratings of Southern Company and the ~~variable rate pollution control revenue bond market.~~traditional operating companies (including Alabama Power) on CreditWatch with negative implications.

Financing Activities

In ~~August 2014,~~March 2015, Alabama Power issued ~~$400~~$550 million aggregate principal amount of Series ~~2014A 4.150%~~2015A 3.750% Senior Notes due ~~August~~March 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, ~~2044. The~~2035 and for general corporate purposes, including Alabama Power's continuous construction program.

Table of Contents

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In April 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power reoffered these bonds to the public in May 2015.

Also in April 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used to redeem in May 2015 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for general corporate purposes, including Alabama Power's continuous construction ~~program~~.program.

~~Subsequent to September 30, 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional~~In June 2015, $18.7 million aggregate principal amount of the ~~swaps totaled $100 million.~~Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1994, $6.15 million aggregate principal amount of the Industrial Development Board of the City of Gadsden, Pollution Control Revenue Bonds (Alabama Power Company Project), Series 1994, and $28.85 million aggregate principal amount of the Industrial Development Board of the Town of Parrish, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1994A were repaid at maturity.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

5558

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GEORGIA POWER COMPANY

5659

Table of Contents

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in millions)						(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	2,452		$	2,314		$	6,502		$	5,922		$	1,872		$	2,000		$	3,686		$	4,050
Wholesale revenues, non-affiliates	80			77			269			212			50			80			118			189
Wholesale revenues, affiliates	7			3			38			14			4			10			12			31
Other revenues	92			90			277			260			90			96			178			185
Total operating revenues	2,631			2,484			7,086			6,408			2,016			2,186			3,994			4,455
Operating Expenses:
Fuel	684			691			2,055			1,767			503			619			1,029			1,371
Purchased power, non-affiliates	77			64			219			175			78			63			138			142
Purchased power, affiliates	172			152			522			503			115			166			263			350
Other operations and maintenance	456			402			1,334			1,230			467			451			943			878
Depreciation and amortization	211			201			628			605			202			209			418			417
Taxes other than income taxes	111			102			320			292			97			106			195			209
Total operating expenses	1,711			1,612			5,078			4,572			1,462			1,614			2,986			3,367
Operating Income	920			872			2,008			1,836			554			572			1,008			1,088
Other Income and (Expense):
Allowance for equity funds used during construction	13			11			29			24
Interest expense, net of amounts capitalized	(88		)	(92		)	(262		)	(279		)	(93		)	(90		)	(182		)	(174		)
Other income (expense), net	1			(1		)	—			(2		)	1			11			16			15
Total other income and (expense)	(74		)	(82		)	(233		)	(257		)	(92		)	(79		)	(166		)	(159		)
Earnings Before Income Taxes	846			790			1,775			1,579			462			493			842			929
Income taxes	317			299			660			600			180			177			320			343
Net Income	529			491			1,115			979			282			316			522			586
Dividends on Preferred and Preference Stock	4			4			13			13			5			5			9			9
Net Income After Dividends on Preferred and Preference Stock	$	525		$	487		$	1,102		$	966		$	277		$	311		$	513		$	577

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

For the Three Months
Ended September 30, For the Nine Months
Ended September 30,
2014 2013 2014 2013
(in millions) (in millions)
Net Income $ 529
$ 491
$ 1,115
$ 979
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in
net income, net of tax of $1, $-, $1 and $1, respectively —
1
1
2
Total other comprehensive income (loss) —
1
1
2
Comprehensive Income $ 529
$ 492
$ 1,116
$ 981

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

~~Table of Contents~~

~~GEORGIA POWER COMPANY~~

~~CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)~~

For the Nine Months
Ended September 30,
2014 2013
(in millions)
Operating Activities:
Net income $ 1,115
$ 979
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total 757
734
Deferred income taxes 121
354
Allowance for equity funds used during construction (29 ) (24 )
Retail fuel cost over recovery — long-term (44 ) (123 )
Deferred expenses (35 ) (34 )
Pension, postretirement, and other employee benefits 28
58
Other, net 23
28
Changes in certain current assets and liabilities —
-Receivables (377 ) (191 )
-Fossil fuel stock 337
213
-Prepaid income taxes 19
11
-Other current assets (24 ) 38
-Accrued taxes 148
131
-Other current liabilities 29
(46 )
Net cash provided from operating activities 2,068
2,128
Investing Activities:
Property additions (1,364 ) (1,165 )
Investment of restricted cash —
(89 )
Distribution of restricted cash —
89
Nuclear decommissioning trust fund purchases (457 ) (582 )
Nuclear decommissioning trust fund sales 455
580
Cost of removal, net of salvage (39 ) (42 )
Change in construction payables, net of joint owner portion 16
(28 )
Prepaid long-term service agreements (66 ) (14 )
Other investing activities (3 ) —
Net cash used for investing activities (1,458 ) (1,251 )
Financing Activities:
Increase (decrease) in notes payable, net (836 ) 211
Proceeds —
Capital contributions from parent company 39
30
Pollution control revenue bonds issuances 40
89
Senior notes issuances —
850
FFB loan 1,000
—
Redemptions —
Pollution control revenue bonds (37 ) (89 )
Senior notes —
(1,250 )
Payment of preferred and preference stock dividends (13 ) (13 )
Payment of common stock dividends (715 ) (680 )
FFB loan issuance costs (49 ) (2 )
Other financing activities (6 ) (15 )
Net cash used for financing activities (577 ) (869 )
Net Change in Cash and Cash Equivalents 33
8
Cash and Cash Equivalents at Beginning of Period 30
45
Cash and Cash Equivalents at End of Period $ 63
$ 53
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $13 and $10 capitalized for 2014 and 2013, respectively) $ 235
$ 247
Income taxes, net 309
109
Noncash transactions — accrued property additions at end of period 220
230

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

~~Table of Contents~~

~~GEORGIA POWER COMPANY~~

~~CONDENSED BALANCE SHEETS (UNAUDITED)~~

Assets At September 30,
2014 At December 31,
2013
(in millions)
Current Assets:
Cash and cash equivalents $ 63
$ 30
Receivables —
Customer accounts receivable 738
512
Unbilled revenues 241
209
Joint owner accounts receivable 75
67
Other accounts and notes receivable 54
117
Affiliated companies 21
21
Accumulated provision for uncollectible accounts (8 ) (5 )
Fossil fuel stock, at average cost 405
742
Materials and supplies, at average cost 431
409
Vacation pay 88
88
Prepaid income taxes 57
97
Other regulatory assets, current 62
66
Other current assets 118
54
Total current assets 2,345
2,407
Property, Plant, and Equipment:
In service 30,818
30,132
Less accumulated provision for depreciation 11,192
10,970
Plant in service, net of depreciation 19,626
19,162
Other utility plant, net 218
240
Nuclear fuel, at amortized cost 516
523
Construction work in progress 3,884
3,500
Total property, plant, and equipment 24,244
23,425
Other Property and Investments:
Equity investments in unconsolidated subsidiaries 58
46
Nuclear decommissioning trusts, at fair value 772
751
Miscellaneous property and investments 37
44
Total other property and investments 867
841
Deferred Charges and Other Assets:
Deferred charges related to income taxes 701
718
Prepaid pension costs 133
118
Deferred under recovered regulatory clause revenues 175
—
Other regulatory assets, deferred 1,156
1,152
Other deferred charges and assets 294
246
Total deferred charges and other assets 2,459
2,234
Total Assets $ 29,915
$ 28,907

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

~~Table of Contents~~

~~GEORGIA POWER COMPANY~~

~~CONDENSED BALANCE SHEETS (UNAUDITED)~~

Liabilities and Stockholder's Equity At September 30,
2014 At December 31,
2013
(in millions)
Current Liabilities:
Securities due within one year $ 503
$ 5
Notes payable 211
1,047
Accounts payable —
Affiliated 503
417
Other 476
472
Customer deposits 250
246
Accrued taxes —
Accrued income taxes 155
—
Other accrued taxes 313
321
Accrued interest 99
91
Accrued vacation pay 60
61
Accrued compensation 111
80
Other current liabilities 177
166
Total current liabilities 2,858
2,906
Long-term Debt 9,135
8,633
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 5,295
5,200
Deferred credits related to income taxes 107
112
Accumulated deferred investment tax credits 196
203
Employee benefit obligations 580
542
Asset retirement obligations 1,215
1,210
Other cost of removal obligations 58
43
Other deferred credits and liabilities 178
201
Total deferred credits and other liabilities 7,629
7,511
Total Liabilities 19,622
19,050
Preferred Stock 45
45
Preference Stock 221
221
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares 398
398
Paid-in capital 5,683
5,633
Retained earnings 3,950
3,565
Accumulated other comprehensive loss (4 ) (5 )
Total common stockholder's equity 10,027
9,591
Total Liabilities and Stockholder's Equity $ 29,915
$ 28,907



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income	$	282	$	316	$	522	$	586
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $9, $-, $-, and $-, respectively	14		—		—		—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $-, respectively	1		1		1		1
Total other comprehensive income (loss)	15		1		1		1
Comprehensive Income	$	297	$	317	$	523	$	587

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

Table of Contents

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	522		$	586
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	512			503
Deferred income taxes	(6		)	121
Allowance for equity funds used during construction	(10		)	(16		)
Retail fuel cost over recovery — long-term	—			(44		)
Deferred expenses	28			31
Contract amendment	(118		)	—
Other, net	—			(12		)
Changes in certain current assets and liabilities —
-Receivables	(21		)	(353		)
-Fossil fuel stock	101			255
-Prepaid income taxes	86			(7		)
-Other current assets	(38		)	(14		)
-Accounts payable	(110		)	(140		)
-Accrued taxes	(125		)	(65		)
-Accrued compensation	(61		)	(15		)
-Retail fuel cost over recovery — short-term	—			(14		)
-Other current liabilities	14			27
Net cash provided from operating activities	774			843
Investing Activities:
Property additions	(853		)	(906		)
Nuclear decommissioning trust fund purchases	(655		)	(324		)
Nuclear decommissioning trust fund sales	649			322
Change in construction payables, net of joint owner portion	26			52
Prepaid long-term service agreements	(40		)	(47		)
Other investing activities	(18		)	(14		)
Net cash used for investing activities	(891		)	(917		)
Financing Activities:
Increase (decrease) in notes payable, net	44			(359		)
Proceeds —
Capital contributions from parent company	23			24
Pollution control revenue bonds	170			—
FFB loan	600			1,000
Short-term borrowings	250			—
Redemptions and repurchases —
Pollution control revenue bonds	(65		)	(37		)
Senior notes	(125		)	—
Short-term borrowings	(250		)	—
Payment of preferred and preference stock dividends	(9		)	(9		)
Payment of common stock dividends	(517		)	(477		)
FFB loan issuance costs	—			(49		)
Other financing activities	(4		)	(3		)
Net cash provided from financing activities	117			90
Net Change in Cash and Cash Equivalents	—			16
Cash and Cash Equivalents at Beginning of Period	24			30
Cash and Cash Equivalents at End of Period	$	24		$	46
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $5 and $8 capitalized for 2015 and 2014, respectively)	$	170		$	157
Income taxes, net	240			145
Noncash transactions — Accrued property additions at end of period	171			267

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

Table of Contents

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	24		$	24
Receivables —
Customer accounts receivable	778			553
Unbilled revenues	294			201
Joint owner accounts receivable	44			121
Other accounts and notes receivable	46			61
Affiliated companies	20			18
Accumulated provision for uncollectible accounts	(6		)	(6		)
Fossil fuel stock, at average cost	338			439
Materials and supplies, at average cost	425			438
Vacation pay	91			91
Prepaid income taxes	225			278
Other regulatory assets, current	147			136
Other current assets	86			74
Total current assets	2,512			2,428
Property, Plant, and Equipment:
In service	31,363			31,083
Less accumulated provision for depreciation	10,961			11,222
Plant in service, net of depreciation	20,402			19,861
Other utility plant, net	10			211
Nuclear fuel, at amortized cost	551			563
Construction work in progress	4,171			4,031
Total property, plant, and equipment	25,134			24,666
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	61			58
Nuclear decommissioning trusts, at fair value	814			789
Miscellaneous property and investments	37			38
Total other property and investments	912			885
Deferred Charges and Other Assets:
Deferred charges related to income taxes	681			698
Deferred under recovered regulatory clause revenues	—			197
Other regulatory assets, deferred	2,063			1,753
Other deferred charges and assets	446			403
Total deferred charges and other assets	3,190			3,051
Total Assets	$	31,748		$	31,030

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

Table of Contents

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	1,660		$	1,154
Notes payable	200			156
Accounts payable —
Affiliated	392			451
Other	574			555
Customer deposits	259			253
Other accrued taxes	207			332
Accrued interest	96			96
Accrued vacation pay	62			63
Accrued compensation	81			153
Other current liabilities	309			257
Total current liabilities	3,840			3,470
Long-term Debt	8,914			8,683
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,524			5,507
Deferred credits related to income taxes	103			106
Accumulated deferred investment tax credits	191			196
Employee benefit obligations	870			903
Asset retirement obligations	1,301			1,223
Other deferred credits and liabilities	286			255
Total deferred credits and other liabilities	8,275			8,190
Total Liabilities	21,029			20,343
Preferred Stock	45			45
Preference Stock	221			221
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares	398			398
Paid-in capital	6,232			6,196
Retained earnings	3,830			3,835
Accumulated other comprehensive loss	(7		)	(8		)
Total common stockholder's equity	10,453			10,421
Total Liabilities and Stockholder's Equity	$	31,748		$	31,030

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

Table of Contents

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~THIRD~~SECOND QUARTER ~~2014~~2015 vs. ~~THIRD~~SECOND QUARTER ~~2013~~2014

AND

YEAR-TO-DATE ~~2014~~2015 vs. YEAR-TO-DATE ~~2013~~2014

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service ~~area~~territory located within the State of Georgia and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, ~~given economic conditions,~~ and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, and fuel. In addition, ~~Georgia Power is currently constructing~~construction continues on Plant Vogtle Units 3 and 4 in which Georgia Power will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.

Georgia Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Georgia Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$38 7.8 $136 14.1

Georgia Power's net income after dividends on preferred and preference stock for the ~~third~~second quarter ~~2014~~2015 was ~~$525~~$277 million compared to ~~$487~~$311 million for the corresponding period in 2013. The increase was primarily due to an increase in retail base revenues effective January 1, 2014 as authorized under the 2013 ARP and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013, partially offset by higher non-fuel operations and maintenance expenses.

~~Georgia Power's~~2014. For year-to-date 2015, net income after dividends on preferred and preference stock ~~for year-to-date 2014~~ was ~~$1.10 billion~~$513 million compared to ~~$966~~$577 million for the corresponding period in ~~2013.~~2014. The ~~increase was~~decreases were primarily due to ~~colder weather in~~higher non-fuel operations and maintenance expenses and the ~~first quarter 2014~~correction of an error affecting billings to a small number of large commercial and ~~warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and an increase~~industrial customers, partially offset by increases in retail base revenues effective January 1, ~~2014~~2015 as authorized ~~under~~by the ~~2013 ARP, partially offset by higher non-fuel operations and maintenance expenses.~~Georgia PSC. Additionally, warmer weather in the second quarter 2015 compared to the corresponding period in 2014 contributed to increases in retail base revenues.

See Note (A) to Condensed Financial Statements herein for additional information.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions)
(% change)
$138 6.0 $580 9.8

In the ~~third~~second quarter ~~2014,~~2015, retail revenues were ~~$2.45~~$1.87 billion compared to ~~$2.31~~$2.00 billion for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, retail revenues were ~~$6.50~~$3.69 billion compared to ~~$5.92~~$4.05 billion for the corresponding period in ~~2013.~~2014.

6164

Table of Contents

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:


	Third Quarter 2014				Year-to-Date 2014				Second Quarter 2015					Year-to-Date 2015
	(in millions)		(% change)		(in millions)		(% change)		(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	2,314			$	5,922			$	2,000				$	4,050
Estimated change resulting from –
Rates and pricing	67		2.9		147		2.5		(27		)	(1.3	)	3			0.1
Sales growth	1		0.1		23		0.4		21			1.0		37			0.9
Weather	51		2.2		131		2.2		22			1.1		6			0.1
Fuel cost recovery	19		0.8		279		4.7		(144		)	(7.2	)	(410		)	(10.1	)
Retail – current year	$	2,452	6.0	%	$	6,502	9.8	%	$	1,872		(6.4	)%	$	3,686		(9.0	)%

Revenues associated with changes in rates and pricing ~~increased~~decreased in the ~~third~~second quarter ~~and year-to-date 2014~~2015 when compared to the corresponding ~~periods~~period in ~~2013~~2014 primarily due to the correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing, partially offset by base tariff increases ~~effective January 1, 2014, as~~ approved ~~by the Georgia PSC in~~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, ~~as well as higher contributions from market-driven~~which were both effective January 1, 2015. Revenues associated with changes in rates ~~from commercial~~ and ~~industrial customers.~~pricing increased slightly year-to-date 2015 when compared to the corresponding period in 2014 primarily due to the base tariff increases and increases in collections for financing costs described above, partially offset by the error correction. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales increased in the ~~third~~second quarter andyear-to-date ~~2014~~2015 when compared to the corresponding periods in ~~2013.~~2014. Weather-adjusted residential KWH sales ~~decreased 0.1%~~increased 2.6%, weather-adjusted commercial KWH sales ~~decreased~~increased 1.1%, and weather-adjusted industrial KWH sales ~~increased 2.4%~~remained flat in the ~~third~~second quarter ~~2014~~2015 when compared to the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, weather-adjusted residential KWH sales increased ~~0.8%~~1.8%, weather-adjusted commercial KWH sales ~~decreased 0.2%~~increased 1.0%, and weather-adjusted industrial KWH sales increased ~~1.7%~~2.0% when compared to the corresponding period in ~~2013.~~2014. An increase of approximately 28,000 residential customers since June 30, 2014 contributed to the increase in weather-adjusted residential KWH sales. Increased customer usage and an increase of approximately 3,000 commercial customers since June 30, 2014 contributed to the increase in weather-adjusted commercial sales. Increased demand in the ~~primary metals, non-manufacturing,~~ paper, stone, clay, and glass, food processing, transportation, rubber, and pipeline sectors was the main contributor to the increase in weather-adjusted industrial sales. Decreased customer usage contributed to the decrease in weather-adjusted commercial sales. An increase of approximately 20,000 residential customers since September 30, 2013 contributed to the year-to-date 2014 increase in weather-adjusted residential KWH sales, partially offset by ~~decreased customer usage. Household income, one of~~a decrease in the ~~primary drivers of residential customer usage, has been flat in 2014.~~chemicals sector.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues ~~increased $19~~decreased $144 million and ~~$279~~$410 million in the ~~third~~second quarter and year-to-date ~~2014,~~2015, respectively, when compared to the corresponding periods in ~~2013~~2014 primarily due to ~~higher~~lower natural gas, ~~costs~~coal, and ~~higher energy sales resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013.~~nuclear fuel costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – ~~"PSC~~"Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

Wholesale Revenues – Non-Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$3 3.9 $57 26.9

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. ~~Capacity~~Wholesale capacity revenues ~~reflect~~from PPAs are

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

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

~~For year-to-date 2014,~~In the second quarter 2015, wholesale revenues from sales to non-affiliates were ~~$269~~$50 million compared to ~~$212~~$80 million for the corresponding period in ~~2013~~2014 related to a $15 million decrease in energy revenues and a $15 million decrease in capacity revenues. For year-to-date 2015, wholesale revenues from sales to non-affiliates were $118 million compared to $189 million for the corresponding period in 2014 related to a $48 million decrease in energy revenues and a $23 million decrease in capacity revenues. The decreases in energy revenues were primarily due to ~~increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and~~ the lower cost of ~~Georgia Power-owned generation compared to~~natural gas and coal. The decreases in capacity revenues reflect the ~~market cost~~expiration of ~~available energy.~~wholesale contracts in December 2014 and the retirements of Plant Branch Units 1, 3, and 4, Plant Yates Units 1 through 5, and Plant McManus Units 1 and 2.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$4 N/M $24 171.4

~~N/M – Not meaningful~~

Wholesale revenues from sales to affiliated companies ~~within the Southern Company system~~ will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost.

~~For year-to-date 2014,~~In the second quarter 2015, wholesale revenues from sales to affiliates were ~~$38~~$4 million compared to ~~$14~~$10 million for the corresponding period in 2013. The increase was due to higher demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and the lower cost of Georgia Power-owned generation.

~~Other Revenues~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$2 2.2 $17 6.5

2014. For year-to-date ~~2014, other operating~~2015, wholesale revenues from sales to affiliates were ~~$277~~$12 million compared to ~~$260~~$31 million infor the corresponding period in ~~2013.~~2014. The ~~increase was primarily~~decreases were due to ~~an increase of $13 million in open access transmission tariff revenues~~lower natural gas and ~~$6 million of solar application fee revenue for year-to-date 2014 as compared to the corresponding period in 2013.~~coal prices.

Fuel and Purchased Power Expenses


	Third Quarter 2014 vs. Third Quarter 2013					Year-to-Date 2014 vs. Year-to-Date 2013			Second Quarter 2015 vs. Second Quarter 2014					Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)		(change in millions)		(% change)	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(7	)	(1.0	)	$	288	16.3	$	(116	)	(18.7	)	$	(342	)	(24.9	)
Purchased power – non-affiliates	13			20.3		44		25.1	15			23.8		(4		)	(2.8	)
Purchased power – affiliates	20			13.2		19		3.8	(51		)	(30.7	)	(87		)	(24.9	)
Total fuel and purchased power expenses	$	26				$	351		$	(152	)			$	(433	)

In the ~~third~~second quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$933~~$696 million compared to ~~$907~~$848 million in the corresponding period in ~~2013.~~2014. The ~~increase~~decrease in the ~~third~~second quarter ~~2014~~2015 was primarily due to ~~an $82~~a $154 million decrease in the average cost of fuel related to lower natural gas, coal, and nuclear fuel prices and a decrease in the average cost of purchased power due to lower natural gas prices and a $21 million decrease in the volume of KWHs generated due to less available generating capacity as a result of plant retirements in April 2015, partially offset by a $23 million increase in the volume of KWHs ~~generated and~~ purchased ~~as a result of warmer weather in the third quarter 2014 as~~due to lower natural gas prices.

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For year-to-date 2015, total fuel and purchased power expenses were $1.43 billion compared to $1.86 billion in the corresponding period in ~~2013 driving higher customer demand, partially offset by~~2014. The decrease in year-to-date 2015 was primarily due to a ~~$56~~$396 million decrease in the average cost of fuel ~~primarily due~~related to lower natural gas, coal, ~~prices.~~

~~For year-to-date 2014, total~~and nuclear fuel prices and ~~purchased power expenses~~ ~~were $2.80 billion compared to $2.45 billion in the corresponding period in 2013.~~ ~~The increase in~~ ~~year-to-date 2014 was primarily due to~~ a ~~$66 million increase~~decrease in the average cost of ~~fuel and~~ purchased power ~~primarily~~ due to ~~higher~~lower natural gas prices and a ~~$285~~$99 million decrease in the volume of KWHs generated due to less available generating capacity as a result of plant retirements in April 2015, partially offset by a $62 million increase in the volume of KWHs ~~generated primarily as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared~~purchased due to ~~the corresponding periods in 2013 driving higher customer demand.~~lower natural gas prices.

Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL – ~~"PSC~~"Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

Details of Georgia Power's generation and purchased power were as follows:


	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013	Second Quarter 2015	Second Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (billions of KWHs)	19	19	55	50	17	18	34	36
Total purchased power (billions of KWHs)	6	5	16	17	6	5	11	10
Sources of generation (percent) —
Coal	45	42	45	35	40	42	37	45
Nuclear	20	22	21	23	24	22	23	21
Gas	34	34	32	39	34	34	38	31
Hydro	1	2	2	3	2	2	2	3
Cost of fuel, generated (cents per net KWH) —
Coal	4.19	4.89	4.49	4.99	3.75	4.20	4.18	4.65
Nuclear	0.86	0.91	0.90	0.91	0.85	0.93	0.71	0.92
Gas	3.41	3.34	3.84	3.34	2.67	3.81	2.65	4.09
Average cost of fuel, generated (cents per net KWH)	3.25	3.47	3.51	3.37	2.66	3.32	2.76	3.66
Average cost of purchased power (cents per net KWH)^(a)	5.03	5.00	5.42	4.80
Average cost of purchased power (cents per net KWH)^(*)					4.56	5.55	4.47	5.66


~~(a)~~	~~Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.~~

(*) Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.

Fuel

In the ~~third~~second quarter ~~2014,~~2015, fuel expense was ~~$684~~$503 million compared to ~~$691~~$619 million in the corresponding period in ~~2013.~~2014. The decrease was primarily due to a ~~14.3%~~19.9% decrease in the average cost of coal per KWH generated, partially offset by a 1.5% increase in the volume of KWHs generated as a result of warmer weather in the third quarter 2014 as compared to the corresponding period in 2013 driving higher customer demand.

~~For year-to-date 2014, fuel expense was $2.06 billion compared to $1.77 billion in the corresponding period in 2013. Th~~e increase was primarily due to a 10.7% increase in the volume of KWHs generated as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 driving higher customer demand and a 4.2% increase in the average cost of fuel per KWH generated and a 6.7% decrease in the volume of KWHs generated by coal.

For year-to-date 2015, fuel expense was $1.03 billion compared to $1.37 billion in the corresponding period in 2014. The decrease was primarily due to ~~higher~~a 24.6% decrease in the average cost of fuel per KWH generated and a 22.2% decrease in the volume of KWHs generated by coal, partially offset by a 13.9% increase in the volume of KWHs generated by natural ~~gas prices.~~gas.

Purchased Power – Non-Affiliates

In the ~~third~~second quarter ~~2014,~~2015, purchased power expense from non-affiliates was ~~$77~~$78 million compared to ~~$64~~$63 million in the corresponding period in ~~2013.~~2014. The increase was primarily due to a ~~4.1%~~94.1% increase in the ~~average cost per KWH~~volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the second quarter 2015 compared to the corresponding period in 2014 and to replace the energy previously generated by the plants retired in April 2015,

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partially offset by a 36.0% decrease in the average cost per KWH purchased, primarily resulting from ~~higher~~lower natural gas prices.

For year-to-date 2015, purchased power expense from non-affiliates was $138 million compared to $142 million in the corresponding period in 2014. The decrease was primarily due to a 32.9% decrease in the average cost per KWH purchased primarily from lower natural gas prices, ~~and~~partially offset by a ~~19.0%~~48.5% increase in ~~the~~ volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the ~~third~~second quarter ~~2014 as~~2015 compared to the corresponding period in ~~2013.~~

~~For year-to-date 2014, purchased power expense from non-affiliates was $219 million compared to $175 million in the corresponding period in 2013.~~ ~~The increase was d~~ue to an increase of 17.5% in the average cost per KWH purchased primarily resulting from higher natural gas prices and a 7.3% increase in the volume of KWHs purchased to meet higher customer demand resulting from colder weather in the first quarter 2014 and ~~warmer weather~~to replace the energy previously generated by the plants retired in ~~the second and third quarters 2014 as compared to the corresponding periods in 2013.~~April 2015.

Purchased Power – Affiliates

In the ~~third~~second quarter ~~2014,~~2015, purchased power expense from affiliates was ~~$172~~$115 million compared to ~~$152~~$166 million in the corresponding period in 2013. The increase was due to a 23.1% increase in the volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.

2014. For year-to-date ~~2014,~~2015, purchased p~~ower~~power expense from affiliates was ~~$522~~$263 million compared to ~~$503~~$350 million in the corresponding period in ~~2013.~~2014. The ~~increase was primarily~~decreases were due to a ~~10.1% increase~~17.7% decrease in the second quarter 2015 and a 20.7% decrease for year-to-date 2015 in the average cost ~~per~~of KWH purchased, ~~reflecting higher~~primarily resulting from lower natural gas ~~prices, partially offset by a 2.1% decrease in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources.~~prices.

Energy purchases from affiliates will vary depending on ~~the~~ demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$54 13.4 $104 8.5

In the ~~third~~second quarter ~~2014,~~2015, other operations and maintenance expenses were ~~$456~~$467 million compared to ~~$402~~$451 million in the corresponding period in ~~2013.~~2014. The increase was primarily due to increases of ~~$21~~$10 million in ~~generation expenses~~employee compensation and benefits including pension costs, $8 million in scheduled outage-related costs, and $3 million primarily related to ~~meet higher demand~~customer incentive and ~~for scheduled outage maintenance and $22~~demand-side management costs, partially offset by a decrease of $7 million in transmission and distribution overhead line maintenance. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

For year-to-date ~~2014,~~2015, other operations and maintenance ~~expens~~esexpenses were ~~$1.33 billion compared~~$943 million compared to ~~$1.23 billion~~$878 million in the corresponding p~~eriod~~period in ~~2013.~~2014. The increase was primarily due to increases of ~~$44~~$31 million in ~~generation expenses to meet higher demand, $37~~employee compensation and benefits including pension costs, $15 million in ~~transmission~~scheduled outage-related costs, and ~~distribution overhead line maintenance, and $16~~$13 million ~~in customer assistance expenses~~primarily related to customer incentive and demand-side management ~~programs.~~costs.

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$10 5.0 $23 3.8

In the ~~third~~second quarter ~~2014,~~2015, depreciation and amortization was ~~$211~~$202 million compared to ~~$201~~$209 million in the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to decreases in other cost of removal of $9 million and $4depreciation of $2 million as authorized by the Georgia PSC under the 2013 ARP, partially offset by an increase in amortization of $4 million.

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regulatory liabilities related to state income tax credits that was completed in December 2013 and other cost of removal obligations as authorized in the 2013 ARP, respectively, partially offset by a decrease of $6 million inFor year-to-date 2015, depreciation and amortization ~~also as authorized in the 2013 ARP.~~

~~For year-to-date 2014, depreciation and amortization~~was ~~$628~~$418 million compared to ~~$605~~$417 million in the corresponding period in ~~2013.~~2014. The increase was due to ~~decreases of $27 million~~an increase in depreciation and ~~$12 million in~~ amortization of ~~regulatory liabilities related to state income tax credits that was completed in December 2013 and other cost of removal obligations~~$10 million as authorized inby the Georgia PSC under the 2013 ARP, ~~respectively,~~ partially offset by a decrease in other cost of ~~$14 million in depreciation and amortization also as authorized in the 2013 ARP.~~removal of $9 million.

Taxes Other Than Income Taxes

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$9 8.8 $28 9.6

In the ~~third~~second quarter ~~2014,~~2015, taxes other than income taxes were ~~$111~~$97 million compared to ~~$102~~$106 million in the corresponding period in ~~2013.~~ 2014. For the year-to-date ~~2014,~~2015, taxes other than income taxes were ~~$320~~$195 million c~~ompared~~compared to ~~$292~~$209 million in the corresponding period in ~~2013.~~2014. The ~~increases~~decreases were primarily due to ~~increases~~decreases of $5$6 million and ~~$21~~$11 million in municipal franchise fees related to ~~higher~~lower retail revenues in the second quarter 2015 and ~~$3 million and $6~~year-to-date 2015, respectively, as well as decreases of $2 million in ~~payroll~~property taxes ~~in the third quarter 2014 and year-to-date 2014, respectively.~~for each period.

~~Interest Expense, Net of Amounts Capitalized~~Other Income (Expense), net

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(4) (4.3) $(17) (6.1)

In the ~~third~~second quarter ~~2014, interest expense,~~2015, other income (expense), net ~~of amounts capitalized~~ was ~~$88~~$1 million compared to ~~$92~~$11 million in the corresponding period in 2013. The decrease was due to a $13 million decrease in interest on long-term debt resulting from the refinancing of long-term debt at lower rates, partially offset by a $9 million increase in interest on outstanding long-term debt borrowings from the FFB.

2014. For year-to-date ~~2014, interest expense,~~2015, other income (expense), net ~~of amounts capitalized~~ was ~~$262~~$16 million compared to ~~$279~~$15 million in the corresponding period in ~~2013.~~2014. The ~~decrease was due~~changes primarily relate to a $36 million decrease in interest on long-term debt resulting from the refinancing of long-term debt at lower rates and redemptions, partially offset by a $22 million increase in interest on outstanding long-term debt borrowings from the FFB.

~~See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.~~AFUDC equity.

Income Taxes

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$18 6.0 $60 10.0

~~In the third quarter 2014,~~For year-to-date 2015, income taxes were ~~$317~~$320 million compared to ~~$299 million for the corresponding period in 2013. For year-to-date 2014, income taxes were $660 million compared to $600~~$343 million in the corresponding period in ~~2013.~~2014. The ~~increases in income taxes were~~decrease was primarily due to ~~higher~~lower pre-tax earnings.

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~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

FUTURE EARNINGS POTENTIAL

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

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Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – ~~"PSC~~"Retail Regulatory Matters – Integrated Resource Plans" of Georgia Power in Item 7 of the Form 10-K and ~~"PSC~~"Retail Regulatory Matters – Integrated Resource Plan" herein for additional information ~~regarding~~on planned unit retirements and fuel conversions at Georgia ~~Power's plans for compliance with environmental statutes and regulations.~~Power.

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR).

On June 12, 2015, the EPA published a final rule requiring affected states (including Georgia, Alabama, and ~~the EPA's proposed rules~~Florida) to revise or remove state implementation plan (SIP) provisions regarding ~~the regulation of~~ excess emissions that occur during periods of ~~startup, shutdown, or malfunction (SSM).~~SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.

On ~~April~~June 29, ~~2014,~~2015, the U.S. Supreme Court ~~overturned~~issued a decision finding that the ~~U.S. Court of Appeals for the District of Columbia Circuit's August 2012~~EPA had failed to properly consider costs in its decision to ~~vacate CSAPR~~regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case ~~back~~ to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. ~~On October 23, 2014,~~The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit ~~granted~~and the ~~EPA's motion~~EPA respond to ~~lift~~ the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR.decision. The ultimate ~~financial and unit operational~~ impact of ~~the rule~~this decision cannot be determined at this ~~time~~time.

On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Georgia, Alabama, and ~~is dependent~~Florida. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).

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~~the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.~~

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Water Quality~~

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the ~~CWA. If finalized as proposed,~~CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. ~~In addition, the~~The rule ~~as proposed could have significant impacts on economic development projects which could affect customer demand growth.~~becomes effective August 28, 2015. The ultimate impact of the ~~proposed~~final rule will depend on ~~the specific requirements of the final rule and~~ the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – ~~Environmental Statutes and Regulations – Water Quality"~~ Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's ~~rulemaking for cooling water intake structures.~~regulation of CCR.

On ~~August 15, 2014,~~April 17, 2015, the EPA published athe Disposal of Coal Combustion Residuals from Electric Utilities final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became(CCR Rule) in the Federal Register, setting October 19, 2015 as the effective ~~October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation~~date of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units.CCR Rule. The ultimate impact of ~~this rule will depend on~~ the ~~outcome of any legal challenges and~~CCR Rule cannot be determined at this ~~time.~~timeand will depend on Georgia Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Georgia Power recorded incremental asset retirement obligations (ARO) of approximately $82 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Georgia Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's AROs.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's ~~current and~~ proposed regulation of ~~GHG emissions under the Clean Air Act.~~CO₂ from fossil-fuel-fired electric generating units.

On ~~June 18, 2014,~~August 3, 2015, the EPA ~~published~~released pre-publication versions of two final rules that would limit CO₂ emissions from fossil fuel-fired electric generating units. One of the ~~proposed Clean Power Plan, setting forth~~final rules contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to ~~address CO~~₂ ~~emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final~~meet EPA-mandated CO₂ emission ~~rate goals~~rates for existing units. The EPA's final guidelines require state plans to ~~be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposed~~meet interim CO₂ performance ~~standards for modified~~rates between 2022 and ~~reconstructed fossil fuel-fired electric generating units. The~~2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, ~~that~~which could ~~impact~~affect future unit retirement and replacement decisions. ~~Also, additional compliance costs could affect~~Georgia Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated ~~rates. Further, any resulting higher costs that are recovered~~rates or through ~~regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.~~

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a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system.market-based contracts. However, the ultimate financial and operational impact of the ~~Clean~~final rules on Georgia Power ~~Plan proposed guidelines on the Southern Company system~~ cannot be determined at this time and will ~~be dependent upon~~depend on numerous ~~factors. These~~ factors ~~include:~~including the ~~structure, timing, and content~~Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final ~~guidelines; individual state implementation of these~~ guidelines, including the potential that state ~~implementation~~ plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and ~~emissions-related~~emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of the U.S. Supreme Court's decision cannot be determined at this time.

~~PSC~~FERC Matters

~~Rate Plans~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate Plans" of~~ Georgia Power ~~in Item 7 and Note 3~~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 ~~financial statements~~requirements of ~~Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of~~an energy auction, which the ~~Form 10-K for additional information on Georgia Power's 2013 ARP.~~

FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with ~~the terms of the 2013 ARP, on October 3, 2014, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2015 pending its approval:~~

~~Increase the traditional base tariffs by approximately $107 million to cover additional capacity costs;~~

~~Increase the environmental compliance cost recovery tariff by approximately $32 million;~~

~~Increase the demand-side management tariffs by approximately $3 million; and~~

~~Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.~~

~~The ultimate outcome of this matter cannot be determined at this time.~~

~~Renewables Development~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Renewables Development" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Renewables Development" in Item 8 of the Form 10-K for additional information.

As a result of biomass PPA amendments executed during 2014, total estimated purchased power contractual obligations decreased $392 million from December 31, 2013. Estimated purchased power contractual obligations have been updated to $641million for 2015 and 2016, $679 million for 2017 and 2018, and $3.8 billion after 2018. Estimated purchased power contractual obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations – Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for additional information.

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FERC regulations governing such authority, the traditional operating companies (including Georgia Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On ~~October 8, 2014,~~April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Georgia Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Georgia Power) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including Georgia Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power ~~executed PPAs~~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 tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to ~~purchase energy from 515 MWs~~the construction of ~~solar capacity as~~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 3 to the financial statements of Georgia Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

Renewables Development

As part of the Georgia Power Advanced Solar Initiative ~~program.~~program, Georgia Power executed ten PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. These PPAs are expected to commence in December 2015 and 2016 and have terms ranging from 20 to 30 ~~years,~~years. As a result of certain acquisitions by Southern Power, Georgia Power expects that 249 MWs of the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.

On June 15, 2015, Georgia Power executed a PPA to purchase a total of 58 MWs of biomass capacity and ~~are subject to~~energy from a 79-MW facility in Georgia that will begin in 2017 and end in 2047. This PPA was approved by the Georgia PSC ~~approval.~~on April 15, 2015. Georgia Power also entered into an energy-only PPA for the remaining 21 MWs from the same facility.

On ~~October 23, 2014,~~July 21, 2015, the Georgia PSC approved Georgia Power's request to build, own, and operate ~~three 30-MW~~a 46-MW solar generation ~~facilities~~facility at ~~three~~a U.S. ~~Army bases~~Marine Corps base in Albany, Georgia by the end of 2016. ~~In addition, Georgia Power has entered into a memorandum of understanding with the U.S. Navy to pursue a similar solar project pending Georgia PSC review.~~

~~The ultimate outcome of these matters cannot be determined at this time.~~

Integrated Resource Plan

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Integrated Resource Plans" of Georgia Power in Item 7 and Note 3 to~~To comply with the ~~financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8~~April 16, 2015 effective date of the ~~Form 10-K for additional information.~~

~~Georgia Power filed a request with the Georgia PSC~~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 ~~January 10, 2014 to cancel the proposed biomass fuel conversion of~~April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) ~~because it would not~~and its decertification will be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3requested in connection with the triennial Integrated Resource Plan in 2016. ~~Georgia Power plans~~The switch to ~~continue~~natural gas as the primary fuel is complete at Plant Yates Units 7 and 6 and the units were returned to ~~operate the unit as needed until the Mercury~~service on May 4, 2015 and ~~Air Toxics Standards rule becomes effective in April 2015.~~June 27, 2015, respectively.

Fuel Cost Recovery

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of~~ Georgia Power ~~in Item 7 and Note 3 to~~has established fuel cost recovery rates approved by the ~~financial statements of~~Georgia PSC. Georgia Power ~~under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.~~

As of September 30, 2014, Georgia Power's under recovered fuel balance totaled $175 million and is included in deferred charges and other assets on Georgia Power's Condensed Balance Sheet herein. As of December 31, 2013, Georgia Power's over recovered fuel balance totaled $58 million and is included in current liabilities and other deferred credits and liabilities on Georgia Power's Condensed Balance Sheet herein. Georgia Power'sexpects to file its next fuel case ~~is expected to~~in September 2015. The ultimate outcome of this matter cannot be ~~filed with the Georgia PSC by February 27, 2015.~~determined at this time.

Fuel cost recovery revenues ~~as recorded on the financial statements~~ are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Georgia Power's revenues or net income, but will affect cash flow. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information.

~~Storm Damage Recovery~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Storm Damage Recovery" of Georgia Power in Item 7 and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $105 million and $37 million, respectively. The increase was primarily the result of an ice storm in February 2014. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Georgia Power's financial statements.

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Nuclear Construction

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – ~~"PSC~~"Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, and pending litigation.

In ~~2009,~~2008, Georgia Power, acting for itself and as agent for the ~~Georgia PSC approved inclusion of~~Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 ~~related CWIP accounts in rate base,~~Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the ~~State of Georgia enacted~~Contractor's failure to fulfill the ~~Georgia Nuclear Energy Financing Act, which allows~~schedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to ~~recover financing costs~~the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.

Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for ~~nuclear construction projects certified~~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 ~~Georgia PSC. Financing costs are recovered~~Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On October 31, 2014, Georgia Power filed to increase the NCCR tariff by approximately $27 million effective January 1, 2015 pending Georgia PSC approval. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2014, approximately $23 million of these 2009 and 2010 costs remained unamortized in CWIP.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and ~~4 certificate from~~4. The NRC certified the ~~Georgia PSC. Accordingly, Georgia Power's eighth VCM report filed~~Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in ~~February 2013 requested an amendment~~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 ~~certificate to increase the estimated in-service capital cost~~construction and licensing of Plant Vogtle Units 3 and 4, ~~from $4.4 billion to $4.8 billion~~at the federal and ~~to extend the estimated in-service dates to the fourth quarter 2017~~state level, and ~~the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the~~additional challenges are expected as construction ~~period are estimated to total approximately $2.0 billion.~~proceeds.

In September 2013, the Georgia PSC approved a stipulation entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. On August 19, 2014, the Georgia PSC approved a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), including construction capital costs incurred, which through December 31, 2013 totaled $2.6 billion. Georgia Power resumed filing semi-annual reports with the eleventh VCM report filed on August 28, 2014, which requests approval of an additional $0.2 billion in costs incurred from January 1, 2014 through June 30, 2014.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the ~~Westinghouse Design Control Document, as amended (DCD),~~DCD and the delays in the timing of approval of the DCD and issuance of the ~~combined construction and operating licenses (COLs),~~COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the ~~agreement entered into by Georgia Power, acting for itself and as agent for the~~ Vogtle ~~Owners, and the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units~~ 3 and 4 ~~(Vogtle 3 and 4 Agreement).~~Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In ~~August~~ 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling

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

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April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May ~~22,~~ 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new ~~allegations, but~~allegations; however, the Contractor subsequently asserted estimated minimum damages related to the amended counterclaim (based on Georgia Power's ownership interest) of approximately $113 million in 2014 dollars (approximately $118 million in 2015 dollars). In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these ~~new~~ allegations, any of which could be substantial. Georgia Power ~~does~~has not ~~agree with either~~agreed to the proposed cost or ~~schedule adjustments~~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 which~~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% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Georgia Power's eighth VCM report filed in 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.

Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.

On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month

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Contractor delay, and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion.

Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in ~~the~~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. ~~While Georgia Power expects~~In addition, the ~~Contractor~~IRS allocated production tax credits to ~~employ mitigation efforts~~each of Plant Vogtle Units 3 and 4, which require the applicable unit to ~~maintain the current project schedule and believes the Contractor is responsible for any related costs, Contractor performance and progress~~be placed in ~~recent months on the assembly and installation of the shield building and structural modules have resulted in additional schedule pressure.~~service before 2021.

Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.

See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

The ultimate outcome of these matters cannot be determined at this time.

Other Matters

Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has ~~increased generally~~occurred throughout the U.S. ~~In particular, personal injury, property damage, and other~~This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, ~~coal combustion residuals,~~CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such ~~matters, have become more frequent.~~matters.

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The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not

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anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See ~~the Notes~~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.

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – "Other Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On June 17, 2014, the Georgia PSC approved Georgia Power's request to credit customers the portion of fuel cost related to the nuclear waste fund fee. The nuclear waste fund rider became effective July 1, 2014. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Pension and Other Postretirement Benefits.

Asset Retirement Obligations

The liability for AROs primarily relates to the decommissioning of Georgia Power's nuclear facilities, which include Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Georgia Power has retirement obligations related to various landfill sites, underground storage tanks, and asbestos removal. Georgia Power also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with Georgia Power's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Georgia Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Georgia Power considers the liabilities for AROs to be critical accounting estimates.

See Note 1 to the financial statements of Georgia Power under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Recently Issued Accounting Standards

~~On May 28, 2014, the~~The Financial Accounting Standards ~~Board issued~~Board's (FASB) ASC 606, Revenue from Contracts with Customers~~. ASC 606~~, revises the accounting for revenue recognition ~~and is~~ effective for fiscal years beginning after December 15, ~~2016.~~2017. Georgia Power ~~is currently evaluating~~continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Georgia Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Georgia Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at ~~September~~June 30, ~~2014.~~2015. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as ~~its~~ bank credit ~~arrangements~~agreements to meet future capital and liquidity needs.

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~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled ~~$2.07 billion~~$774 million for the first ~~nine~~six months of ~~2014~~2015 compared to ~~$2.13 billion~~$843 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to ~~fuel cost recovery and storm restoration costs,~~lower operating revenues, partially offset by ~~higher retail operating revenues and lower~~increased fuel ~~inventory additions.~~cost recovery. Net cash used for investing activities totaled ~~$1.46 billion~~$891 million for the first ~~nine~~six months of ~~2014~~2015 compared to ~~$1.25 billion~~$917 million for the corresponding period in ~~2013 due to gross property additions~~2014 primarily related to installation of equipment to comply with environmental ~~standards;~~standards and construction of transmission and distribution ~~facilities; and purchase of nuclear fuel.~~facilities. Net cash ~~used for~~provided from financing activities totaled ~~$577~~$117 million for the first ~~nine~~six months of ~~2014~~2015 compared to ~~$869~~$90 million ~~used for financing activities~~ in the corresponding period in ~~2013.~~2014. The ~~decrease~~increase in cash ~~used for~~provided from financing activities is primarily due to ~~borrowings from the FFB for the construction of Plant Vogtle Units 3 and 4, partially offset by FFB loan issuance costs and a reduction~~an increase in short-term ~~debt.~~debt borrowings. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first ~~nine~~six months of ~~2014~~2015 include increases of ~~$819~~$468 million in property, plant, and equipment ~~$502~~to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases of $550 million ~~in long-term debt primarily due to borrowings from the FFB,~~ and ~~$175 million in deferred under recovered regulatory clause revenues and decreases of $836~~$231 million in short-term debt and ~~$337 million in fossil fuel stock.~~long-term debt, respectively, to fund the continuous construction program and for general corporate purposes.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately ~~$503 million~~$1.7 billion will be required through ~~September~~June 30, ~~2015~~2016 to fund maturities and announced redemptions of long-term ~~debt, including $98 million~~debt. See "Sources of certain pollution control revenue bonds reclassified to securities due within one year in anticipation of redemption in connection with unit retirement decisions. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information regarding unit retirement decisions. Also see FUTURE EARNINGS POTENTIAL – "PSC Matters – Renewables Development"Capital" herein for additional ~~information regarding estimated purchased power contractual obligations.~~information.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.

Sources of Capital

Except as described below with respect to the DOE loan guarantees, Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory

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~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.

~~On February 20, 2014,~~In addition, Georgia Power ~~and the DOE entered into~~may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement)~~, pursuant~~ between Georgia Power and the DOE, the proceeds of which may be used to ~~which~~reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. ~~Georgia Power is obligated~~Eligible Project Costs incurred through June 30, 2015 would allow for borrowings of up to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and also are secured by a first priority lien on (i) Georgia Power's 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit Facility, Georgia Power may make term loan borrowings through the FFB. Proceeds of borrowings made$2.2 billion under the FFB Credit Facility, ~~will be used to reimburse~~of which Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46has borrowed $1.8 billion. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

~~Eligible Project Costs incurred through September~~As of June 30, 2014 would allow for borrowings of up to $2.0 billion under the FFB Credit Facility. Through September 30, 2014, Georgia Power has borrowed $1.0 billion under the FFB Credit Facility, leaving $1.0 billion of available borrowing ability.

2015, Georgia Power's current liabilities ~~frequently exceed~~exceeded current assets ~~because of the continued use of short-term debt as a funding source~~by $1.3 billion primarily due to ~~meet scheduled maturities~~approximately $1.9 billion of long-term debt due within one year and notes payable. For the remainder of 2015, Georgia Power expects to utilize borrowings through the FFB as the primary source of long-term borrowed funds. Georgia Power also intends to utilize operating cash flows, as well as ~~cash needs, which can fluctuate significantly due~~commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, and equity contributions from Southern Company to ~~the seasonality of the business.~~fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

At ~~September~~June 30, ~~2014,~~2015, Georgia Power had approximately ~~$63~~$24 million of cash and cash equivalents. Committed credit arrangements with banks at ~~September~~June 30, ~~2014~~2015 were as follows:


Expires^(a)	Expires^(a)								Expires^(a)								Due Within One Year
	2016		2018		Total		Unused
2016									2016	2018		Total		Unused		Term Out		No Term Out
(in millions)	(in millions)				(in millions)				(in millions)			(in millions)				(in millions)
	$	150	$	1,600	$	1,750	$	1,736
$									150	$	1,600	$	1,750	$	1,737	$	—	$	150


~~(a)~~	~~No credit arrangements expire in 2014, 2015, or 2017.~~

See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's variable rate pollution control revenue bonds and commercial paper ~~borrowings.~~program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of ~~September~~June 30, ~~2014~~2015 was approximately ~~$865~~$970 million. In addition, at ~~September~~June 30, ~~2014,~~2015, Georgia Power had ~~$65~~$122 million of fixed rate pollution control revenue bonds outstanding that were required to be ~~remarketed~~reoffered within the next 12 months.

~~Georgia Power's~~Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Georgia Power. Such cross default provisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness or guarantee obligations over a specified threshold. Georgia Power is currently in compliance with all such covenants. None of the

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~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Georgia Power expects to renew or replace its credit arrangements, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 2015				Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	200	0.3	%	$	370	0.3	%	$	598
Short-term bank debt	—		—	%	247		0.8	%	250
Total	$	200	0.3	%	$	617	0.5	%


~~(a)~~(*)	Average and maximum amounts are based upon daily balances during the three-month period ended ~~September~~June 30, ~~2014.~~2015.

~~Management~~Georgia Power believes the need for working capital can be adequately met by utilizing ~~the~~ commercial paper ~~program,~~programs, lines of credit, short-term bank notes, and ~~cash.~~operating cash flows.

Credit Rating Risk

Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, interest rate derivatives, and construction of new generation.

The maximum potential collateral requirements under these contracts at ~~September~~June 30, ~~2014~~2015 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB- and/or Baa3	$	86	$	102
Below BBB- and/or Baa3	1,297		1,341

Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, ~~any~~a credit rating downgrade could impact Georgia Power's ~~ability~~access to ~~access capital markets, particularly~~ the short-term debt market and the variable rate pollution control revenue bond market.

Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Georgia Power) on CreditWatch with negative implications.

Financing Activities

In ~~February 2014,~~March 2015, Georgia Power entered into a $250 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes and the loan was repaid at maturity.

In April 2015, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power reoffered these bonds to the public in May 2015.

In April 2015, Georgia Power redeemed $125 million aggregate principal amount of its Series Y 5.80% Senior Notes due April 15, 2035.

In May 2015, Georgia Power reoffered to the public $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013, which had been previously purchased and held by Georgia Power since 2013.

In June 2015, Georgia Power made ~~initial~~additional borrowings under the FFB Credit Facility in an aggregate principal amount of ~~$1.0 billion.~~$600 million. The interest rate applicable to ~~$500~~the $600 million ~~of the initial advance under the FFB Credit Facility~~principal amount is ~~3.860%~~3.283% for an interest period that extends to ~~2044 and~~ the ~~interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029 and is expected to be reset from time to time thereafter through 2044. The~~ final maturity date ~~for all advances under the FFB Credit Facility is~~of February 20, 2044. The proceeds ~~of the initial borrowings under the FFB Credit Facility~~ were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. ~~In connection with its entry into the~~

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~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~agreements with the DOE and the FFB,~~ Georgia Power ~~incurred issuance costs~~settled $350 million of interest rate swaps related to this borrowing for approximately ~~$66~~$6 million, which will be amortized to interest expense over ~~the life of the borrowings under the FFB Credit Facility.~~10 years.

~~Under the Loan Guarantee Agreement, Georgia Power is subject~~Subsequent to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of Georgia Power or Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. See Note 6 to the financial statements of Georgia Power in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.

~~In February 2014, Georgia Power repaid three four-month floating rate bank loans in an aggregate principal amount of $400 million.~~

In June ~~2014, Georgia Power redeemed $17~~30, 2015, $97.925 million aggregate principal amount of the Development Authority of ~~Bartow~~Putnam County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), Second Series 1998 and $19.5 million aggregate principal amount of Development Authority of Appling County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Hatch Project), Second Series 2001.

In July 2014, Georgia Power reoffered to the public $40 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant SchererBranch Project), First Series ~~2009, which had been previously purchased~~1996, First Series 1997, Second Series 1997, and ~~held by Georgia Power since 2010.~~

Subsequent to September 30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amount of the swaps totaled $900 million.First Series 1998 were redeemed.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in thousands)						(in thousands)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	365,971		$	335,916		$	979,435		$	901,343		$	327		$	310		$	620		$	613
Wholesale revenues, non-affiliates	33,689			29,431			103,616			82,533			27			34			52			70
Wholesale revenues, affiliates	20,591			16,701			96,996			65,206			13			24			35			76
Other revenues	18,083			17,313			48,950			47,726			17			16			34			32
Total operating revenues	438,334			399,361			1,228,997			1,096,808			384			384			741			791
Operating Expenses:
Fuel	164,497			136,216			478,163			397,409			122			145			232			314
Purchased power, non-affiliates	26,813			17,180			56,605			41,369			25			14			50			30
Purchased power, affiliates	3,611			15,829			19,299			30,075			9			9			17			16
Other operations and maintenance	85,097			76,964			250,425			232,472			91			82			185			164
Depreciation and amortization	38,487			37,345			109,354			111,479			40			39			60			71
Taxes other than income taxes	31,229			28,051			83,786			75,437			28			26			56			53
Total operating expenses	349,734			311,585			997,632			888,241			315			315			600			648
Operating Income	88,600			87,776			231,365			208,567			69			69			141			143
Other Income and (Expense):
Allowance for equity funds used during construction	3,195			1,663			8,276			4,318			3			3			8			5
Interest expense, net of amounts capitalized	(12,859		)	(13,988		)	(39,417		)	(42,650		)	(12		)	(13		)	(26		)	(27		)
Other income (expense), net	(627		)	(337		)	(1,857		)	(2,704		)	(1		)	(1		)	(2		)	(1		)
Total other income and (expense)	(10,291		)	(12,662		)	(32,998		)	(41,036		)	(10		)	(11		)	(20		)	(23		)
Earnings Before Income Taxes	78,309			75,114			198,367			167,531			59			58			121			120
Income taxes	29,511			28,109			74,228			62,950			21			22			44			45
Net Income	48,798			47,005			124,139			104,581			38			36			77			75
Dividends on Preference Stock	2,251			2,251			6,752			5,453			3			2			5			4
Net Income After Dividends on Preference Stock	$	46,547		$	44,754		$	117,387		$	99,128		$	35		$	34		$	72		$	71

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

For the Three Months
Ended September 30, For the Nine Months
Ended September 30,
2014 2013 2014 2013
(in thousands) (in thousands)
Net Income $ 48,798
$ 47,005
$ 124,139
$ 104,581
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income,
net of tax of $58, $58, $175 and $238 respectively 93
93
279
379
Total other comprehensive income (loss) 93
93
279
379
Comprehensive Income $ 48,891
$ 47,098
$ 124,418
$ 104,960

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

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~~GULF POWER COMPANY~~

~~CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)~~

For the Nine Months
Ended September 30,
2014 2013
(in thousands)
Operating Activities:
Net income $ 124,139
$ 104,581
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total 115,093
116,626
Deferred income taxes 29,359
55,911
Allowance for equity funds used during construction (8,276 ) (4,318 )
Pension, postretirement, and other employee benefits 5,693
9,279
Stock based compensation expense 1,520
1,389
Other, net (2,667 ) 2,509
Changes in certain current assets and liabilities —
-Receivables (45,777 ) (49,690 )
-Prepayments 2,894
2,568
-Fossil fuel stock 44,300
24,475
-Materials and supplies 1,007
(2,683 )
-Prepaid income taxes 8,627
23,515
-Other current assets (1,022 ) —
-Accounts payable 10,097
(9,132 )
-Accrued taxes 21,858
20,648
-Accrued compensation 5,131
(5,974 )
-Over recovered regulatory clause revenues 6,834
(17,092 )
-Other current liabilities 4,939
5,258
Net cash provided from operating activities 323,749
277,870
Investing Activities:
Property additions (254,256 ) (205,161 )
Cost of removal, net of salvage (9,309 ) (12,563 )
Change in construction payables 1,688
6,752
Payments pursuant to long-term service agreements (6,097 ) (3,843 )
Other investing activities 89
306
Net cash used for investing activities (267,885 ) (214,509 )
Financing Activities:
Decrease in notes payable, net (44,395 ) (65,077 )
Proceeds —
Common stock issued to parent 50,000
40,000
Capital contributions from parent company 2,873
1,936
Preference stock —
50,000
Pollution control revenue bonds 42,075
63,000
Senior notes 200,000
90,000
Redemptions —
Pollution control revenue bonds (29,075 ) (63,000 )
Senior notes —
(90,000 )
Payment of preference stock dividends (6,752 ) (4,753 )
Payment of common stock dividends (92,400 ) (86,550 )
Other financing activities (2,951 ) (3,209 )
Net cash provided from (used for) financing activities 119,375
(67,653 )
Net Change in Cash and Cash Equivalents 175,239
(4,292 )
Cash and Cash Equivalents at Beginning of Period 21,753
32,167
Cash and Cash Equivalents at End of Period $ 196,992
$ 27,875
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3,699 and $2,291 capitalized for 2014 and 2013, respectively) $ 28,574
$ 33,433
Income taxes, net 35,940
(17,064 )
Noncash transactions — accrued property additions at end of period 34,876
30,846

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

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~~GULF POWER COMPANY~~

~~CONDENSED BALANCE SHEETS (UNAUDITED)~~

Assets At September 30,
2014 At December 31,
2013
(in thousands)
Current Assets:
Cash and cash equivalents $ 196,992
$ 21,753
Receivables —
Customer accounts receivable 98,357
64,884
Unbilled revenues 63,950
57,282
Under recovered regulatory clause revenues 52,531
48,282
Other accounts and notes receivable 10,131
8,620
Affiliated companies 7,405
8,259
Accumulated provision for uncollectible accounts (1,695 ) (1,131 )
Fossil fuel stock, at average cost 90,750
135,050
Materials and supplies, at average cost 53,928
54,935
Other regulatory assets, current 42,683
18,536
Prepaid expenses 8,374
33,186
Other current assets 3,805
6,120
Total current assets 627,211
455,776
Property, Plant, and Equipment:
In service 4,444,015
4,363,664
Less accumulated provision for depreciation 1,277,290
1,211,336
Plant in service, net of depreciation 3,166,725
3,152,328
Construction work in progress 433,299
280,626
Total property, plant, and equipment 3,600,024
3,432,954
Other Property and Investments 15,212
15,314
Deferred Charges and Other Assets:
Deferred charges related to income taxes 54,856
50,597
Prepaid pension costs 11,639
11,533
Other regulatory assets, deferred 322,370
340,415
Other deferred charges and assets 38,394
30,982
Total deferred charges and other assets 427,259
433,527
Total Assets $ 4,669,706
$ 4,337,571

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

~~Table of Contents~~

~~GULF POWER COMPANY~~

~~CONDENSED BALANCE SHEETS (UNAUDITED)~~

Liabilities and Stockholder's Equity At September 30,
2014 At December 31,
2013
(in thousands)
Current Liabilities:
Securities due within one year $ 75,000
$ 75,000
Notes payable 91,483
135,878
Accounts payable —
Affiliated 82,258
76,897
Other 55,713
47,038
Customer deposits 35,188
34,433
Accrued taxes —
Accrued income taxes 16,124
45
Other accrued taxes 29,777
7,486
Accrued interest 17,808
10,272
Accrued compensation 16,839
11,657
Other regulatory liabilities, current 9,136
13,408
Liabilities from risk management activities 7,337
6,470
Other current liabilities 41,716
22,972
Total current liabilities 478,379
441,556
Long-term Debt 1,369,447
1,158,163
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 746,866
734,355
Accumulated deferred investment tax credits 3,101
4,055
Employee benefit obligations 78,004
76,338
Other cost of removal obligations 233,926
228,148
Other regulatory liabilities, deferred 50,859
56,051
Deferred capacity expense 168,574
180,149
Other deferred credits and liabilities 78,671
77,126
Total deferred credits and other liabilities 1,360,001
1,356,222
Total Liabilities 3,207,827
2,955,941
Preference Stock 146,504
146,504
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — September 30, 2014: 5,442,717 shares
— December 31, 2013: 4,942,717 shares 483,060
433,060
Paid-in capital 557,664
552,681
Retained earnings 275,481
250,494
Accumulated other comprehensive loss (830 ) (1,109 )
Total common stockholder's equity 1,315,375
1,235,126
Total Liabilities and Stockholder's Equity $ 4,669,706
$ 4,337,571



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income	$	38	$	36	$	77	$	75
Other comprehensive income (loss)	—		—		—		—
Comprehensive Income	$	38	$	36	$	77	$	75

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

Table of Contents

GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	77		$	75
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	64			75
Deferred income taxes	40			20
Allowance for equity funds used during construction	(8		)	(5		)
Other, net	11			1
Changes in certain current assets and liabilities —
-Receivables	(15		)	(57		)
-Fossil fuel stock	6			39
-Prepaid income taxes	12			9
-Other current assets	1			2
-Accounts payable	(9		)	1
-Accrued taxes	15			12
-Accrued compensation	(10		)	—
-Over recovered regulatory clause revenues	—			9
-Other current liabilities	(1		)	(4		)
Net cash provided from operating activities	183			177
Investing Activities:
Property additions	(148		)	(159		)
Cost of removal, net of salvage	(7		)	(6		)
Other investing activities	(19		)	(5		)
Net cash used for investing activities	(174		)	(170		)
Financing Activities:
Increase in notes payable, net	4			3
Proceeds —
Common stock issued to parent	20			50
Pollution control revenue bonds	—			42
Short-term borrowings	40			—
Redemptions — Pollution control revenue bonds	—			(29		)
Payment of preference stock dividends	(5		)	(5		)
Payment of common stock dividends	(65		)	(62		)
Other financing activities	2			2
Net cash provided from (used for) financing activities	(4		)	1
Net Change in Cash and Cash Equivalents	5			8
Cash and Cash Equivalents at Beginning of Period	39			22
Cash and Cash Equivalents at End of Period	$	44		$	30
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3 and $2 capitalized for 2015 and 2014, respectively)	$	26		$	26
Income taxes, net	(9		)	17
Noncash transactions — Accrued property additions at end of period	28			31

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

Table of Contents

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	44		$	39
Receivables —
Customer accounts receivable	93			73
Unbilled revenues	77			58
Under recovered regulatory clause revenues	38			57
Other accounts and notes receivable	9			8
Affiliated companies	4			10
Accumulated provision for uncollectible accounts	(2		)	(2		)
Fossil fuel stock, at average cost	95			101
Materials and supplies, at average cost	55			56
Other regulatory assets, current	72			74
Prepaid expenses	35			40
Other current assets	3			2
Total current assets	523			516
Property, Plant, and Equipment:
In service	4,600			4,495
Less accumulated provision for depreciation	1,234			1,296
Plant in service, net of depreciation	3,366			3,199
Other utility plant, net	77			—
Construction work in progress	387			465
Total property, plant, and equipment	3,830			3,664
Other Property and Investments	15			15
Deferred Charges and Other Assets:
Deferred charges related to income taxes	59			56
Other regulatory assets, deferred	406			416
Other deferred charges and assets	41			41
Total deferred charges and other assets	506			513
Total Assets	$	4,874		$	4,708

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

Table of Contents

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Notes payable	$	154		$	110
Accounts payable —
Affiliated	72			87
Other	52			56
Customer deposits	36			35
Other accrued taxes	24			9
Accrued interest	10			11
Accrued compensation	13			23
Deferred capacity expense, current	22			22
Liabilities from risk management activities	32			37
Other current liabilities	21			23
Total current liabilities	436			413
Long-term Debt	1,370			1,370
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	852			800
Employee benefit obligations	119			121
Other cost of removal obligations	222			235
Other regulatory liabilities, deferred	49			49
Deferred capacity expense	152			163
Other deferred credits and liabilities	187			101
Total deferred credits and other liabilities	1,581			1,469
Total Liabilities	3,387			3,252
Preference Stock	147			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — June 30, 2015: 5,642,717 shares
— December 31, 2014: 5,442,717 shares	503			483
Paid-in capital	564			560
Retained earnings	274			267
Accumulated other comprehensive loss	(1		)	(1		)
Total common stockholder's equity	1,340			1,309
Total Liabilities and Stockholder's Equity	$	4,874		$	4,708

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

Table of Contents

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~THIRD~~SECOND QUARTER ~~2014~~2015 vs. ~~THIRD~~SECOND QUARTER ~~2013~~2014

AND

YEAR-TO-DATE ~~2014~~2015 vs. YEAR-TO-DATE ~~2013~~2014

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service ~~area~~territory located in northwest Florida and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Gulf Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, ~~given economic conditions,~~ and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, restoration following major storms, and fuel. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future. Capacity revenues represent the majority of Gulf Power's wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's co-ownership of Plant Scherer Unit 3 (205 MWs) through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively evaluating strategic alternatives related to this asset, including replacement wholesale contracts, but the expiration of current contracts could have a material negative impact on Gulf Power's earnings.

Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Gulf Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1.8 4.0 $18.3 18.4

Gulf Power's net income after dividends on preference stock for the ~~third~~second quarter ~~2014~~2015 was ~~$46.5~~$35 million compared to ~~$44.7~~$34 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to higher retail revenues related to a base rate increase, partially offset by higher ~~non-fuel~~ operations and maintenance expenses.

Gulf Power's net income after dividends on preference stock for year-to-date ~~2014~~2015 was ~~$117.4~~$72 million compared to ~~$99.1~~$71 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to a reduction in depreciation, as authorized by the Florida PSC, and higher retail revenues related to a base rate increase, ~~and colder weather in the first quarter 2014,~~ partially offset by higher ~~non-fuel~~ operations and maintenance expenses.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$30.1 8.9 $78.1 8.7

In the ~~third~~second quarter ~~2014,~~2015, retail revenues were ~~$366.0~~$327 million compared to ~~$335.9~~$310 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, retail revenues were ~~$979.4~~$620 million c~~ompared~~compared to ~~$901.3~~$613 million for the corresponding period in ~~2013.~~2014.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:


	Third Quarter 2014					Year-to-Date 2014				Second Quarter 2015				Year-to-Date 2015
	(in millions)			(% change)		(in millions)		(% change)		(in millions)		(% change)		(in millions)			(% change)
Retail – prior year	$	335.9				$	901.3			$	310			$	613
Estimated change resulting from –
Rates and pricing	11.0			3.3		33.6		3.7		7		2.3		10			1.7
Sales growth	6.1			1.8		7.7		0.9		2		0.6		—			—
Weather	(0.9		)	(0.3	)	10.0		1.1		4		1.3		4			0.6
Fuel and other cost recovery	13.9			4.1		26.8		3.0		4		1.3		(7		)	(1.2	)
Retail – current year	$	366.0		8.9	%	$	979.4	8.7	%	$	327	5.5	%	$	620		1.1	%

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – ~~"PSC~~"Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.

Revenues associated with changes in rates and pricing increased in the ~~third~~second quarter and year-to-date ~~2014~~2015 when compared to the corresponding periods in ~~2013~~2014 primarily due to an increase in retail base ~~revenues resulting from the retail~~rates effective in January 2015, as authorized in a settlement agreement for Gulf Power's 2013 base rate ~~increase effective January 2014~~case, and higher revenues associated with an increase in the environmental and energy conservation cost recovery clause ~~rate~~rates effective in January ~~2014.~~2015.

Revenues attributable to changes in sales increased in the ~~third~~second quarter ~~2014~~2015 when compared to the corresponding period in ~~2013.~~2014. Weather-adjusted KWH energy sales to residential and commercial customers increased ~~5.8%~~3.0% and ~~2.6%~~1.6%, respectively, due to customer growth and higher ~~weather-adjusted use per~~ customer usage. KWH energy sales to industrial customers decreased 2.8% primarily due to increased customer co-generation.

Revenues attributable to changes in sales remained essentially flat year-to-date 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH energy sales to residential and commercial customers decreased 0.9% and 0.1%, respectively, due to lower customer usage, partially offset by customer growth. KWH energy sales to industrial customers ~~increased 6.4%~~decreased 2.7% primarily due to ~~decreased~~increased customer ~~co-generation and changes in customers' operations.~~

Revenues attributable to changes in sales increased year-to-date 2014 when compared to the corresponding period in 2013. Weather-adjusted KWH energy sales to residential customers increased 1.8% due to higher weather-adjusted use per customer and customer growth. Weather-adjusted KWH energy sales to commercial customers increased 0.3% due to customer growth, partially offset by a decline in weather-adjusted use per customer. KWH energy sales to industrial customers increased 11.0% due to decreased customer co-generation and changes in customers' operations.co-generation.

Fuel and other cost recovery revenues increased in the ~~third~~second quarter ~~2014 and year-to-date 2014~~2015 when compared to the corresponding ~~periods~~period in ~~2013~~2014 primarily due to higher revenues associated with ~~recoverable fuel costs for~~ increased ~~generation and~~recoverable purchased power capacity costs, partially offset by lower revenues associated with fuel costs as the result of decreased generation and lower ~~recoverable costs under Gulf Power's~~purchased power energy ~~conservation~~costs. For year-to-date 2015, fuel and ~~environmental~~other cost recovery ~~clauses. Recoverable~~revenues decreased when compared to the corresponding period in 2014 primarily due to lower revenues associated with fuel costs ~~include the effect~~as a result of ~~a 2013 payment received pursuant to the resolution of a contract dispute.~~decreased generation and lower purchased power energy costs, partially offset by higher revenues associated with purchased power capacity costs.

Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See ~~FUTURE EARNINGS POTENTIAL – "PSC~~Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" ~~of Gulf Power~~ in Item 78 of the Form 10-K for additional information.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$4.3 14.5 $21.1 25.5

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~~wholesale earnings. Energy is generally sold at variable ~~cost.~~cost and does not have a significant impact on wholesale earnings. Short-term opportunity sales are made at market-based rates that generally provide a margin above Gulf Power's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.

In the ~~third~~second quarter ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$33.7~~$27 million compared to ~~$29.4~~$34 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~25.4% increase~~43.5% decrease in KWH sales ~~primarily to wholesale customers~~resulting from lower sales under the Plant Scherer Unit 3 long-term sales ~~agreements.~~agreements due to a planned outage and lower natural gas prices that led to increased customer-owned generation.

For y~~ear-to-date 2014,~~year-to-date 2015, wholesale revenues from sales to non-affiliates were ~~$103.6~~$52 million compared to ~~$82.5~~$70 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~59.9% increase~~52.1% decrease in KWH sales ~~due to lower-priced supply alternatives~~resulting from lower sales under the ~~Southern Company system's resources compared to wholesale market prices and a planned outage at~~ Plant Scherer Unit 3 ~~in 2013.~~long-term sales agreements due to a planned outage and lower natural gas prices that led to increased customer-owned generation.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$3.9 23.3 $31.8 48.8

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold.

In the ~~third~~second quarter ~~2014,~~2015, wholesale revenues from sales to affiliates were ~~$20.6~~$13 million compared to ~~$16.7~~$24 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to ~~an 11.7% increase~~a 29.9% decrease in KWH sales that resulted from planned outages for Gulf Power generation resources and a 20.6% decrease in the price of energy sold to affiliates due to ~~higher marginal generation costs and~~lower power pool interchange rates resulting from lower natural gas prices.

For year-to-date 2015, wholesale revenues from sales to affiliates were $35 million compared to $76 million for the corresponding period in 2014. The decrease was primarily due to a ~~10.3% increase~~37.2% decrease in KWH sales that resulted from ~~more~~planned outages for Gulf Power generation ~~dispatched to serve affiliated companies' higher weather-related energy demand.~~

~~For year-to-date 2014, wholesale revenues from sales to affiliates were~~ ~~$97.0 million compared to $65.2 million for the corresponding period in 2013. The increase was primarily due to~~resources and a ~~29.6% increase~~26.1% decrease in the price of energy sold to affiliates due to ~~higher marginal generation costs and a 14.8% increase in KWH sales that resulted~~lower power pool interchange rates resulting from ~~more Gulf Power generation dispatched to serve affiliated companies' higher weather-related energy demand in 2014.~~lower natural gas prices.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses


	Third Quarter 2014 vs. Third Quarter 2013					Year-to-Date 2014 vs. Year-to-Date 2013					Second Quarter 2015 vs. Second Quarter 2014					Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)		(change in millions)			(% change)		(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	28.3		20.8		$	80.8		20.3		$	(23	)	(15.9	)	$	(82	)	(26.1	)
Purchased power – non-affiliates	9.6			56.1		15.2			36.8		11			78.6		20			66.7
Purchased power – affiliates	(12.2		)	(77.2	)	(10.8		)	(35.8	)	—			—		1			6.3
Total fuel and purchased power expenses	$	25.7				$	85.2				$	(12	)			$	(61	)

In the ~~third~~second quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$194.9~~$156 million compared to ~~$169.2~~$168 million for the corresponding period in ~~2013. Total fuel and purchased power expenses for~~2014. The decrease was primarily the ~~third quarter 2013 included the effect~~result of a ~~2013 payment received pursuant to~~$9 million decrease in the ~~resolution of a contract dispute. Excluding that effect, higher~~ volume of KWHs generated and purchased ~~increased expenses $12.5 million in the third quarter 2014~~ due to ~~more~~planned outages for Gulf ~~Power~~Power's generation ~~dispatched to serve affiliated companies' higher weather-related demand. This increase was offset by~~and a ~~$7.3~~resource contracted under a PPA and a $3 million net decrease due to athe lower average cost of fuel and purchased power.

For year-to-date ~~2014,~~2015, total fuel and purchased power expenses were ~~$554.1~~$299 million compared to ~~$468.9~~$360 million for the corresponding period in ~~2013. Total fuel and purchased power expenses for~~2014. The decrease was primarily the ~~first nine months of 2013 included the effect~~result of a ~~2013 payment received pursuant to~~$50 million decrease in the ~~resolution of a contract dispute. Excluding that effect, higher~~ volume of KWHs generated and purchased ~~increased expenses $62.3 million year-to-date 2014 primarily~~ due to ~~more~~planned outages for Gulf ~~Power~~Power's generation ~~dispatched to serve affiliated companies' higher demand as~~and a ~~result of colder weather in the first quarter 2014~~resource contracted under a PPA and ~~warmer weather in the third quarter 2014 compared~~an $11 million net decrease due to the ~~corresponding periods in 2013. The increased expenses also included a $2.4 million increase due to a higher~~lower average cost of fuel and purchased power.

Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel cost and purchased power capacity recovery clauses. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" ~~of Gulf Power~~ in Item 8 of the Form 10-K for additional information.

Details of Gulf Power's generation and purchased power were as follows:


	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013	Second Quarter 2015	Second Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (millions of KWHs)	3,085	2,692	8,717	6,978	2,360	2,670	4,596	5,632
Total purchased power (millions of KWHs)	1,479	1,593	4,190	4,602	1,336	1,281	2,594	2,711
Sources of generation (percent) –
Coal	66	64	69	62	61	69	60	70
Gas	34	36	31	38	39	31	40	30
Cost of fuel, generated (cents per net KWH) –
Coal^(a)	3.83	3.33	4.08	4.09	4.05	4.09	4.02	4.21
Gas	4.16	4.17	3.95	4.05	4.38	3.99	4.17	3.82
Average cost of fuel, generated (cents per net KWH)^(a)	3.94	3.64	4.04	4.07	4.18	4.06	4.08	4.09
Average cost of purchased power (cents per net KWH)^(b)	4.96	4.48	4.83	4.01
Average cost of purchased power (cents per net KWH)^(*)					4.25	4.71	4.31	4.75


~~(a)~~	~~2013 cost of coal includes the effect of a payment received in 2013 pursuant to the resolution of a coal contract dispute.~~


~~(b)~~(*)	Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.

Fuel

In the second quarter 2015, fuel expense was $122 million compared to $145 million for the corresponding period in 2014. The decrease was primarily due to an 11.6% decrease in the volume of KWHs generated due to planned outages for Gulf Power's generation and a resource contracted under a PPA. This was partially offset by a 3.0% increase in the average cost of fuel due to higher natural gas prices per KWH generated, which includes firm gas transportation and storage.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Fuel~~

~~In the third quarter 2014,~~For year-to-date 2015, fuel expense was ~~$164.5~~$232 million compared to ~~$136.2~~$314 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to an 18.4% decrease in the volume of KWHs generated due to planned outages for Gulf Power's generation and a resource contracted under a PPA.

Purchased Power – Non-Affiliates

In the second quarter 2015, purchased power expense from non-affiliates was $25 million compared to $14 million for the corresponding period in 2014. The increase was primarily due to a 14.6% higher volume of KWHs generated due to more Gulf Power generation dispatched to serve affiliated companies' higher demand resulting from warmer weather in the third quarter 2014. The fuel expense for the third quarter 2013 included the effect of a 2013 payment received pursuant to the resolution of a coal contract dispute. Excluding this effect, the average cost of fuel decreased 10.5% primarily due to lower-priced coal supply.

~~For year-to-date 2014, fu~~el expense was $478.2 million compared to $397.4 million for the corresponding period in 2013. The increase was primarily due to a 24.9% higher volume of KWHs generated primarily due to more Gulf Power generation dispatched to serve affiliated companies' higher demand resulting from colder weather in the first quarter 2014 and warmer weather in the third quarter 2014 compared to the corresponding periods in 2013. The fuel expense for year-to-date 2013 included the effect of a 2013 payment received pursuant to the resolution of a coal contract dispute. Excluding this effect, the average cost of fuel decreased 7.6% primarily due to lower-priced coal supply.

~~Purchased Power – Non-Affiliates~~

In the third quarter 2014, purchased power expense from non-affiliates was $26.8 million compared to $17.2 million for the corresponding period in 2013. The increase was primarily due to a 30.4% increase in the average cost per KWH purchased, which included a $9.7$10 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another ~~PPA.~~PPA in mid-2014. The increase was partially offset by a ~~3.3%~~7.9% decrease in the volume of KWHs purchased due to ~~the expiration of~~ a ~~Gulf Power~~planned outage for a resource contracted under a PPA.

For year-to-date ~~2014,~~2015, purchased power expense from non-affiliates was ~~$56.6~~$50 million compared to ~~$41.4~~$30 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to a ~~34.9% increase in the average cost per KWH purchased, which included a $12.8~~$26 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another ~~PPA. This~~PPA in mid-2014. The increase was partially offset by ~~an 11.7%~~a 17.4% decrease in the volume of KWHs purchased due to ~~colder regional weather conditions in the first quarter 2014 which limited the availability of market resources.~~a planned outage for a resource contracted under a PPA.

Purchased Power – Affiliates

In the ~~third~~second quarter 2015 and the corresponding period in 2014, purchased power expense from affiliates was ~~$3.6 million compared to $15.8 million for the corresponding period in 2013.~~$9 million. The ~~decrease was primarily~~volume of KWHs purchased increased 55.4% due to planned outages for Gulf Power's generation and a ~~67.0%~~resource contracted under a PPA. The increase was offset by a 39.1% decrease in the average cost per KWH purchased ~~which included a $9.2 million reduction in capacity costs primarily associated with the expiration of an existing PPA, and a 31.8% decrease in the volume of KWHs purchased~~ due to ~~increased generation from Gulf Power's owned units in 2014.~~lower power pool interchange rates.

For year-to-date ~~2014,~~2015, purchased power expense from affiliates was ~~$19.3~~$17 million compared to ~~$30.1~~$16 million for the corresponding period in ~~2013.~~2014. The ~~decrease~~increase was primarily due to a 44.8% decrease in the average cost per KWH purchased, which included a $12.8 million reduction in capacity costs primarily associated with the expiration of an existing PPA, partially offset by a 14.5%68.5% increase in the volume of KWHs purchased due to ~~colder weather driving higher demand~~planned outages for Gulf Power's generation and a resource contracted under a PPA, largely offset by a 36.0% decrease in the ~~first quarter 2014 compared~~average cost per KWH purchased due to ~~the corresponding period in 2013.~~lower power pool interchange rates.

Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

Other Operations and Maintenance Expenses

In the second quarter 2015, other operations and maintenance expenses were $91 million compared to $82 million for the corresponding period in 2014. The increase was primarily due to increases of $6 million in routine and planned maintenance expenses at generation and distribution facilities, $1 million in energy services expenses, $1 million in customer service expenses, and $1 million in employee benefits including pension costs.

For year-to-date 2015, other operations and maintenance expenses were $185 million compared to $164 million for the corresponding period in 2014. The increase was primarily due to increases of $11 million in routine and planned maintenance expenses at generation facilities, $2 million in energy services expenses, $2 million in customer service expenses, and $2 million in employee benefits including pension costs.

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~~Other Operations and Maintenance~~ Expenses

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$8.2 10.6 $17.9 7.7

In the third quarter 2014, other operations and maintenance expenses were $85.1 million compared to $76.9 million for the corresponding period in 2013. The increase was primarily due to increases of $7.0 million in routine and planned maintenance expense at generation facilities, partially offset by a decrease of $1.8 million in marketing programs.

For year-to-date 2014, other operations and maintenance expenses were $250.4 million compared to $232.5 million for the corresponding period in 2013. The increase was primarily due to a $20.0 million increase in routine and planned maintenance expenses at generation, transmission, and distribution facilities, a $2.3 million net increase in employee compensation and benefits including pension costs, a $2.1 million increase in customer uncollectibles and collection expenses, and a $2.0 million increase in transmission service related to a third party PPA. These increases were partially offset by a $5.3 million decrease in marketing programs and a $2.9 million decrease in other energy services expenses.

~~The year-to-date 2014 increased expense~~ from routine and planned maintenance at distribution facilities included $3.7 million in environmental projects that did not have a significant impact on net income since the expense was offset by environmental revenues through Gulf Power's environmental cost recovery clause. The increased expense from transmission service did not have a significant impact on net income since the expense was offset by purchased power capacity revenues through Gulf Power's purchased power capacity recovery clause. The decreased expense from marketing programs did not have a significant impact on net income since the expense was offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause. The decreased expense from other energy services did not have a significant impact on ~~net income~~earnings since ~~the expense was~~they were generally offset by associated revenues. See Note 3(F) to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Purchased Power Capacity Recovery," "– Environmental Cost Recovery," and "– Energy Conservation Cost Recovery" in Item 8 of the Form 10-KCondensed Financial Statements herein for additional ~~information.~~information related to pension costs.

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1.2 3.1 $(2.1) (1.9)

In the ~~third~~second quarter ~~2014,~~2015, depreciation and amortization was ~~$38.5~~$40 million compared to ~~$37.3~~$39 million for the corresponding period in ~~2013.~~2014. The increase in depreciation and amortization was primarily attributable to property additions at generation, transmission, and distribution facilities.

For year-to-date ~~2014,~~2015, depreciation and amortization was ~~$109.4~~$60 million compared to ~~$111.5~~$71 million for the corresponding period in ~~2013.~~2014. As authorized by the Florida PSC in a ~~2013 rate order,~~settlement agreement, Gulf Power recorded a ~~$5.4~~$19.6 million reduction in depreciation ~~expense~~in the first half of 2015 as compared to $5.4 million in the corresponding period in 2014. ~~This~~The decrease was partially offset by increases of ~~$3.3~~$3 million ~~in depreciation and amortization~~ primarily attributable to property additions at generation, transmission, and distribution facilities.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – ~~"PSC~~"Retail Regulatory Matters – Retail Base Rate Case" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" herein for additional information.

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Taxes Other Than Income Taxes

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$3.2 11.3 $8.4 11.1

In the ~~third~~second quarter ~~2014,~~2015, taxes other than income taxes were ~~$31.2~~$28 million compared to ~~$28.0~~$26 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, taxes other than income taxes were ~~$83.8~~$56 million compared to ~~$75.4~~$53 million for the corresponding period in ~~2013.~~2014. The increases were primarily due to increases in property taxes, franchise fees, and gross receipts ~~taxes as a result of higher retail revenues.~~taxes. Franchise fees and gross receipts taxes have no impact on net income.

Allowance for Equity Funds Used During Construction

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1.5 92.1 $4.0 91.7

~~In the third quarter 2014,~~For year-to-date 2015, AFUDC equity was ~~$3.2~~$8 million compared to ~~$1.7~~$5 million for the corresponding period in ~~2013. For year-to-date 2014, AFUDC equity~~2014. The increase was ~~$8.3 million compared to $4.3 million for the corresponding period in 2013. These increases were~~ primarily due to increased construction related to environmental control projects at generation facilities.

~~Income Taxes~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$1.4 5.0 $11.2 17.9

~~In the third quarter 2014, income taxes were $29.5 million compared to $28.1 million for the corresponding period in 2013. For year-to-date 2014, income taxes were $74.2 million compared to $63.0 million for the corresponding period in 2013.~~ ~~These increases were~~ ~~primarily due to higher pre-tax earnings.~~

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of selling electricity. These factors include Gulf Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining and

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growing sales which isare subject to a number of factors. These factors include weather, competition, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, the rate of economic growth or decline in Gulf Power's service territory, and the successful remarketing of wholesale capacity as current contracts expire. Changes in regional and global economic conditions may impact sales for Gulf Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.

Gulf Power's wholesale business consists of two types of agreements. The first type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's co-ownership of ~~a unit with Georgia Power at~~ Plant Scherer Unit 3 (205 MWs) and consist of both capacity and energy sales. Capacity revenues represent the majority of Gulf Power's

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wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's ~~ownership~~co-ownership of that unit through 2015 and ~~57%~~41% through ~~2018. The second type, referred to as requirements service, provides that~~2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power ~~serves~~is actively evaluating strategic alternatives related to this asset, including replacement wholesale contracts, but the ~~customer's capacity and energy requirements from other~~expiration of current contracts could have a material negative impact on Gulf ~~Power resources.~~Power's earnings. In the event some portion of Gulf Power's ownership in Plant Scherer is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely ~~basis.~~basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such regulatory or legislative changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" and ~~"PSC~~"Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR) ~~and the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM)~~.

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

~~On September 17, 2014,~~June 12, 2015, the EPA published a ~~supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement~~final rule requiring ~~the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require~~affected states ~~subject to the rule~~ (including Florida, Georgia, and Mississippi) to revise ~~their~~or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSM ~~provisions within 18 months after issuance of the final rule.~~by no later than November 22, 2016. The ultimate impact of the ~~proposed SSM~~final rule will depend on the ~~specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.~~

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Water Quality~~

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outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.

On June 29, 2015, the U.S. Supreme Court issued a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate impact of this decision cannot be determined at this time.

On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Florida and Georgia. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of federal jurisdiction under the ~~CWA. If finalized as proposed,~~CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. ~~In addition, the~~The rule ~~as proposed could have significant impacts on economic development projects which could affect customer demand growth.~~becomes effective August 28, 2015. The ultimate impact of the ~~proposed~~final rule will depend on ~~the specific requirements of the final rule and~~ the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – ~~Environmental Statutes and Regulations – Water Quality"~~ Coal Combustion Residuals" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's ~~rulemaking for cooling water intake structures.~~regulation of CCR.

On ~~August 15, 2014,~~April 17, 2015, the EPA published athe Disposal of Coal Combustion Residuals from Electric Utilities final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became(CCR Rule) in the Federal Register, setting October 19, 2015 as the effective ~~October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation~~date of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units.CCR Rule. The ultimate impact of ~~this rule will depend on~~ the ~~outcome of any legal challenges and~~CCR Rule cannot be determined at this ~~time.~~timeand will depend on Gulf Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Gulf Power recorded incremental asset retirement obligations (ARO) of approximately $75 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Gulf Power expects to periodically update these estimates.

In connection with a proposed settlement related to the closure of Plant Scholz, Gulf Power may incur additional AROs associated with CCR of approximately $15 million to $35 million.

See Note (A) to the Condensed Financial Statements herein for additional information regarding Gulf Power's AROs.

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Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's ~~current and~~ proposed regulation of ~~GHG emissions under the Clean Air Act.~~CO₂ from fossil-fuel-fired electric generating units.

On ~~June 18, 2014,~~August 3, 2015, the EPA ~~published~~released pre-publication versions of two final rules that would limit CO₂ emissions from fossil fuel-fired electric generating units. One of the ~~proposed Clean Power Plan, setting forth~~final rules contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to ~~address CO~~₂ ~~emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final~~meet EPA-mandated CO₂ emission ~~rate goals~~rates for existing units. The EPA's final guidelines require state plans to ~~be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposed~~meet interim CO₂ performance ~~standards for modified~~rates between 2022 and ~~reconstructed fossil fuel-fired electric generating units. The~~2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, ~~that~~which could ~~impact~~affect future unit retirement and replacement decisions. ~~Also, additional compliance costs could affect~~Gulf Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated ~~rates. Further, any resulting higher costs that are recovered~~rates or through ~~regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.~~

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system.market-based contracts. However, the ultimate financial and operational impact of the ~~Clean~~final rules on Gulf Power ~~Plan proposed guidelines on the Southern Company system~~ cannot be determined at this time and will ~~be dependent upon~~depend on numerous ~~factors. These~~ factors ~~include:~~including the ~~structure, timing, and content~~Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final ~~guidelines; individual state implementation of these~~ guidelines, including the potential that state ~~implementation~~ plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and ~~emissions-related~~emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

FERC Matters

Gulf Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Gulf Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Gulf Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Gulf Power) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including Gulf Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June ~~23, 2014,~~26, 2015 filed their response with the ~~U.S. Supreme Court struck down a portion~~FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the ~~EPA's program~~Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for ~~GHG permitting~~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 Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority toForm 10-K for additional information.

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~~tailor the statutory permitting thresholds. The ultimate impact of the U.S. Supreme Court's decision cannot be determined at this time.~~

~~PSC Matters~~

Retail Base Rate Case

~~See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.~~

In December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a ~~$5.4~~$19.6 million reduction in depreciation expense in the first ~~nine~~six months of ~~2014.~~2015.

Cost Recovery Clauses

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – ~~"PSC~~"Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. ~~The recovery balance of each regulatory clause for Gulf Power is reported in~~See Note (B) to the Condensed Financial Statements ~~herein.~~herein for additional information.

Renewables

On ~~October 22, 2014,~~April 16, 2015, the Florida PSC approved ~~Gulf Power's annual rate clause request~~three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. On May 5, 2015, the Florida PSC approved an energy purchase agreement for ~~its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2015. The net effect~~up to 178 MWs of ~~the approved changes is a $41.2 million increase~~wind generation in ~~annual revenue for 2015. The increased revenues will not have a significant impact on net income since most of the revenues~~central Oklahoma. Purchases under these agreements will be ~~offset by expenses.~~

~~Retail Fuel Cost Recovery~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery" of~~for energy only and will be recovered through Gulf Power in Item 7 and Note 1 and Note 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Cost Recovery Clauses – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

~~Gulf Power has established~~Power's fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first half of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested for 2014. Under recovered fuel costs at September 30, 2014 totaled $41.3 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.mechanism.

Other Matters

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

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occurred throughout the U.S. ~~In particular, personal injury, property damage, and other~~This litigation included claims for damages alleged to have been caused by CO₂ and other emissions, ~~coal combustion residuals,~~CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such ~~matters, have become more frequent.~~matters.

The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See ~~the Notes~~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, Contingent Obligations, and Pension and Other Postretirement Benefits.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Asset Retirement Obligations

The liability for AROs primarily relates to Gulf Power's combustion turbines at its Pea Ridge facility and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Gulf Power has retirement obligations related to various landfill sites, a barge unloading dock, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. Gulf Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Gulf Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Gulf Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Gulf Power considers the liabilities for AROs to be critical accounting estimates.

See Note 1 to the financial statements of Gulf Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Recently Issued Accounting Standards

~~On May 28, 2014, the~~The Financial Accounting Standards ~~Board issued~~Board's (FASB) ASC 606, Revenue from Contracts with Customers~~. ASC 606~~, revises the accounting for revenue recognition ~~and is~~ effective for fiscal years beginning after December 15, ~~2016.~~2017. Gulf Power ~~is currently evaluating~~continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Gulf Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Gulf Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at ~~September~~June 30, ~~2014.~~2015. Gulf Power intends to continue to monitor its access to short-term and long-term

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

capital markets as well as ~~its~~ bank credit ~~arrangements~~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 ~~$323.7~~$183 million for the first ~~nine~~six months of ~~2014~~2015 compared to ~~$277.9~~$177 million for the corresponding period in ~~2013.~~2014. The ~~$45.8~~$6 million increase in net cash was primarily due to ~~changes~~increases in cash flows related to ~~clause~~cost recovery ~~a decrease in fossil fuel stock,~~clauses and an increase in ~~accounts payable,~~deferred income taxes related to bonus depreciation, partially offset by ~~a decrease~~decreases in ~~deferred income taxes.~~the timing of fossil fuel stock purchases, accrued compensation, and accounts payable. Net cash used for investing activities totaled ~~$267.9~~$174 million in the first ~~nine~~six months of ~~2014~~2015 primarily due to property additions to utility plant. Net cash ~~provided from~~used for financing activities totaled ~~$119.4~~$4 million for the first ~~nine~~six months of ~~2014~~2015 primarily due to ~~the issuance of long-term debt and common stock, partially offset by~~ the payment of common stock dividends, partially offset by an increase in notes payable and the ~~redemption~~issuance of ~~long-term debt.~~common stock to Southern Company. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first ~~nine~~six months of ~~2014~~2015 include increases of ~~$211.3 million in long-term debt, $175.2 million in cash and cash equivalents, $167.1~~$166 million in net property, plant, and equipment, ~~and $50.0~~

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~~GULF POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

$86 million in ~~common stock due~~other deferred credits and other liabilities primarily related to AROs associated with the ~~issuance of common stock~~CCR Rule, $52 million in accumulated deferred income tax liabilities primarily related to ~~Southern Company. Decreases included $44.4~~bonus depreciation, and $44 million in notes ~~payable and $44.3 million in fossil fuel stock resulting from an increase in KWH generation.~~payable.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately ~~$75~~$60 million ~~was~~will be required through ~~September~~June 30, ~~2015~~2016 to fund ~~maturities~~announced redemptions of long-term debt. ~~Subsequent to September 30, 2014, Gulf Power repaid at maturity the $75 million of securities due within one year.~~See "Financing Activities" herein for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.

Gulf Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity ~~needs.~~needs, including its commercial paper program which is supported by bank credit facilities.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At ~~September~~June 30, ~~2014,~~2015, Gulf Power had approximately ~~$197.0~~$44 million of cash and cash equivalents. Committed credit arrangements with banks at ~~September~~June 30, ~~2014~~2015 were as follows:


Expires^(a)	Expires^(a)											Executable Term Loans				Due Within One Year				Expires^(a)											Executable Term Loans				Due Within One Year
2014		2015		2016		2017		Total		Unused		One Year		Two Years		Term Out		No Term Out
2015																				2015	2016		2017		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)	(in millions)							(in millions)				(in millions)				(in millions)				(in millions)					(in millions)				(in millions)				(in millions)
$	20	$	60	$	165	$	30	$	275	$	275	$	50	$	—	$	50	$	30	20	$	225	$	30	$	275	$	275	$	50	$	—	$	50	$	195


~~(a)~~	~~No credit arrangements expire in 2018.~~

See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

Most of the unused credit arrangements with banks is allocated to provide liquidity support to Gulf Power's variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $69 million. In addition, at June 30, 2015, Gulf Power had approximately $46 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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~~GULF POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

or guarantee obligations over a specified threshold. Gulf Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration.

A portion of the unused credit arrangements with banks provide liquidity support to Gulf Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2014 was approximately $69 million. In ~~addition, at September 30, 2014,~~connection therewith, Gulf Power ~~had $78 million of fixed rate pollution control revenue bonds that are required to be remarketed within~~may extend the ~~next 12 months.~~maturity dates and/or increase or decrease the lending commitments thereunder.

Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:

Short-term Debt at
September 30, 2014
Short-term Debt During the Period^(a)

Amount
Outstanding

Weighted
Average
Interest
Rate

Average
Outstanding

Weighted
Average
Interest
Rate

Maximum
Amount
Outstanding
(in millions) (in millions) (in millions)
Commercial paper $ 92
0.2% $ 106
0.2% $ 139



	Short-term Debt at June 30, 2015				Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	114	0.3	%	$	133	0.3	%	$	175
Short-term bank debt	40		1.3	%	10		1.3	%	40
Total	$	154	0.6	%	$	143	0.4	%


~~(a)~~(*)	Average and maximum amounts are based upon daily balances during the three-month period ended ~~September~~June 30, ~~2014.~~2015.

~~Management~~Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, ~~short-term bank notes,~~ and ~~cash.~~operating cash flows.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

The maximum potential collateral requirements under these contracts at ~~September~~June 30, ~~2014~~2015 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB- and/or Baa3	$	74	$	91
Below BBB- and/or Baa3	425		481

Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Gulf Power) on CreditWatch with negative implications.

Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the ~~third~~second quarter ~~2014~~and year-to-date 2015 has not changed materially compared to the December 31, ~~2013~~2014 reporting period. Gulf Power's exposure to market volatility in

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~~GULF POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreements shift substantially all fuel cost responsibility to the purchaser. However, Gulf Power could become exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and ~~57%~~41% through ~~2018.~~2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively pursuing replacement wholesale contracts but the expiration of current contracts could have a material negative impact on Gulf Power's earnings. In the event some portion of Gulf Power's ownership in Plant Scherer is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market. For an in-depth discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.

Financing Activities

In January ~~2014,~~2015, Gulf Power issued ~~500,000~~200,000 shares of common stock to Southern Company and realized proceeds of ~~$50~~$20 million. The proceeds were used to repay a portion of Gulf Power's short-term debt and for other general corporate purposes, including Gulf Power's continuous construction program.

In ~~April 2014,~~June 2015, Gulf Power ~~executed~~entered into a three-month floating rate bank loan ~~agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075~~bearing interest based on one-month LIBOR. This short-term loan was for $40 million aggregate principal amount ~~of Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 for~~and the ~~benefit of Gulf Power. The~~ proceeds were used for credit support, working capital, and other general corporate purposes.

Subsequent to ~~redeem $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).~~

In June ~~2014,~~30, 2015, Gulf Power ~~reoffered to the public~~purchased and held $13 million aggregate principal amount of ~~MBFC~~Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Refunding Bonds ~~Series 2012~~ (Gulf Power Company Project), ~~which had been previously purchased and held by~~Series 2012. Gulf Power ~~since December 2013.~~reoffered these bonds on July 16, 2015.

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~~In September 2014,~~GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and ~~storm-recovery,~~storm recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in thousands)						(in thousands)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	228,331		$	230,710		$	646,695		$	613,274		$	189		$	211		$	357		$	418
Wholesale revenues, non-affiliates	82,952			82,937			254,642			219,984			63			75			141			172
Wholesale revenues, affiliates	38,639			6,999			81,593			31,242			18			20			45			43
Other revenues	4,701			4,560			13,829			13,075			5			5			9			9
Total operating revenues	354,623			325,206			996,759			877,575			275			311			552			642
Operating Expenses:
Fuel	168,708			138,148			458,976			384,905			115			143			229			290
Purchased power, non-affiliates	3,475			2,077			16,163			5,222			2			1			3			13
Purchased power, affiliates	1,966			14,691			16,630			28,302			2			6			4			15
Other operations and maintenance	65,758			56,907			191,923			166,175			68			61			144			125
Depreciation and amortization	23,382			22,202			70,318			67,644			30			24			57			47
Taxes other than income taxes	22,344			21,071			63,198			60,760			23			20			48			41
Estimated loss on Kemper IGCC	418,000			150,000			798,000			1,062,000			23			—			32			380
Total operating expenses	703,633			405,096			1,615,208			1,775,008			263			255			517			911
Operating Income (Loss)	(349,010		)	(79,890		)	(618,449		)	(897,433		)	12			56			35			(269		)
Other Income and (Expense):
Allowance for equity funds used during construction	32,223			32,624			107,685			87,740			25			37			53			75
Interest expense, net of amounts capitalized	(9,416		)	(8,728		)	(34,071		)	(29,526		)	30			(13		)	19			(25		)
Other income (expense), net	(7,764		)	(375		)	(11,496		)	(4,184		)	(1		)	(1		)	(2		)	(4		)
Total other income and (expense)	15,043			23,521			62,118			54,030			54			23			70			46
Earnings (Loss) Before Income Taxes	(333,967		)	(56,369		)	(556,331		)	(843,403		)	66			79			105			(223		)
Income taxes (benefit)	(139,330		)	(32,687		)	(253,007		)	(355,156		)	16			16			20			(114		)
Net Income (Loss)	(194,637		)	(23,682		)	(303,324		)	(488,247		)	50			63			85			(109		)
Dividends on Preferred Stock	433			433			1,299			1,299			1			1			1			1
Net Income (Loss) After Dividends on Preferred Stock	$	(195,070	)	$	(24,115	)	$	(304,623	)	$	(489,546	)	$	49		$	62		$	84		$	(110	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

For the Three Months
Ended September 30, For the Nine Months
Ended September 30,
2014 2013 2014 2013
(in thousands) (in thousands)
Net Income (Loss) $ (194,637 ) $ (23,682 ) $ (303,324 ) $ (488,247 )
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income,
net of tax of $131, $131, $394 and $394, respectively 212
212
637
637
Total other comprehensive income (loss) 212
212
637
637
Comprehensive Income (Loss) $ (194,425 ) $ (23,470 ) $ (302,687 ) $ (487,610 )



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income (Loss)	$	50	$	63	$	85	$	(109	)
Other comprehensive income (loss)	—		—		—		—
Comprehensive Income (Loss)	$	50	$	63	$	85	$	(109	)

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

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

For the Nine Months
Ended September 30,
2014 2013
(in thousands)
Operating Activities:
Net income (loss) $ (303,324 ) $ (488,247 )
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total 77,774
68,436
Deferred income taxes 158,552
(391,143 )
Investment tax credits (108,171 ) 45,228
Allowance for equity funds used during construction (107,685 ) (87,740 )
Regulatory assets associated with Kemper IGCC (51,875 ) (23,545 )
Estimated loss on Kemper IGCC 798,000
1,062,000
Kemper regulatory deferral 111,828
61,997
Other, net 12,105
23,697
Changes in certain current assets and liabilities —
-Receivables (30,452 ) (40,003 )
-Under recovered regulatory clause revenues (17,845 ) —
-Fossil fuel stock 35,917
59,608
-Materials and supplies (9,080 ) (8,029 )
-Prepaid income taxes (90,401 ) 33,793
-Other current assets 5,173
(1,710 )
-Accounts payable 27,511
17,397
-Accrued taxes (17,032 ) (2,334 )
-Accrued interest 23,939
15,153
-Accrued compensation 7,993
(8,543 )
-Over recovered regulatory clause revenues (18,358 ) (49,247 )
-Other current liabilities 154
—
Net cash provided from operating activities 504,723
286,768
Investing Activities:
Property additions (986,019 ) (1,221,519 )
Cost of removal, net of salvage (7,431 ) (5,769 )
Construction payables (40,301 ) (6,200 )
Capital grant proceeds —
4,500
Investment in restricted cash (10,548 ) —
Distribution of restricted cash 9,104
—
Proceeds from asset sales —
79,020
Other investing activities (14,804 ) (3,659 )
Net cash used for investing activities (1,049,999 ) (1,153,627 )
Financing Activities:
Proceeds —
Capital contributions from parent company 310,860
601,197
Bonds — Other 22,866
31,092
Interest-bearing refundable deposit 75,000
—
Long-term debt issuance to parent company 220,000
—
Other long-term debt issuances 250,000
475,000
Redemptions —
Bonds — Other —
(82,563 )
Capital leases (1,893 ) (82 )
Long-term debt to parent company (220,000 ) —
Other long-term debt —
(125,000 )
Payment of preferred stock dividends (1,299 ) (1,299 )
Payment of common stock dividends —
(71,956 )
Return of capital (164,790 ) (60,614 )
Other financing activities (687 ) (1,845 )
Net cash provided from financing activities 490,057
763,930
Net Change in Cash and Cash Equivalents (55,219 ) (102,929 )
Cash and Cash Equivalents at Beginning of Period 145,165
145,008
Cash and Cash Equivalents at End of Period $ 89,946
$ 42,079
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $55,376 and $53,450, net of $50,446 and $37,882
capitalized for 2014 and 2013, respectively) $ 4,930
$ 15,568
Income taxes, net (210,465 ) (48,307 )
Noncash transactions — accrued property additions at end of period 123,894
208,663
Noncash transactions — capital lease obligation —
82,915



	For the Six Months Ended June 30,
	2015			2014
	(in millions)
Operating Activities:
Net income (loss)	$	85		$	(109	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	55			50
Deferred income taxes	694			(108		)
Investment tax credits	32			28
Allowance for equity funds used during construction	(53		)	(75		)
Regulatory assets associated with Kemper IGCC	(50		)	(26		)
Estimated loss on Kemper IGCC	32			380
Income taxes receivable, non-current	(544		)	—
Other, net	8			7
Changes in certain current assets and liabilities —
-Receivables	6			(32		)
-Fossil fuel stock	5			32
-Prepaid income taxes	24			(12		)
-Other current assets	(7		)	(5		)
-Accounts payable	(25		)	4
-Accrued taxes	(51		)	(23		)
-Accrued interest	(7		)	13
-Accrued compensation	(12		)	4
-Over recovered regulatory clause revenues	32			(18		)
-Mirror CWIP	82			67
-Other current liabilities	3			1
Net cash provided from operating activities	309			178
Investing Activities:
Property additions	(428		)	(692		)
Construction payables	(15		)	(28		)
Other investing activities	(17		)	(13		)
Net cash used for investing activities	(460		)	(733		)
Financing Activities:
Increase in notes payable, net	475			—
Proceeds —
Capital contributions from parent company	77			211
Bonds — Other	—			12
Interest-bearing refundable deposit	—			75
Long-term debt issuance to parent company	—			220
Other long-term debt issuances	—			250
Short-term borrowings	30			—
Redemptions — Other long-term debt	(350		)	—
Payment of preferred stock dividends	(1		)	(1		)
Return of capital	—			(110		)
Other financing activities	(1		)	(1		)
Net cash provided from financing activities	230			656
Net Change in Cash and Cash Equivalents	79			101
Cash and Cash Equivalents at Beginning of Period	133			145
Cash and Cash Equivalents at End of Period	$	212		$	246
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $39 and $37, net of $37 and $29 capitalized for 2015 and 2014, respectively)	$	2		$	8
Income taxes, net	(181		)	(34		)
Noncash transactions —
Accrued property additions at end of period	99			136
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest	301			—

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


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

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

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CONDENSED BALANCE SHEETS (UNAUDITED)


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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~THIRD~~SECOND QUARTER ~~2014~~2015 vs. ~~THIRD~~SECOND QUARTER ~~2013~~2014

AND

YEAR-TO-DATE ~~2014~~2015 vs. YEAR-TO-DATE ~~2013~~2014

OVERVIEW

Mississippi Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of selling electricity. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment ~~to maintain and grow energy sales given economic conditions, and to effectively manage and secure~~that provides timely recovery of prudently-incurred costs. These costs include those related to ~~projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, restoration following major storms, and~~ the completion and operation of ~~ongoing~~major construction projects, primarily the Kemper ~~IGCC.~~IGCC and the Plant Daniel scrubber project, projected long-term demand growth, reliability, fuel, and increasingly stringent environmental standards, as well as ongoing capital expenditures required for maintenance. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

~~On October 27, 2014,~~In 2010, the Mississippi ~~Power further revised its~~PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate ~~for~~of the Kemper IGCC ~~to approximately $4.86~~established by the Mississippi PSC was $2.4 billion with a construction cost cap of $2.88 billion, net of ~~$245.3~~$245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). ~~The revised~~

Mississippi Power's current cost estimate ~~primarily reflects costs related to the extension of the project schedule~~ for the Kemper IGCC ~~as a result~~in total is approximately $6.23 billion, which includes approximately $4.96 billion of ~~matters related~~costs subject to the ~~time expected to be required for start-up activities and operational readiness, including enhancing the scope of specialized operator training.~~

construction cost cap. Mississippi Power does not intend to seek any rate recovery ~~or joint owner contributions~~ for any ~~costs~~ related ~~to the construction and start-up of the Kemper IGCC~~costs that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. ~~As a result of the revised cost estimate,~~ Mississippi Power recorded pre-tax charges to income for revisions to the ~~estimated probable losses on the Kemper IGCC~~cost estimate of ~~$418.0~~$23 million ($~~258.1~~14 million after tax) in the ~~third~~second quarter ~~2014 resulting in an estimated probable loss of $798.0~~2015 and $9 million ($~~492.8~~6 million after tax) ~~for~~in the first ~~nine months of 2014. In~~quarter 2015. Since 2012, in the aggregate, Mississippi Power has incurred charges of ~~$1.98~~$2.08 billion ($~~1.22~~1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through ~~September~~June 30, ~~2014.~~2015.

Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC project in service onin August 9, 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016. The ~~revised~~current cost estimate ~~above~~ includes costs through March 31, 2016. As a result of the additional factors that have the potential to impact start-up and operational readiness activities for this first-of-a-kind technology as described herein, the risk of further schedule extensions and/or cost increases, which could be material, remains.

For additional information on the Kemper IGCC, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.

On February 12, 2015, the Mississippi Supreme Court (Court) issued its decision in a legal challenge with respect to the Mississippi PSC's March 2013 order that authorized the collection of $156 million annually (2013 MPSC Rate Order) to be recorded as Mirror CWIP. The Court reversed the 2013 MPSC Rate Order, deemed the 2013

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Settlement Agreement (defined below) between Mississippi Power and the Mississippi PSC unenforceable due to a lack of public notice for the related proceedings, and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts collected pursuant to the 2013 MPSC Rate Order. As of June 30, 2015, $331 million had been collected by Mississippi Power. On March 12, 2015, Mississippi Power and the Mississippi PSC filed motions for rehearing, and, on June 11, 2015, the Court issued its final decision, rejecting both Mississippi Power's and the Mississippi PSC's motions for rehearing and requiring that a rate refund be made and that the Mirror CWIP rate be terminated. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.

See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information.

Prior to the Court's final decision on June 11, 2015, Mississippi Power sought alternate rate recovery and filed a rate case on May 15, 2015 (2015 Rate Case). Mississippi Power's 2015 Rate Case presented the Mississippi PSC with three alternative rate proposals: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). RMP 2019 contemplated the total Mirror CWIP funds collected would be used to offset the retail revenue requirements over the life of the plan. However, in light of the Court's mandate and the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.

On May 20, 2015, SMEPA notified Mississippi Power of its termination of the asset purchase agreement (APA) between Mississippi Power and SMEPA whereby SMEPA previously agreed to purchase a 15% undivided interest in the Kemper IGCC. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

As a result, on July 10, 2015, Mississippi Power submitted a supplemental filing with the Mississippi PSC that includes a request for interim rates (Supplemental Notice) until such time as the Mississippi PSC renders a final decision on an additional alternative rate proposal (In-Service Asset Proposal). The Supplemental Notice was filed in response to the Mississippi PSC's July 7, 2015 order and presents the In-Service Asset Proposal for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016 and is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.

See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.

As of June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately ~~$1 billion at September~~$898 million primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying

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costs through June 30, ~~2014, primarily because~~2015. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of ~~securities due within a year. Management~~Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information. In addition, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company that matures on December 2, 2016 in conjunction with the repayment of SMEPA's deposits with interest, following the termination of SMEPA's planned purchase of 15% of the Kemper IGCC project. Furthermore, Mississippi Power expects to fund the cash component of the Mirror CWIP refund with an intercompany loan from Southern Company. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions ~~and/or loans~~ from Southern Company ~~and cash, as well as commercial paper, lines of credit, and bank notes, as market conditions permit,~~ to fund Mississippi Power's short-term capital needs.

Mississippi Power continues to focus on several key performance indicators, including the construction, start-up, and rate recovery of the Kemper IGCC. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed return. In addition to the PEP performance indicators, Mississippi Power focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Mississippi Power in Item 7 of the Form 10-K. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding revisions to the cost estimate for the Kemper IGCC and the Court's decision that have negatively impacted Mississippi Power's actual performance on net income after dividends on preferred stock, one of its key performance indicators, for ~~2014,~~2015, as compared to the target.

RESULTS OF OPERATIONS

Net Income (Loss)

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(171.0) N/M $184.9 37.8

N/~~M – Not~~M-Not meaningful

Mississippi Power's net ~~loss~~income after dividends on preferred stock for the ~~third~~second quarter ~~2014~~2015 was ~~$195.1~~$49 million compared to ~~$24.1~~$62 million for the corresponding period in ~~2013.~~2014. The ~~change~~decrease was primarily related to ~~a $418.0~~$23 million in pre-tax ~~charge~~charges ($~~258.1~~14 million after tax) in the ~~third~~second quarter ~~2014 compared to a $150.0 million pre-tax charge ($92.6 million after tax) in the third quarter 2013~~2015 for ~~a revision~~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 DOE Grants and excluding the Cost Cap Exceptions. The ~~change~~decrease in net income was also related to a decrease in AFUDC equity, increases in non-fuel operations and maintenance expenses, an increase in depreciation and amortization, and a decrease in retail revenues primarily resulting from the Court's decision, partially offset by ~~an increase~~a decrease in revenues primarily due to retail and wholesale base rate increases and the recognition as revenue of a portion of the retail rate increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013.interest expense.

For year-to-date ~~2014, the~~2015, net ~~loss~~income after dividends on preferred stock was ~~$304.6~~$84 million compared to ~~$489.5~~a net loss of $110 million for the corresponding period in ~~2013.~~2014. The ~~change~~increase was primarily related to ~~a $798.0~~$32 million in pre-tax ~~charge~~charges ($~~492.8~~20 million after tax) in ~~2014~~2015 compared to ~~$1.06 billion~~$380 million in pre-tax charges ($~~655.8~~235 million after tax) in ~~2013~~2014 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. The ~~change~~increase in net income was also related to ~~an increase~~a decrease in interest expense, partially offset by a decrease in AFUDC equity, primarily related to the construction of the Kemper IGCC and an increase in revenues primarily due to retail and wholesale base rate increases and the recognition as revenue of a portion of the retail rate increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013. The change was partially offset by increases in non-fuel operations and maintenance ~~expenses.~~expenses, an increase in depreciation and amortization, and a decrease in retail revenues primarily resulting from the Court's decision.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined ~~Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.~~

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Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information. Also see "Interest Expense, Net of Amounts Capitalized" herein for additional information.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(2.4) (1.0) $33.4 5.4

In the ~~third~~second quarter ~~2014,~~2015, retail revenues were ~~$228.3~~$189 million compared to ~~$230.7~~$211 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, retail revenues were ~~$646.7~~$357 million compared to ~~$613.3~~$418 million for the corresponding period in ~~2013.~~2014.

Details of the changes in retail revenues were as follows:


	Third Quarter 2014					Year-to-Date 2014					Second Quarter 2015					Year-to-Date 2015
	(in millions)			(% change)		(in millions)			(% change)		(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	230.7				$	613.3				$	211				$	418
Estimated change resulting from –
Rates and pricing	2.8			1.2		16.4			2.7		(6		)	(2.7	)	(9		)	(2.2	)
Sales decline	(3.3		)	(1.4	)	(3.6		)	(0.6	)	(1		)	(0.6	)	(5		)	(1.2	)
Weather	4.8			2.1		6.3			1.0		2			0.9		1			0.2
Fuel and other cost recovery	(6.7		)	(2.9	)	14.3			2.3		(17		)	(8.0	)	(48		)	(11.4	)
Retail – current year	$	228.3		(1.0	)%	$	646.7		5.4	%	$	189		(10.4	)%	$	357		(14.6	)%

Revenues associated with changes in rates and pricing ~~increased~~decreased in the ~~third~~second quarter ~~2014~~and year-to-date 2015 when compared to the corresponding ~~period~~periods in ~~2013~~2014 primarily due to $7 million and $11 million, respectively, of revenues associated with the ~~collection of~~ Kemper IGCC cost recovery ~~revenues,~~recognized in 2014, which ceased in 2015 as a result of the ~~majority of which were deferred to a regulatory liability. The collected revenue for third~~Court's decision, partially offset by $1 million in the second quarter ~~2014 was $47.6~~2015 and $2 million ~~compared to $37.0 million~~year-to-date 2015 in net revenues for the ~~corresponding period in 2013, with deferrals of $41.8 million in 2014 and $34.0 million in 2013.~~

~~Revenues associated with changes in rates and pricing increased year-to-date 2014 when compared to the corresponding period in 2013 due to the collection of Kemper IGCC~~new energy efficiency cost recovery ~~revenues,~~rate, which began in the majority of which were deferred to a regulatory liability, and a $2.8 million PEP base rate increase, which both became effective March 2013. The collected Kemper IGCC cost recovery revenue for year-to-date 2014 was $121.9 million compared to $68.1 million for the corresponding period in 2013, with deferrals of $105.1 million in 2014 and $60.1 million in 2013. Also contributing to the increase was a $4.7 million refund in 2013 related to the annual PEP lookback filing.fourth quarter 2014.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K and ~~FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and~~ Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Revenues attributable to changes in sales decreased in the ~~third~~second quarter ~~and year-to-date 2014~~2015 when compared to the corresponding ~~periods~~period in ~~2013.~~2014. Weather-adjusted KWH sales to residential customers decreased 0.5% in the second quarter 2015 due to lower customer usage, slightly offset by an increase in customers. Weather-adjusted KWH sales to commercial customers increased 2.6% in the second quarter 2015 due to higher customer usage and an increase in customers. KWH sales to industrial customers decreased 0.9% in the second quarter 2015 due to decreased usage by larger customers related to planned maintenance outages.

Revenues attributable to changes in sales decreased year-to-date 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH energy sales to residential customers decreased ~~5.5% in the third quarter and 2.7% for year-to-date 2014 when compared to the corresponding periods in 2013~~1.2% due to lower ~~average usage per customer. Household income, one of the primary drivers of residential~~ customer usage, ~~has been flat~~slightly offset by an increase in ~~2014.~~customers. Weather-adjusted KWH energy sales to commercial customers decreased ~~1.8% in the third quarter and 0.5% for year-to-date 2014 when compared to the corresponding periods in 2013~~0.2% due to ~~decreased commercial economic activity.~~lower customer usage slightly offset by an increase in customers. KWH energy sales to industrial customers increased ~~2.5% in the third quarter and 3.2% for year-to-date 2014 when compared to the corresponding periods in 2013~~1.2% primarily due to increased usage by larger customers.

In the first quarter 2015, Mississippi Power updated its methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled second quarter

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and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without these adjustments, second quarter 2015 weather-adjusted residential KWH sales increased 4.0%, weather-adjusted commercial KWH sales decreased 1.5%, and industrial KWH sales decreased 2.1% as compared to the corresponding period in 2014. Also, without these adjustments, year-to-date 2015 weather-adjusted residential KWH sales decreased 3.3%, weather-adjusted commercial KWH sales decreased 5.1%, and industrial KWH sales remained flat as compared to the corresponding period in 2014.

Fuel and other cost recovery revenues decreased in the ~~third~~second quarter ~~2014~~and year-to-date 2015 when compared to the corresponding ~~period~~periods in ~~2013,~~2014, primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased year-to-date 2014 when compared to the corresponding period in 2013 primarily as a result of higher recoverable fuel costs resulting from an increase in Mississippi Power's generation and higher natural gas costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$0.1 — $34.6 15.8

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Mississippi Power serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under ~~long-term contracts with~~ cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.

In the ~~third~~second quarter ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$83.0~~$63 million compared to ~~$82.9~~$75 million for the corresponding period in 2013. The increase was due to a $2.0 million increase in base revenues primarily resulting from a wholesale base rate increase effective beginning May 1, 2014, partially offset by a $1.9 million decrease in energy revenues.

2014. For year-to-date ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$254.6~~$141 million compared to ~~$220.0~~$172 million for the corresponding period in ~~2013.~~2014. The ~~increase was~~decreases were primarily due to a ~~$17.2 million increase in base revenues primarily resulting from wholesale base rate increases effective April 1, 2013 and May 1, 2014 and a $17.4 million increase~~decrease in energy revenues ~~of which $5.1 million was primarily associated with higher fuel~~resulting from lower market prices and ~~$12.3 million was associated with an increase in KWH sales primarily due to the higher demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013.~~fuel cost.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$31.6 N/M $50.4 N/M

~~N/M – Not meaningful~~

Wholesale revenues from sales to ~~affiliates~~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~~this energy is generally sold at marginal cost.

In the ~~third~~second quarter ~~2014,~~2015, wholesale revenues from sales to affiliates were ~~$38.6~~$18 million compared to ~~$7.0~~$20 million for the corresponding period in ~~2013.~~2014. The decrease was due to a $6 million decrease associated with lower natural gas prices, partially offset by a $4 million increase in KWH sales due to higher gas generation partially as a result of the Kemper IGCC combined cycle being in service since August 2014.

For year-to-date 2015, wholesale revenues from sales to affiliates were $45 million compared to $43 million for the corresponding period in 2014. The increase was due to ~~a $33.7~~an $18 million increase in ~~energy revenues~~KWH sales due to higher gas

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~primarily due to placing~~generation partially as a result of the Kemper IGCC combined cycle being in service. These increased revenues are offset by fuel expense. Of the $33.7 million increase in energy revenues, $31.6 million was associated with an increase in KWH sales due to higher gas and coal generation and $2.1 million was associated with higher prices,service since August 2014, partially offset by a ~~$2.1~~$16 million decrease ~~in capacity revenues.~~

For year-to-date 2014, wholesale revenues from sales to affiliates were $81.6 million compared to $31.2 million for the corresponding period in 2013. The increased revenues were driven by $48.0 million associated with ~~an increase in KWH sales primarily due to higher~~lower natural gas ~~prices resulting in higher coal-fired generation at lower coal prices and $4.6 million associated with higher prices, partially offset by a $2.2 million decrease in capacity revenues.~~prices.

Fuel and Purchased Power Expenses

Third Quarter 2014
vs.
Third Quarter 2013 Year-to-Date 2014
vs.
Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
Fuel $ 30.5
22.1 $ 74.1
19.2
Purchased power – non-affiliates 1.4
67.3 11.0
N/M
Purchased power – affiliates (12.7 ) (86.6) (11.7 ) (41.2 )
Total fuel and purchased power expenses $ 19.2
$ 73.4

~~N/M – Not meaningful~~



	Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(28	)	(19.6)	$	(61	)	(21.0	)
Purchased power – non-affiliates	1			100.0	(10		)	(76.9	)
Purchased power – affiliates	(4		)	(66.7)	(11		)	(73.3	)
Total fuel and purchased power expenses	$	(31	)		$	(82	)

In the ~~third~~second quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$174.1~~$119 million compared to ~~$154.9~~$150 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was due to a ~~$39.4 million increase in the total volume of KWHs generated, partially offset by a $20.2~~$28 million decrease in the average cost of fuel and purchased ~~power.~~power and a $3 million decrease in the volume of KWHs purchased.

For year-to-date ~~2014,~~2015, total fuel and purchased power expenses were ~~$491.8~~$236 million compared to ~~$418.4~~$318 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was due to a ~~$91.8 million increase in the total volume of KWHs generated, partially offset by an $18.5~~$72 million decrease in the average cost of fuel and purchased ~~power.~~power and a $14 million decrease in the volume of KWHs purchased, partially offset by a $4 million increase in the volume of KWHs generated.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause. ~~See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.~~

Details of Mississippi Power's generation and purchased power were as follows:


	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013	Second Quarter 2015	Second Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (millions of KWHs)^(a)	5,022	3,688	12,996	10,645
Total generation (millions of KWHs)^(*)					4,109	3,932	8,455	7,974
Total purchased power (millions of KWHs)	125	469	591	1,070	114	208	227	466
Sources of generation (percent)^(a) –
Sources of generation (percent)^(*) –
Coal	43	43	45	38	18	47	20	46
Gas	57	57	55	62	82	53	80	54
Cost of fuel, generated (cents per net KWH) –
Coal	3.97	5.12	4.12	5.01	4.14	4.18	3.64	4.21
Gas^(a)	3.20	3.08	3.45	3.14
Average cost of fuel, generated (cents per net KWH)^(a)	3.55	4.03	3.77	3.91
Average cost of purchased power (cents per net KWH)^(a)	4.36	3.58	5.55	3.13
Gas^(*)					2.71	3.62	2.69	3.61
Average cost of fuel, generated (cents per net KWH)^(*)					2.98	3.90	2.90	3.91
Average cost of purchased power (cents per net KWH)^(*)					3.19	3.33	3.37	5.87


~~(a)~~(*)	Includes energy produced during the test period for the Kemper IGCC which is accounted for in accordance with FERC guidance.

Fuel

In the second quarter 2015, fuel expense was $115 million compared to $143 million for the corresponding period in 2014. The decrease was primarily due to a 23.6% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower natural gas prices, partially offset by a 4.9% increase in the volume of KWHs generated resulting from the availability of lower cost Mississippi Power units. The 4.9% increase in volume included an increase in gas-fired generation of 70.2%, partially offset by a decrease in coal-fired generation of 60.2%.

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~~Fuel~~

~~In the third quarter 2014,~~For year-to-date 2015, total fuel expense was ~~$168.7~~$229 million compared to ~~$138.2~~$290 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a 38.6% increase in the volume of KWHs generated to meet demand attributed to industrial consumption and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013, partially offset by an 11.9%25.8% decrease in the average cost of fuel per KWH generated primarily due to higher ~~coal-fired~~gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower ~~coal~~natural gas prices, partially offset by ~~higher natural gas prices.~~

~~For year-to-date 2014, fuel expense was $459.0 million compared to $384.9 million for the corresponding period in 2013. The increase was primarily due to~~ a ~~23.9%~~6.1% increase in the volume of KWHs generated ~~to meet demand related to colder weather~~resulting from the availability of lower cost Mississippi Power units. The 6.1% increase in ~~the first quarter 2014 as compared to the corresponding period~~volume included an increase in ~~2013, partially~~gas-fired generation of 65.2%, offset by a ~~3.6%~~ decrease in ~~the average cost of fuel per KWH generated, primarily due to higher natural gas prices resulting in higher~~ coal-fired generation ~~at lower coal prices.~~of 53.7%.

Purchased Power - Non-Affiliates

In the ~~third~~second quarter ~~2014,~~2015, purchased power expense from non-affiliates was ~~$3.5~~$2 million compared to ~~$2.1~~$1 million for the corresponding period in ~~2013.~~2014. The increase was primarily the result of a ~~145.8%~~57.6% increase in the average cost per KWH, ~~purchased, partially~~ offset by a ~~32.0%~~2.8% decrease in the volume of KWHs ~~purchased.~~purchased due to an increase in Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014.

For year-to-date ~~2014,~~2015, purchased power expense from non-affiliates was ~~$16.2~~$3 million compared to ~~$5.2~~$13 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily the result of a 54.1% decrease in the volume of KWHs purchased due to an increase in Mississippi Power generation partially as a ~~283.8% increase~~result of the Kemper IGCC combined cycle being placed in service in August 2014 and a 42.3% decrease in the average cost per KWH purchased ~~partially offset by~~as a ~~19.4% decrease in the volume~~result of ~~KWHs purchased.~~lower natural gas prices.

Purchased Power - Affiliates

In the ~~third~~second quarter ~~2014,~~2015, purchased power expense from affiliates was ~~$2.0~~$2 million compared to ~~$14.7~~$6 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to ~~an 83.4%~~a 58.3% decrease in the volume of KWHs purchased due to increased Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014, and a ~~19.5%~~24.7% decrease in the average cost per KWH ~~purchased.~~purchased as a result of lower natural gas prices.

For year-to-date ~~2014,~~2015, purchased power expense from affiliates was ~~$16.6~~$4 million compared to ~~$28.3~~$15 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to a ~~52.8%~~50.0% decrease in the volume of KWHs purchased due to increased Mississippi Power generation partially ~~offset by~~as a ~~24.5% increase~~result of the Kemper IGCC combined cycle being placed in service in August 2014, and a 41.5% decrease in the average cost per KWH ~~purchased.~~purchased as a result of lower natural gas prices.

Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$8.9 15.6 $25.7 15.5

In the ~~third~~second quarter ~~2014,~~2015, other operations and maintenance expenses were ~~$65.8~~$68 million compared to ~~$56.9~~$61 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to a ~~$4.0~~$7 million increase in employee compensation and benefits and labor, a $2.3 million increase in customer accounting services and sales expenses primarily due to uncollectible expenses and customer incentives, a $1.9 million increase in administrative and general expenses primarily due to an increase in charges from affiliates and a $1.5 million increase in transmission and distribution expenses mainly for overhead line maintenance and vegetation management. These increases were partially offset by a $0.7 million decrease in generation maintenance expenses primarily related to scheduled outages.

For year-to-date 2015, other operations and maintenance expenses were $144 million compared to $125 million for the corresponding period in 2014. The increase was primarily due to a $6 million increase in generation

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~~For year-to-date 2014, other operations and~~ maintenance expenses ~~were $191.9 million compared to $166.2 million for the corresponding period in 2013. The increase was primarily due to an $11.8~~including scheduled outages, a $5 million increase in employee compensation and benefits including pension, and ~~labor,~~ a ~~$10.5~~$5 million increase ~~in generation maintenance expenses primarily~~ related to ~~scheduled outages,~~uncollectible expenses and ~~a $2.7 million increase in transmission and distribution maintenance expenses primarily~~customer incentives.

See Note (F) to the Condensed Financial Statements herein for ~~overhead line maintenance, vegetation management and equipment maintenance.~~additional information related to pension costs.

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$1.2 5.3 $2.7 4.0

In the ~~third~~second quarter ~~2014,~~2015, depreciation and amortization was ~~$23.4~~$30 million compared to ~~$22.2~~$24 million for the corresponding period in ~~2013.~~2014. The ~~$1.2 million~~ increase was primarily due to a ~~$0.6~~$2 million increase in depreciation related to increases in generation and ~~transmission~~distribution plant in service, a $2 million increase related to regulatory deferrals associated with Plant Daniel Units 3 and 4 and the Kemper IGCC, and a ~~$0.3~~$1 million increase in ~~amortization primarily resulting from the 2013 regulatory deferral associated with the capital lease related to the Kemper IGCC air separation unit.~~ECO Plan amortization.

For year-to-date ~~2014,~~2015, depreciation and amortization was ~~$70.3~~$57 million compared to ~~$67.6~~$47 million for the corresponding period in ~~2013.~~2014. The ~~$2.7 million~~ increase was primarily due to a ~~$1.6~~$4 million increase in depreciation related to increases in generation, transmission and ~~transmission~~distribution plant in service, ~~and~~ a ~~$1.9~~$4 million increase ~~in the~~related to regulatory ~~deferral~~deferrals associated with ~~the purchase of~~ Plant Daniel Units 3 and ~~4. These increases were partially offset by a $0.6 million decrease in amortization resulting from regulatory deferrals associated with~~4 and the Kemper ~~IGCC.~~IGCC, and a $2 million increase in ECO Plan amortization.

See Note 1 to the financial statements of Mississippi Power under ~~"Purchase of the Plant Daniel Combined Cycle Generating Units" and~~ "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Taxes Other Than Income Taxes

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$1.2 6.0 $2.4 4.0

In the ~~third~~second quarter ~~2014,~~2015, taxes other than income taxes were ~~$22.3~~$23 million compared to ~~$21.1~~$20 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to a ~~$1.4~~$3 million increase in ad valorem taxes, ~~and a $0.4 million increase in payroll taxes due to an increase in labor expenses,~~ partially offset by a ~~$0.5~~$1 million decrease ~~primarily~~ in ~~corporate~~ franchise ~~taxes.~~tax.

For year-to-date ~~2014,~~2015, taxes other than income taxes were ~~$63.2~~$48 million compared to ~~$60.8~~$41 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to a ~~$1.4~~$9 million increase in ad valorem taxes, partially offset by a $2 million decrease in franchise taxes.

The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, ~~a $1.0 million increase in payroll taxes due to an increase in labor expenses.~~therefore, does not affect net income.

Estimated Loss on Kemper IGCC

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$268.0 N/M $(264.0) (24.9)

N/~~M – Not~~M-Not meaningful

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In the ~~third~~second quarter ~~2014~~2015 an estimated probable loss on the Kemper IGCC of $23 million was recorded at Mississippi Power. For year-to-date 2015 and ~~the third quarter 2013,~~year-to-date 2014, estimated probable losses on the Kemper IGCC of ~~$418.0~~$32 million and ~~$150.0~~$380 million, ~~respectively, were recorded at Mississippi Power. For year-to-date 2014 and year-to-date 2013, estimated probable losses on the Kemper IGCC of $798.0 million and $1.06 billion,~~ respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and ~~FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and~~ Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(0.4) (1.2) $20.0 22.7

~~For year-to-date 2014,~~In the second quarter 2015, AFUDC equity was ~~$107.7~~$25 million compared to ~~$87.7~~$37 million for the corresponding period in ~~2013.~~2014. For year-to-date 2015, AFUDC equity was $53 million compared to $75 million for the corresponding period in 2014. The ~~increase was primarily due to $16.8 million related to~~decreases are driven by a reduction in the ~~construction~~AFUDC rate and by placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and ~~$3.2~~Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

Interest Expense, Net of Amounts Capitalized

N/M-Not meaningful

In the second quarter 2015, interest expense, net of amounts capitalized was ($30) million compared to $13 million for the corresponding period in 2014. For year-to-date 2015, interest expense, net of amounts capitalized was ($19) million compared to $25 million for the corresponding period in 2014. The decreases were primarily due to a $41 million decrease related to the ~~Plant Daniel scrubber project.~~termination of the APA between Mississippi Power and SMEPA which required the return of SMEPA's deposits at a lower rate of interest than accrued. Also contributing to the decrease was an increase in capitalized interest primarily resulting from carrying costs related to the Kemper IGCC. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional ~~information regarding the Kemper IGCC.~~information.

~~Interest Expense, Net of Amounts Capitalized~~Income Taxes (Benefit)

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$0.7 7.9 $4.5 15.4

N/M-Not meaningful

In the ~~third~~second quarter 2015 and 2014, ~~interest expense, net of amounts capitalized was $9.4~~income taxes were $16 million. For year-to-date 2015, income taxes (benefit) were $20 million compared to ~~$8.7~~$(114) million for the corresponding period in ~~2013.~~2014. The ~~increase was~~change primarily ~~due to~~reflects a $2.5 million increase resulting from the receipt of a $75.0 million interest-bearing refundable deposit from SMEPA in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC, a $1.9 million increase related to the regulatory liability for Kemper IGCC rate recovery, and a $1.5 million increase associated with issuances of new long-term debt. These increases were partially offset by a $4.0 million increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC and a $0.9 million decrease in interest expense associated with the redemption of long-term debt in 2013.

For year-to-date 2014, interest expense, net of amounts capitalized was $34.0 million compared to $29.5 million for the corresponding period in 2013. The increase was primarily due to a $7.3 million increase resulting from the receipt of a $75.0 million interest-bearing refundable deposit from SMEPA in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC, a $4.9 million increase related to the regulatory liability for Kemper IGCC rate recovery, and a $3.7 million increase associated with issuances of new long-term debt. These increases were partially offset by an $8.1 million increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC and a $2.8 million decrease in interest expense associated with the redemption of long-term debt in 2013.

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~~Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.~~

~~Other Income (Expense), Net~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(7.4) N/M $(7.3) N/M

~~N/M – Not meaningful~~

~~In the third quarter 2014, other income (expense), net was $(7.8) million compared to $(0.4) million for the corresponding period~~reduction in 2013. For year-to-date 2014, other income (expense), net was $(11.5) million compared to $(4.2) million for the corresponding period in 2013. These changes in expense were primarily due to a settlement with the Sierra Club in 2014. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

~~Income Taxes (Benefit)~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(106.6) N/M $102.2 28.8

~~N/M – Not meaningful~~

~~In the third quarter 2014, income~~ tax benefits were $139.3 million compared to $32.7 million for the corresponding period in 2013. For year-to-date 2014, income tax benefits were $253.0 million compared to $355.2 million for the corresponding period in 2013. These changes were primarily related to the estimated probable losses ~~recorded~~ on the construction of the Kemper ~~IGCC.~~IGCC recorded in 2014.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely ~~basis.~~basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million excluding the reserve for cost of removal. As of June 30, 2015, Mississippi Power reclassified the net carrying value of these assets from accumulated provision for depreciation to other regulatory assets, deferred, in accordance with an accounting order from the Mississippi PSC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Sierra Club Settlement Agreement" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.

Mississippi Power expects to recover through its rates the remaining book value of the retired assets and certain costs, including unusable inventory, associated with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.

New Source Review Actions

See Note 3 to the financial statements of Mississippi Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

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Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

See Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR).

On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama and ~~the EPA's proposed rules~~Mississippi) to revise or remove state implementation plan (SIP) provisions regarding ~~the regulation of~~ excess emissions that occur during periods of ~~startup, shutdown, or malfunction (SSM).~~SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subjectrespond to the ~~rule (including Alabama and Mississippi) to revise their SSM provisions within 18 months after issuance of the final rule.~~decision. The ultimate impact of ~~the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and~~this decision cannot be determined at this time.

~~See "PSC Matters~~ – ~~Environmental Compliance Overview Plan"~~On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama. The court's decision leaves the emissions trading program in place and ~~"Other Matters~~ – ~~Sierra Club Settlement Agreement" and Note (B)~~remands the rule to the ~~Condensed Financial Statements under "PSC Matters~~ – ~~Environmental Compliance Overview Plan" and "Other Matters~~ – ~~Sierra Club Settlement Agreement" herein~~EPA for ~~additional information regarding generating unit retirement, repowering, and/or conversion.~~

further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate ~~outcome~~impact of ~~these matters~~this decision will depend on additional rulemaking and cannot be determined at this time.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).

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Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Coal Combustion Residuals" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On ~~August 15, 2014,~~April 17, 2015, the EPA published athe Disposal of Coal Combustion Residuals from Electric Utilities final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became(CCR Rule) in the Federal Register, setting October 19, 2015 as the effective ~~October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation~~date of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units.CCR Rule. The ultimate impact of ~~this rule will depend on~~ the ~~outcome of any legal challenges and~~CCR Rule cannot be determined at this ~~time.~~timeand will depend on Mississippi Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Mississippi Power recorded incremental asset retirement obligations (ARO) of approximately $95 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Mississippi Power's AROs.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's ~~current and~~ proposed regulation of ~~GHG emissions under the Clean Air Act.~~CO₂ from fossil-fuel-fired electric generating units.

On ~~June 18, 2014,~~August 3, 2015, the EPA ~~published~~released pre-publication versions of two final rules that would limit CO₂ emissions from fossil fuel-fired electric generating units. One of the ~~proposed Clean Power Plan, setting forth~~final rules contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to ~~address CO~~₂ ~~emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final~~meet EPA-mandated CO₂ emission ~~rate goals~~rates for existing units. The EPA's final guidelines require state plans to ~~be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposed~~meet interim CO₂ performance ~~standards for modified~~rates between 2022 and ~~reconstructed fossil fuel-fired electric generating units. The~~2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, ~~that~~which could ~~impact~~affect future unit retirement and replacement decisions. ~~Also, additional compliance costs could affect~~Mississippi Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated ~~rates. Further, any resulting higher costs that are recovered~~rates or through ~~regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.~~

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system.market-based contracts. However, the ultimate financial and operational impact of the ~~Clean~~final rules on Mississippi Power ~~Plan proposed guidelines on the Southern Company system~~ cannot be determined at this time and will ~~be dependent upon~~depend on numerous ~~factors. These~~ factors ~~include:~~including the ~~structure, timing, and content~~Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final ~~guidelines; individual state implementation of these~~ guidelines, including the potential that state ~~implementation~~ plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and ~~emissions-related~~emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

~~On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration~~FERC Matters

Municipal and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of the U.S. Supreme Court's decision cannot be determined at this time.

~~FERC Matters~~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 ~~authority to defer in~~establishment of a regulatory asset ~~costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules.~~for Kemper IGCC-related costs. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.

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~~On March 31, 2014, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with~~ the ~~FERC for an increase~~filing by, among other things, increasing the accrual of AFUDC in ~~the Municipal and Rural Associations (MRA) cost-based electric tariff.~~lieu of including CWIP in rate base. The settlement agreement, ~~approved~~which was accepted by the FERC on May ~~20, 2014,~~13, 2015, provides that the additional accrual of AFUDC was effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $11 million annually, of which $8 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.

Market-Based Rate Authority

Mississippi Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Mississippi Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Mississippi Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Mississippi Power) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies (including Mississippi Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates ~~under~~and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as the ~~MRA cost-based electric tariff will increase approximately $10.1 million annually,~~Kemper IGCC, fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with ~~revised rates effective for services rendered beginning May 1, 2014.~~

~~PSC Matters~~

~~Energy Efficiency~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Energy Efficiency"~~environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through Mississippi ~~Power in Item 7 and~~Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory ~~Matters – Energy Efficiency"~~Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

~~On June 3, 2014,~~Renewables

In April and May 2015, Mississippi Power entered into separate PPAs for three solar facilities for a combined total of approximately 105 MWs. Mississippi Power would purchase all of the energy produced by the solar facilities for the 25-year term of the contracts. If approved by the Mississippi PSC, ~~approved~~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 ~~2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio~~fuel cost recovery mechanism. The ultimate outcome of energy efficiency programs. On October 17, 2014, Mississippi Power filed a revised compliance filing, which proposed an increase of $6.7 million in retail revenues for the period December 2014 through December 2015. The Mississippi PSC approved the revised filing on November 4, 2014.this matter cannot be determined at this time.

Performance Evaluation Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Performance Evaluation Plan" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

On March ~~18, 2014,~~17, 2015, Mississippi Power submitted its annual PEP lookback filing for ~~2013,~~2014, which indicated no surcharge or refund. On March ~~31, 2014,~~26, 2015, the Mississippi PSC suspended the filing to allow it more time for review.

On June 3, 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for Mississippi Power and other regulated electric utilities in Mississippi.

The ultimate outcome of ~~these matters~~this matter cannot be determined at this time.

~~Environmental Compliance Overview Plan~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Compliance Overview Plan" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information regarding the CPCN to construct a scrubber on Plant Daniel Units 1 and 2.

On August 1, 2014, Mississippi Power entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On August 28, 2014, the Chancery Court dismissed the appeal.

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environmental regulations. As of September 30, 2014, $5.5 million of Plant Greene County CWIP had been reclassified as a regulatory asset. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Greene County and Watson. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Fuel Cost Recovery~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Mississippi Power's fuel cost recovery.

At September 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $13.1 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

Ad Valorem Tax Adjustment

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Ad Valorem Tax Adjustment" of~~On April 23, 2015, Mississippi Power ~~in Item 7 of the Form 10-K for additional information.~~

~~On May 6, 2014, the Mississippi PSC approved Mississippi Power's~~filed its annual ad valorem tax adjustment factor filing for ~~2014,~~2015, which requested an annual rate ~~increase~~decrease of ~~0.38%~~0.35%, or ~~$3.6~~$2 million in annual retail revenues, primarily due to ~~an increase~~a decrease in ~~property tax~~average millage rates. On May 26, 2015, the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC ~~Project Approval~~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, which the Sierra Club appealed to the Chancery Court. Later in 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. In January 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN, which the Mississippi Supreme Court granted on September 11, 2014. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

~~Kemper IGCC Schedule and Cost Estimate~~IGCC.

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of ~~$245.3~~$245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂

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pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the Cost Cap Exceptions, as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

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

~~The ultimate outcome of this matter cannot be determined at this time.~~Court's decision, are as follows:

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~~Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of September 30, 2014 for the Kemper IGCC are as follows:~~


Cost Category	2010 Project Estimate^(f)		Current Estimate		Actual Costs at September 30, 2014		2010 Project Estimate^(f)		Current Estimate		Actual Costs at June 30, 2015
	(in billions)						(in billions)
Plant Subject to Cost Cap^(a)	$	2.40	$	4.86	$	4.06	$	2.40	$	4.96	$	4.51
Lignite Mine and Equipment	0.21		0.23		0.23		0.21		0.23		0.23
CO₂ Pipeline Facilities	0.14		0.11		0.10		0.14		0.11		0.11
AFUDC^(b)(c)	0.17		0.62		0.41		0.17		0.62		0.52
Combined Cycle and Related Assets Placed in Service – Incremental^(d)	—		—		—		—		0.02		—
General Exceptions	0.05		0.10		0.07		0.05		0.10		0.08
Regulatory Asset^(c)(e)	—		0.18		0.10
Deferred Costs^(c)(e)							—		0.19		0.15
Total Kemper IGCC^(a)(c)	$	2.97	$	6.10	$	4.97	$	2.97	$	6.23	$	5.60

(a)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost ~~cap.~~cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.

(b)

Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.


(c)	Amounts in the Current Estimate reflect estimated costs through March 31, 2016.


(d)	Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service onin August 9, 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.


(e)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."


(f)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of ~~September~~June 30, ~~2014, $2.88~~2015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of ~~$1.98~~$2.08 billion), ~~$104.3~~$2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, ~~and $3.9~~$16 million in other deferred charges and assets, and $24 million in ~~Mississippi Power's Condensed Balance Sheet herein, and $1.1~~AROs in the balance sheet, with $1 million ~~was~~ previously expensed.

Mississippi Power does not intend to seek any rate recovery ~~or joint owner contributions~~ for any costs related ~~costs~~to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of ~~$418.0~~$23 million ($~~258.1~~14 million after tax) in the ~~third~~second quarter ~~2014~~2015 and ~~$380.0~~$9 million ($~~234.7~~6 million after tax) in the first quarter ~~2014.~~2015. These amounts are in addition to charges totaling ~~$1.18 billion~~$868 million ($~~728.7~~536 million after tax) ~~recognized through December 31, 2013.~~, $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. The ~~first quarter 2014 revised~~increases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to decreases in construction labor productivity at the Kemper IGCC due in large part to adverse weather, unexpected excessive craft labor turn-over, and unanticipated installation inefficiencies, as well as additional risk related to the expected in-service date. The third quarter 2014 revised cost estimate primarily reflects costs related to the extension of the project schedule for the remainder of the Kemper IGCC (including the gasifierequipment rework, scope modifications, and the ~~gas clean-up facilities) as a result~~related additional labor costs in support of ~~matters related to the time expected to be required for~~ start-up ~~activities~~ and operational readiness ~~including enhancing the scope of specialized operator training.~~activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately ~~$20~~$25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion

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cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

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inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational ~~performance, operational~~ readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or ~~operations.~~operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the ~~Seven-Year~~2015 Rate ~~Plan (described below)~~Case and ~~other~~any alternative proceedings related ~~proceedings during~~to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, ~~establishes~~established the process for resolving matters regarding cost recovery related to the Kemper IGCC ~~and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order~~ (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also ~~allows~~allowed Mississippi Power to secure alternate financing for costs ~~that are~~ not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in ~~February~~ 2013. Mississippi ~~Power intends~~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 Seven-Year Rate Plan (described below) as approved by the Mississippi PSC. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective following completion of the Mississippi PSC's prudence review of the costs to be securitized. With the extension of the Kemper IGCC in-service date, under certain potential scenarios, the amount eligible to be securitized may exceed $1.0 billion. In that event, Mississippi Power would expect to pursue rate recovery of any additional eligible costs.

The 2013 Settlement Agreement provides that Mississippi Power may terminate the 2013 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 2013 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the 2013 Settlement

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~~Agreement.~~estimated in-service date until securitization is finalized and other costs not included in Mississippi ~~Power continues~~Power's 2013 revision to ~~work~~the proposed rate recovery plan filed with the Mississippi PSC ~~and~~for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi ~~Public Utilities Staff (MPUS)~~PSC. The Court's decision did not impact Mississippi Power's ability to ~~implement~~utilize alternate financing through securitization, the ~~requirements of~~2012 MPSC CPCN Order, or the February 2013 ~~Settlement Agreement.~~legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in ~~January 2013, Mississippi Power filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013.~~

In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively ~~are~~were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order). For the first nine months of 2014, $121.9 million has been collected, with $16.8 million recognized in retail revenues in Mississippi Power's Condensed Statements of Operations herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Mississippi Power's Condensed Balance Sheet herein. Since March 2013, $220.0 million has been collected, with $27.1 million recognized in retail revenues in Mississippi Power's Condensed Statements of Operations herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Mississippi Power's Condensed Balance Sheet herein.

service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC ~~and to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates~~ through the in-service date ~~unless~~until directed to do otherwise by the Mississippi PSC.

In ~~March~~August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.

In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Mississippi Power.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was ~~filed by Thomas A. Blanton with~~not provided for under the Baseload Act and (2) the Mississippi ~~Supreme~~PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court ~~which remains pending against~~also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi ~~PSC. On April 22, 2014,~~PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi ~~Supreme Court requested further briefing~~PSC to (1) fix by order the rates that were in ~~this proceeding on a number of substantive issues relating~~existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. ~~An adverse outcome could affect the rates that went into effect on March 19, 2013 and January 1, 2014 and the related amounts deferred as a regulatory liability.~~

~~See "Regulatory Assets and Liabilities" herein for additional information.~~

~~Seven-Year Rate Plan~~

~~In March 2013,~~Through June 30, 2015, Mississippi Power ~~in compliance with~~had collected $331 million through rates under the 2013 MPSC Rate Order ~~filed a revision to the proposed rate recovery plan with~~and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ~~for~~ordered that the ~~Kemper IGCC for cost recovery through 2020 (Seven-Year Rate Plan), which is still under review by the Mississippi PSC. In the Seven-Year Rate Plan,~~Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power ~~proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal~~submitted a refund plan to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC ~~will review~~on July 21, 2015, which proposed two alternative refund plans for the ~~amount~~Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.

2015 Rate Case

As a result of the 2015 Mississippi Supreme Court decision and ~~if approved, determine~~ the ~~appropriate method and period of disposition.~~Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See ~~"Regulatory Assets and Liabilities"~~"2015 Mississippi Supreme Court Decision" herein for additional information.

The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act On

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~~of 2012 (ATRA), which currently requires that assets be placed in service in 2014. While~~May 15, 2015, Mississippi Power ~~placed~~filed the 2015 Rate Case with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.

On July 10, 2015, Mississippi Power filed a Supplemental Notice with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal, In-Service Asset Proposal, for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the ~~associated common facilities portion~~In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.

The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC ~~in service on August 9, 2014, extension of the in-service date for the remainder of the Kemper IGCC beyond 2014 results in the loss of tax benefits~~ related to ~~bonus depreciation under current law. The estimated value to retail customers of~~ the ~~bonus depreciation tax benefits not associated with the combined cycle and the associated common facilities portion of the Kemper IGCC is approximately $130 million to $160 million.~~

Mississippi Power plans to further revise the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to investment tax credits, various other revenue requirement items, and other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated15% undivided interest that was previously projected to be ~~an increase~~purchased by SMEPA. See "Termination of ~~approximately $60 million~~Proposed Sale of Undivided Interest to $70 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power, including Section 174 Research and Experimental (R&E) tax deductions, that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan. See "Income Tax Matters"SMEPA" herein for additional information.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC could have an adverse impact on the Seven-Year Rate Plan, including the inability to recover items considered as Cost Cap Exceptions.

~~In the event that~~If the Mississippi PSC does not ~~approve~~act on the Supplemental Notice or the 2015 Rate Case within 120 days of the Supplemental Notice filing, Mississippi Power ~~withdraws~~expects to put one of the ~~Seven-Year Rate Plan,~~three viable alternative rate proposals into effect as ~~ultimately revised,~~ temporary rates under bond and subject to refund pursuant to Mississippi state law.

Mississippi Power ~~would~~also expects to seek additional rate relief to address recovery ~~through alternate means, which could include a traditional rate case.~~

of the remaining Kemper IGCC assets. In addition to current estimated costs at ~~September~~June 30, ~~2014~~2015 of ~~$6.10~~$6.23 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the ~~Seven-Year Rate Plan, as ultimately amended or revised, and securitization are~~Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. OnIn August 5, 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the ~~MPUS.~~Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for

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interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.

Regulatory Assets and Liabilities

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC ~~granted~~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, ~~interest~~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.

OnIn August ~~18,~~ 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of ~~September~~June 30, ~~2014,~~2015, the regulatory asset balance associated with the Kemper IGCC was ~~$104.3~~$198 million. The projected balance at March 31, 2016 is estimated to total approximately ~~$180~~$276 million. The amortization period ~~of 40 years proposed by Mississippi Power~~ for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

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~~In March 2013,~~See "2015 Mississippi Supreme Court Decision" herein for additional information related to the July 7, 2015 Mississippi PSC ~~issued~~order terminating the ~~2013 MPSC Rate Order approving retail~~Mirror CWIP rate ~~increases~~and requiring refund of ~~15% effective March 19, 2013, and 3% effective January~~collections under Mirror CWIP.

See Note 1 ~~2014, which collectively are designed~~ to ~~collect $156 million annually beginning in 2014. Because~~ the ~~2013 MPSC Rate Order did not provide for the inclusion~~financial statements of ~~CWIP in rate base as permitted by the Baseload Act,~~ Mississippi Power ~~continues to record AFUDC on the Kemper IGCC through the in-service date. To comply with the 2013 MPSC Rate Order, Mississippi Power is deferring the collections~~ under ~~the approved rates through the in-service date~~"Regulatory Assets and Liabilities" in a regulatory liability to be amortized and used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Mississippi Power is accruing interest costs on the unamortized balance of such regulatory liability for the benefit of retail customers. The dispositionItem 8 of the ~~regulatory liability will be determined by the Mississippi PSC in future cost recovery mechanism proceedings.~~Form 10-K for additional information.

Lignite Mine and CO₂ Pipeline Facilities

In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights ~~in the event that~~as Mississippi Power ~~does~~has not ~~satisfy~~satisfied its contractual obligation ~~with respect~~ to ~~deliveries of~~deliver captured CO₂ by May 11, 2015. ~~While~~Since May 11, 2015, Mississippi Power has ~~received no indication from either Denbury or~~been engaged in ongoing discussions with its off-takers regarding the status of the CO₂delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their ~~intent to terminate their respective~~agreement that do not affect pricing or minimum purchase quantities. Any termination or material modification of these agreements ~~any termination~~ could result in a material reduction in future ~~by-product~~chemical product sales revenues and could have a material financial impact ~~on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.~~

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Proposed Sale of Undivided Interest to SMEPA~~

In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the April 2011 power supply agreement were $17.5 million in 2013. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014.

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~~In 2012 and~~ on ~~January 2, 2014,~~ Mississippi Power ~~received $150 million and $75 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied~~ to the ~~purchase. While the expectation is that these amounts will be applied to the purchase price at closing,~~extent Mississippi Power ~~would be required~~is not able to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposits have been presented as a current liability in Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Mississippi Power's Condensed Statements of Cash Flows herein. In July 2013, Southern Company enteredenter into ~~an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.~~

By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle with respect to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The parties agreed to further amend the APA as follows: (1) Mississippi Power agreed to cap at $2.88 billion the portion of the purchase price for development and construction costs, net of the Cost Cap Exceptions; title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the plant's in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date.

The letter agreement also provides for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service. In addition, if the parties approve an amendment to the APA incorporating the terms of the letter agreement but do not execute the amendment before December 31, 2014, the parties agreed to extend the current APA through December 31, 2015.

The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement incorporating the principles of the amended APA, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase.

~~On October 9, 2014, Mississippi Power received an additional $50 million deposit from SMEPA to be applied to the purchase.~~other similar contractual arrangements.

The ultimate outcome of these matters cannot be determined at this time.

Termination of Proposed Sale of Undivided Interest to SMEPA

In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and SMEPA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction," respectively, herein for additional ~~information about the Kemper IGCC.~~information. The ultimate outcome of ~~these~~this tax ~~matters~~matter cannot be determined at this time.

~~Bonus Depreciation~~

In January 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which will apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million.

~~Investment Tax Credits~~

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through September 30, 2014, Mississippi Power had recorded tax benefits

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totaling $276.4 million for the Phase II credits, of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%~~of the CO~~₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.

~~Section 174 Research and Experimental Deduction~~

For the 2013 tax year, Southern Company included in its consolidated federal income tax return a deduction for R&E expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Mississippi Power recorded an unrecognized tax benefit of approximately $100 million as of September 30, 2014. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits" herein for additional information.

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has ~~increased generally~~occurred throughout the U.S. ~~In particular, personal injury, property damage, and other~~This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, ~~coal combustion residuals,~~CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such ~~matters, have become more frequent.~~matters.

The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See ~~the Notes~~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.

~~Sierra Club Settlement Agreement~~

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC and the scrubber project at Plant Daniel Units 1 and 2. In addition, the Sierra Club agreed to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings for the Kemper IGCC, including, but not limited to, the prudence review, and Plant Daniel for a period of three years from the date of the Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw all appeals associated with certification of the Kemper IGCC and the Plant Daniel Units 1 and 2 scrubber project, which the applicable courts granted in the third quarter 2014.

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agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "PSC Matters – Environmental Compliance Overview Plan" herein for additional information.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, and AFUDC.

Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery

As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of ~~$418.0~~$23 million ($~~258.1~~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, ~~$380.0~~$380 million ($~~234.7~~235 million after tax) in the first quarter 2014, ~~$40.0~~$40 million ($~~24.7~~25 million after tax) in the fourth quarter 2013, ~~$150.0~~$150 million ($~~92.6~~93 million after tax) in the third quarter 2013, ~~$450.0~~$450 million ($~~277.9~~278 million after tax) in the second quarter 2013, ~~$462.0~~$462 million ($~~285.3~~285 million after tax) in the first quarter 2013, and ~~$78.0~~$78 million ($~~48.2~~48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of ~~$1.98~~$2.08 billion ($~~1.22~~1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through ~~September~~June 30, ~~2014.~~2015.

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational ~~performance, operational~~ readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or ~~operations.~~operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

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MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Asset Retirement Obligations

The liability for AROs primarily relates to facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Mississippi Power has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. Mississippi Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Mississippi Power considers the liabilities for AROs to be critical accounting estimates.

See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Recently Issued Accounting Standards

~~On May 28, 2014, the~~The Financial Accounting Standards ~~Board issued~~Board's (FASB) ASC 606, Revenue from Contracts with Customers~~. ASC 606~~, revises the accounting for revenue recognition ~~and is~~ effective for fiscal years beginning after December 15, ~~2016.~~2017. Mississippi Power ~~is currently evaluating~~continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Mississippi Power's financial condition was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections, which as of June 30, 2015 was approximately $353 million including associated carrying costs, and the termination of the Mirror CWIP rate will further adversely impact Mississippi Power's financial condition and its ability to obtain financing needed for normal business operations and completion of the Kemper IGCC. Earnings for the ~~nine~~six months ended ~~September~~June 30, 2015 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. Earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper ~~IGCC; however,~~IGCC.

In addition to funding normal business operations and projected capital expenditures, Mississippi Power's ~~financial condition remained stable at September 30, 2014 as a result~~cash requirements primarily consist of ~~capital contributions~~$900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs. In addition, Mississippi Power byissued an 18-month promissory note to Southern ~~Company.~~Company in the aggregate principal amount of approximately $301 million related to the refund to SMEPA and expects to enter into a similar promissory note with Southern Company to fund the Mirror CWIP refund. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA," "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order,"" – 2015 Mississippi Supreme Court Decision," and " – 2015 Rate Case" herein for additional information. For the three-year period from 2015 through 2017, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental equipment for existing generating units, including the Plant Daniel scrubber project, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. See "Sources of Capital" herein for additional information.

Through ~~September~~June 30, ~~2014,~~2015, Mississippi Power has incurred non-recoverable cash expenditures of ~~$1.18~~$1.62 billion and is expected to incur approximately ~~$0.8~~$0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.

During the first ~~nine~~six months of ~~2014,~~2015, Mississippi Power received ~~$310.0 million in equity contributions and a $220.0 million loan from Southern Company which was repaid on September 29, 2014. In October 2014, Mississippi Power received an additional $100~~$75 million in equity contributions from Southern Company. In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. On June 3, 2015, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company as a result of Southern Company's refund of approximately $301 million in deposits and associated interest to SMEPA in connection with the termination of the APA. Mississippi Power intends to ~~continue to monitor its access to short-term~~utilize operating cash flows and ~~long-term capital markets~~lines of credit (to the extent available) as well as loans and, ~~bank credit arrangements. Management intends to utilize~~under certain circumstances, equity contributions ~~and/or loans~~ from Southern Company ~~and cash, as well as commercial paper, lines of credit, and bank notes as market conditions permit,~~ to fund Mississippi Power's short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled ~~$504.7~~$309 million for the first ~~nine~~six months of ~~2014,~~2015, an increase of ~~$218.0~~$131 million as compared to the corresponding period in ~~2013.~~2014. The increase in cash provided from operating activities is primarily due to ~~Kemper IGCC collections that are being deferred for future rate mitigation,~~R&E tax deductions and bonus depreciation reducing tax payments, an increase in fuel recovery, and a decrease in receivables, ~~and increases in~~partially offset by the timing of payments for accounts payable and ~~accrued compensation, partially offset by investment tax credits related~~fuel purchases. See Notes (B) and Note (G) to the ~~Kemper IGCC, income taxes primarily related to the Kemper IGCC, lower fuel inventory additions compared to the prior year, and an increase in under-recovered regulatory clause revenue.~~Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled ~~$1.0 billion~~$460 million for the first ~~nine~~six months of ~~2014~~2015 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled ~~$490.1~~$230 million for the first ~~nine~~six months of ~~2014~~2015 primarily due to ~~an increase in equity~~short-term bank loans, capital contributions ~~the issuance of bank notes,~~from Southern Company, and ~~the receipt of an additional SMEPA deposit,~~short-term borrowings, partially offset by ~~a return~~redemptions of ~~paid in capital.~~long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs," " – Regulatory Assets and Liabilities," and " – Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

Significant balance sheet changes for the first ~~nine~~six months of ~~2014~~2015 include ~~an increase~~a decrease in securities due within one year of ~~$798.0 million and a decrease in long-term debt of $533.7~~$349 million, primarily due to ~~bank loans~~refinancing or replacing maturing ~~by the end of the third quarter 2015, as well as an increase in the~~long-term debt with short-term loans. Additionally, long-term debt increased $301 million and interest-bearing refundable deposit ~~from~~decreased $275 million, due to an intercompany loan for repayment of the SMEPA of

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~$75 million.~~deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased ~~$212.4 million,~~$439 million; other regulatory ~~asset,~~assets, deferred increased ~~$54.8 million,~~$97 million; and ~~other~~the Mirror CWIP regulatory ~~liabilities, deferred~~liability increased ~~$122.7~~$82 million primarily ~~due to the Kemper IGCC. Additional changes included an increase in prepaid income taxes of $128.0 million, an increase in accrued income taxes of $86.4 million,~~associated with construction, operation, and ~~an increase in deferred charges related to income taxes of $57.4 million primarily related to R&E tax deductions and investment tax credits~~collections related to the Kemper IGCC. See ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Income Tax Matters"~~"Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current; accrued income taxes; accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and other deferred credits and liabilities increased primarily due to R&E tax deductions and the related reserve. Additional changes include increases in notes payable primarily due to new short-term bank loans and asset retirement obligations due to the CCR Rule. Total common stockholder's equity ~~decreased $155.5~~increased $164 million primarily due to the ~~estimated probable loss on the Kemper IGCC partially offset by the~~ receipt of ~~$310.0~~$75 million in capital contributions from Southern ~~Company.~~Company and due to net income during the second quarter 2015.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately ~~$812~~$900 million will be required through ~~September~~June 30, ~~2015~~2016 to fund maturities of ~~long-term~~bank term loans scheduled to mature on April 1, 2016 and $30 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs. See "Sources of Capital" herein for additional information.

The construction program of Mississippi Power is currently estimated to be ~~$1.5~~$1.0 billion ~~for 2014, $804~~in 2015, $354 million in 2016, and $229 million for ~~2015, and $324 million for 2016,~~2017, which includes expenditures related to the construction ~~and start-up~~ of the Kemper IGCC of ~~$1.3 billion for 2014, $551~~$801 million ~~for~~in 2015 and ~~$75~~$150 million ~~for~~in 2016. The amounts related to the construction and start-up of the Kemper IGCC exclude SMEPA's proposed acquisition of a 15% ownership share of the Kemper IGCC for approximately $569 million (including construction costs for all prior periods relating to its proposed ownership interest).

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See ~~FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" and~~ Note (B) to the Condensed Financial Statements under "Integrated Coal

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Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.

Sources of Capital

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

Mississippi Power ~~has~~ received ~~$245.3~~$245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note ~~(B)~~3 to the ~~Condensed Financial Statements~~financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" ~~herein~~in Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

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~~Table~~In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of ~~Contents~~

~~MISSISSIPPI POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. As of June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately ~~$1 billion at September~~$898 million primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs through June 30, ~~2014, primarily because of securities due within one year. Management~~2015. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions ~~and/or loans~~ from Southern Company ~~and cash, as well as commercial paper, lines of credit, and bank notes as market conditions permit,~~ to fund Mississippi Power's short-term capital needs.

At ~~September~~June 30, ~~2014,~~2015, Mississippi Power had approximately ~~$89.9~~$212 million of cash and cash equivalents. Committed credit arrangements with banks at ~~September~~June 30, ~~2014~~2015 were as follows:


Expires^(a)	Expires^(a)									Executable Term Loans				Due Within One Year				Expires^(a)									Executable Term Loans				Due Within One Year
2014		2015		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
2015																		2015	2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)	(in millions)					(in millions)				(in millions)				(in millions)				(in millions)			(in millions)				(in millions)				(in millions)
$	15	$	120	$	165	$	300	$	300	$	25	$	40	$	65	$	70	40	$	255	$	295	$	265	$	30	$	40	$	70	$	225


~~(a)~~	~~No credit arrangements expire in 2017 or 2018.~~

See Note 6 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

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A portion of the $265 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $40 million.

Most of these bank credit arrangements contain covenants that limit debt levels and typically contain cross default provisions to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specified threshold. Mississippi Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements, as needed prior to expiration.

A portion of the $300 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2014 was approximately $40.1 million.

In connection therewith, Mississippi Power may ~~also meet short-term cash needs through~~seek to extend the maturity dates and/or increase or decrease the lending commitments thereunder.

To the extent available, Mississippi Power may seek to utilize a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power ~~are~~would be loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

~~Mississippi Power had no commercial paper or~~Details of short-term ~~debt outstanding during the three-month period ended September 30, 2014.~~borrowings were as follows:



	Short-term Debt at June 30, 2015			Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Short-term bank debt	$	505	1.4%	$	460	1.4%	$	505


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to ~~below~~ BBB- and/or ~~Baa3.~~Baa3 or below. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At ~~September~~June 30, ~~2014,~~2015, the maximum potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 ~~were~~equaled approximately ~~$259~~$282 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade ~~could~~has impacted and may continue to impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

On June 5, 2015, Fitch downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power.

Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Mississippi Power) on CreditWatch with negative implications.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In ~~January 2014,~~March 2015, Mississippi Power repaid at maturity a $75 million bank term loan.

In April 2015, Mississippi Power entered into ~~an 18-month~~two floating rate bank ~~loan~~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 ~~loan was for $250 million~~loans in an aggregate principal amount ~~and proceeds were used for~~of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ~~continuous~~ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

In 2012, January 2014, and subsequent to September 30, 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 10.132% per annum for the period ended September 30, 2014 and 9.932% per annum for 2013, and are refundable to SMEPA upon termination of the asset purchase agreement related to such purchase or within 15 days of a request by SMEPA for a full or partial refund. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

~~In May 2014,~~June 2015, Mississippi Power issued ~~a 19-month~~an 18-month floating rate promissory note to Southern Company ~~for a loan~~ bearing interest based on one-month LIBOR. This ~~loan~~note was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program. This loan was repaid on September 29, 2014.

~~In May 2014 and August 2014, the Mississippi Business Finance Corporation (MBFC) issued $12.3 million and $10.5 million, respectively,~~an aggregate principal amount of ~~MBFC Taxable Revenue Bonds (Mississippi Power~~approximately $301 million, the amount paid by Southern Company ~~Project), Series 2013A for the benefit of Mississippi Power and proceeds were used~~ to ~~reimburse Mississippi Power for the cost~~SMEPA pursuant to Southern Company's guarantee of the ~~acquisition, construction, equipping, installation, and improvement~~return of ~~certain equipment and facilities for~~SMEPA's deposit in connection with the ~~lignite mining facility related~~termination of the APA. See Note (B) to the ~~Kemper IGCC. Any future issuances~~Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of ~~the Series 2013A bonds will be used for this same purpose. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities"~~Proposed Sale of ~~Mississippi Power in Item 7 of the Form 10-K~~Undivided Interest to SMEPA" herein for additional information.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in thousands)						(in thousands)						(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	331,878		$	265,752		$	870,093		$	705,828		$	250		$	260		$	481		$	538
Wholesale revenues, affiliates	102,631			96,795			242,527			263,624			85			68			199			140
Other revenues	747			2,220			2,293			5,517			2			1			4			2
Total operating revenues	435,256			364,767			1,114,913			974,969			337			329			684			680
Operating Expenses:
Fuel	178,281			133,464			420,896			363,466			105			118			243			243
Purchased power, non-affiliates	28,156			19,673			72,643			56,553			18			17			34			45
Purchased power, affiliates	12,796			7,011			58,475			21,158			4			16			14			46
Other operations and maintenance	46,347			41,309			168,392			154,920			69			69			121			122
Depreciation and amortization	59,508			41,094			162,524			126,152			60			52			118			103
Taxes other than income taxes	5,458			5,719			16,842			16,526			6			6			12			11
Total operating expenses	330,546			248,270			899,772			738,775			262			278			542			570
Operating Income	104,710			116,497			215,141			236,194			75			51			142			110
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22,983		)	(12,961		)	(66,952		)	(53,923		)	(23		)	(22		)	(45		)	(44		)
Other income (expense), net	5,511			(791		)	5,596			(2,739		)	1			—			1			—
Total other income and (expense)	(17,472		)	(13,752		)	(61,356		)	(56,662		)	(22		)	(22		)	(44		)	(44		)
Earnings Before Income Taxes	87,238			102,745			153,785			179,532			53			29			98			66
Income taxes	21,960			17,592			22,177			37,265
Income taxes (benefit)													1			(3		)	13			—
Net Income	65,278			85,153			131,608			142,267			52			32			85			66
Less: Net income attributable to noncontrolling interest	1,647			—			3,694			—
Less: Net income attributable to noncontrolling interests													6			1			6			2
Net Income Attributable to Southern Power Company	$	63,631		$	85,153		$	127,914		$	142,267		$	46		$	31		$	79		$	64

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

For the Three Months
Ended September 30, For the Nine Months
Ended September 30,
2014 2013 2014 2013
(in thousands) (in thousands)
Net Income $ 65,278
$ 85,153
$ 131,608
$ 142,267
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $-, $(1) and $-,
respectively (1 ) —
(1 ) —
Reclassification adjustment for amounts included in net income,
net of tax of $52, $213, $115 and $2,310 respectively 84
338
281
3,619
Total other comprehensive income (loss) 83
338
280
3,619
Less: Comprehensive income attributable to noncontrolling interest 1,647
—
3,694
—
Comprehensive Income Attributable to Southern Power Company $ 63,714
$ 85,491
$ 128,194
$ 145,886



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income	$	52	$	32	$	85	$	66
Other comprehensive income (loss)	—		—		—		—
Less: Comprehensive income attributable to noncontrolling interests	6		1		6		2
Comprehensive Income Attributable to Southern Power Company	$	46	$	31	$	79	$	64

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months Ended September 30,						For the Six Months Ended June 30,
	2014			2013			2015			2014
	(in thousands)						(in millions)
Operating Activities:
Net income	$	131,608		$	142,267		$	85		$	66
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	158,264			131,955			121			105
Deferred income taxes	(6,340		)	83,331			59			(3		)
Investment tax credits	38,215			(25,137		)	153			26
Amortization of investment tax credits							(10		)	(5		)
Deferred revenues	(2,452		)	3,136			(21		)	(24		)
Accrued income taxes, non-current							100			—
Other, net	3,853			962			10			7
Changes in certain current assets and liabilities —
-Receivables	(62,757		)	(28,486		)	(26		)	(34		)
-Fossil fuel stock	(1,565		)	881			5			(1		)
-Materials and supplies	(3,455		)	(5,902		)
-Prepaid income taxes	38,716			(12,485		)	(102		)	21
-Other current assets	(720		)	(2,017		)	—			(1		)
-Accounts payable	26,989			(4,282		)	(31		)	24
-Accrued taxes	62,124			12,550			(110		)	7
-Accrued interest	(13,451		)	(8,306		)
-Other current liabilities	2,000			235			18			5
Net cash provided from operating activities	371,029			288,702			251			193
Investing Activities:
Plant acquisition	(217,547		)	(111,600		)
Plant acquisitions							(408		)	(213		)
Property additions	(14,782		)	(463,873		)	(154		)	(11		)
Change in construction payables	(3,282		)	292			38			(3		)
Payments pursuant to long-term service agreements	(41,782		)	(40,978		)	(45		)	(23		)
Investment in restricted cash	(166		)	(20,000		)
Other investing activities	(9,996		)	(1,724		)	(1		)	(11		)
Net cash used for investing activities	(287,555		)	(637,883		)	(570		)	(261		)
Financing Activities:
Increase in notes payable, net	19,995			120,798
Proceeds —
Senior notes	—			300,000
Capital contributions	(3,628		)	1,897
Other long-term debt	10,199			22,722
Repayments — Other long-term debt	(818		)	(220		)
Distributions to noncontrolling interest	(150		)	(146		)
Contributions from noncontrolling interest	7,492			16,802
Increase (decrease) in notes payable, net							(195		)	73
Proceeds — Senior notes							650			—
Distributions to noncontrolling interests							(1		)	—
Contributions from noncontrolling interests							78			7
Payment of common stock dividends	(98,340		)	(96,840		)	(65		)	(66		)
Other financing activities	(184		)	(2,287		)	(3		)	9
Net cash provided from (used for) financing activities	(65,434		)	362,726
Net cash provided from financing activities							464			23
Net Change in Cash and Cash Equivalents	18,040			13,545			145			(45		)
Cash and Cash Equivalents at Beginning of Period	68,744			28,592			75			69
Cash and Cash Equivalents at End of Period	$	86,784		$	42,137		$	220		$	24
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(113) and $7,682 capitalized for 2014 and 2013, respectively)	$	78,496		$	55,190
Interest (net of $1 and $- capitalized for 2015 and 2014, respectively)							$	35		$	43
Income taxes, net	(91,193		)	(6,518		)	(72		)	(59		)
Noncash transactions — accrued property additions at end of period	549			36,370
Noncash transactions — Accrued property additions at end of period							38			5

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


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

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~THIRD~~SECOND QUARTER ~~2014~~2015 vs. ~~THIRD~~SECOND QUARTER ~~2013~~2014

AND

YEAR-TO-DATE ~~2014~~2015 vs. YEAR-TO-DATE ~~2013~~2014

OVERVIEW

Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants, and entry into PPAs primarily with ~~investor owned~~investor-owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.

~~Southern Power and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by~~During the six months ended June 30, 2015, Southern Power acquired ~~all~~approximately 353 MWs of ~~the outstanding membership interests of Adobe Solar, LLC (Adobe) and Macho Springs Solar, LLC (Macho Springs) on April 17, 2014 and May 22, 2014, respectively. The two~~additional solar facilities ~~began commercial operation~~including the five Georgia construction projects located in ~~May 2014 with~~Taylor and Butler Counties, as well as the ~~approximate 20-MW Adobe solar photovoltaic facility serving a PPA with Southern California Edison (SCE) through 2034~~Lost Hills, Blackwell, and ~~the approximate 50-MW Macho Springs solar photovoltaic facility serving a PPA with El Paso Electric Company (EPE) also through 2034.~~

~~Subsequent to September 30, 2014,~~North Star projects located in California. Southern Power through its wholly-owned subsidiary SG2 Holdings, LLC (Holdings), acquired all of the outstanding membership interests of SG2 Imperial Valley, LLC (SG2) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project. SG2 is constructingalso entered into an agreement to acquire an approximately ~~150-MW solar photovoltaic~~299-MW wind facility, located in ~~Southern California (Imperial Facility), which is expected to begin commercial operation later in the fourth quarter 2014. Prior to commercial operation, subject to~~Oklahoma, contingent upon certain ~~terms~~construction and ~~conditions, including the payment of~~project milestones. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional agreed upon capital contributions, First Solar will become a non-controlling minority member of Holdings. The Imperial Facility's output is contracted under a 25-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy.information.

~~To evaluate operating results and to ensure Southern Power's ability to meet its contractual commitments to customers,~~ Southern Power ~~focuses~~continues to focus on several key performance indicators. These indicators include peak season equivalent forced outage rate, ~~(Peak Season EFOR),~~ contract availability, and net income. Peak Season EFOR defines the hours during peak demand times when Southern Power's generating units are not available due to forced outages (a low metric is optimal). Contract availability measures the percentage of scheduled hours delivered. Net income is the primary measureFor additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern ~~Power's financial performance.~~Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$(21.6) (25.3) $(14.4) (10.1)

Net income attributable to Southern Power for the ~~third~~second quarter ~~2014~~2015 was ~~$63.6~~$46 million compared to ~~$85.2~~$31 million for the corresponding period in ~~2013.~~2014. The ~~decrease~~increase was primarily due to an increase in depreciation, lower capitalized interest due to reduced construction, and lower ITCs in income taxes, partially offset by an increase in energy revenue from non-affiliates primarily due to increased revenue ~~from new solar contracts.~~and lower fuel and purchased power expenses.

Net income attributable to Southern Power for year-to-date ~~2014~~2015 was ~~$127.9~~$79 million compared to ~~$142.3~~$64 million for the corresponding period in ~~2013.~~2014. The ~~decrease~~increase was primarily due to a decrease in ~~capacity revenues, increased depreciation arising from new~~

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~solar facilities, lower ITCs in income taxes, and lower capitalized interest due to reduced construction. The decrease was~~purchased power expenses, partially offset by ~~an increase~~increases in ~~energy revenue from non-affiliates primarily from new solar contracts~~depreciation and ~~beneficial changes in certain state~~ income taxes.

Wholesale Revenues – Non-Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$66.1 24.9 $164.3 23.3

Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

~~Details~~

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Table of ~~the changes in wholesale~~Contents

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale revenues from non-affiliates for the second quarter 2015 were ~~as follows:~~

Third Quarter
2014

Year-to-Date
2014
(in millions) (% change) (in millions) (% change)
Wholesale Revenues – Non-Affiliates, prior year $ 265.8
$ 705.8

Change resulting from -
Capacity (4.4 ) (1.6 ) (10.0 ) (1.4 )
Energy – solar 20.0
7.5
60.3
8.5
Energy – other 50.5
19.0
114.0
16.2
Wholesale Revenues – Non-Affiliates, current year $ 331.9
24.9 % $ 870.1
23.3 %

$250 million compared to $260 million for the corresponding period in 2014. The ~~increase~~decrease was due to a $5 million decrease in energy – solar was primarily a result of new solar PPAs. The increase in energy – other, primarily from gas plants, arose from requirements contracts, increased revenue from existing contracts, and energy sales, ~~not under PPAs,~~ primarily as a result of ~~higher demand. The increases were~~decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by aincreased sales volumes and new solar PPAs. The decrease in ~~capacity~~energy revenues ~~primarily as a result of periodic scheduled adjustments to requirements contracts. The increase in energy sales~~ reflects a ~~4.6% and 16.9% increase~~14% decrease in the average price of energy, ~~and~~partially offset by a ~~47.0% and 26.8%~~12% increase in KWH ~~sales~~sales. In addition, capacity revenues decreased $5 million primarily due to PPA expirations.

Wholesale revenues from non-affiliates for year-to-date 2015 were $481 million compared to $538 million for the ~~third quarter~~corresponding period in 2014. The decrease was due to a $44 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and ~~year-to-date 2014, respectively.~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Power Sales Agreements"~~new solar PPAs. The decrease in energy revenues reflects a 17% decrease in the average price of ~~Southern Power~~energy, partially offset by a 5% increase in ~~Item 7 of the Form 10-K for additional information.~~KWH sales. In addition, capacity revenues decreased $13 million primarily due to PPA expirations.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$5.8 6.0 $(21.1) (8.0)

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 ~~third~~second quarter ~~2014~~2015 were ~~$102.6~~$85 million compared to ~~$96.8~~$68 million for the corresponding period in ~~2013.~~2014. The increase was the result of a ~~$9.3~~$10 million increase in energy ~~revenue, primarily due to an~~revenues and a $7 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC ~~reflecting~~as a ~~13.2%~~result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 61% increase in KWH sales, partially offset by a 21% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.

Wholesale revenues from affiliates for year-to-date 2015 were $199 million compared to $140 million for the corresponding period in 2014. The increase was the result of a $50 million increase in energy revenues and a $9 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of ~~higher~~lower natural gas ~~prices. This~~prices, which increased demand for Southern Power Company's resources. The increase ~~was~~in energy revenues reflects a 110% increase in KWH sales, partially offset by a ~~$3.5 million~~22% decrease in the average price of energy. The increase in capacity ~~revenue as a~~revenues was primarily the result of new PPAs.

Fuel and Purchased Power Expenses



	Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(13	)	(11.0)	$	—		—
Purchased power – non-affiliates	1			5.9	(11		)	(24.4	)
Purchased power – affiliates	(12		)	(75.0)	(32		)	(69.6	)
Total fuel and purchased power expenses	$	(24	)		$	(43	)

Southern Power's PPAs for natural gas-fired generation generally provide that the ~~completion~~purchasers are responsible for substantially all of ~~an existing contract for Plant Dahlberg.~~the cost of fuel. Consequently, any increase or decrease in such fuel cost is generally

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Wholesale revenues from affiliates for yea~~r-to-date 2014 were $242.5 million compared to $263.6 million for the corresponding period in 2013. The decrease was the result of a decrease in energy revenue, primarily due to a $24.2 million decrease in energy sales under the IIC, reflecting a 25.2% decrease in KWH sales, primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. Also contributing to the decrease was a $4.6 million decrease in capacity revenue as a result of the completion of an existing contract for Plant Dahlberg. The decrease was partially offset by a $7.7 million increase in energy revenues under existing contracts, reflecting a 21.7% increase in the average price of energy and a 14.2% increase in KWH sales, primarily as a result of higher natural gas prices and increased demand.

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information.~~

~~Fuel and Purchased Power Expenses~~

Third Quarter 2014
vs.
Third Quarter 2013 Year-to-Date 2014
vs.
Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
Fuel $ 44.9
33.6 $ 57.4
15.8
Purchased power – non-affiliates 8.4
42.9 16.1
28.6
Purchased power – affiliates 5.8
82.8 37.3
175.8
Total fuel and purchased power expenses $ 59.1
$ 110.8

Southern Power PPAs for natural gas-fired generation generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel cost is generally accompanied by an increase or decrease in related fuel ~~revenue~~revenues under the PPAs and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.

Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power Company, ~~affiliate-owned generation,~~affiliate companies, or external ~~purchases.~~parties.

In the ~~third~~second quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$219.2~~$127 million compared to ~~$160.1~~$151 million for the corresponding period in ~~2013. Fuel and purchased power expenses increased $59.1~~2014. The decrease was the result of a $58 million ~~reflecting a 13.7% increase~~decrease in the average cost of fuel and purchased power primarily due to lower natural gas ~~and~~prices, partially offset by a ~~14.2%~~$34 million net increase in the ~~average cost of purchased power primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. This increase also reflects a 19.1% increase in the~~total volume of KWHs generated and purchased ~~and generated~~ primarily ~~as a result of higher demand.~~due to increased demand resulting from lower natural gas prices.

For year-to-date ~~2014,~~2015, total fuel and purchased power expenses were ~~$552.0~~$291 million compared to ~~$441.2~~$334 million for the corresponding period in ~~2013. Fuel~~2014. The decrease was a result of a $154 million decrease in the average cost of fuel and purchased power ~~expenses~~primarily due to lower natural gas prices, partially offset by a $111 million net increase in the total volume of KWHs generated and purchased primarily due to increased ~~$110.8~~demand resulting from lower natural gas prices.

Fuel

In the second quarter 2015, fuel expense was $105 million ~~reflecting~~compared to $118 million for the corresponding period in 2014. The decrease was due to a ~~24.2% increase in~~36.1% decrease associated with the average cost of natural gas ~~and a 20.1% increase in the average cost of purchased power primarily as a result of higher natural gas prices and the availability of lower cost affiliate power.~~

~~Fuel~~

In the third quarter 2014, fuel expense was $178.3 million compared to $133.4 million for the corresponding period in 2013. The increase was due to a $22.5 million increase associated with the higher average cost of fuel per KWH generated, ~~primarily due to higher average natural gas prices and~~partially offset by a ~~$22.4 million~~40.6% increase associated with the volume of KWHs generated, primarily ~~due to higher demand.~~as a result of increased demand resulting from lower natural gas prices.

For year-to-date 2015 and for the corresponding period in 2014, fuel expense was ~~$420.9~~$243 million. While there was no overall change, a $152 million increase in the total cost of fuel attributable to the volume of KWHs generated was offset by a $152 million decrease in the average cost of natural gas per KWH generated.

Purchased Power – Non-Affiliates and Affiliates

In the second quarter 2015, purchased power expense was $22 million compared to ~~$363.5~~$33 million for the corresponding period in ~~2013.~~2014. For year-to-date 2015, purchased power expense was $48 million compared to $91 million for the corresponding period in 2014. The decreases were primarily the result of 37.4% and 45.6% decreases in the volume of KWHs purchased in the second quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices which resulted in higher use of Southern Power Company's generation resources.

Other Operations and Maintenance Expenses

In the second quarter 2015 and for the corresponding period in 2014, other operations and maintenance expenses were $69 million. While there was no overall change, a decrease in outage expense of $10 million was offset by a $10 million increase in expenses associated with support services, transmission, and new plants placed in service in 2014 and 2015.

For year-to-date 2015, other operations and maintenance expenses were $121 million compared to $122 million for the corresponding period in 2014. The decrease was primarily due to a ~~$79.1~~$17 million ~~increase associated with the higher average cost of fuel per KWH~~decrease in outage expense,

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~generated primarily due to higher average natural gas prices, partially~~largely offset by a ~~$21.7~~$16 million ~~decrease~~increase in expenses associated with ~~the volume of KWHs generated primarily as a result of the availability of lower cost affiliate power.~~

~~Purchased Power~~

In the third quarter 2014, purchased power expense was $40.9 million compared to $26.7 million for the corresponding period in 2013. The increase was due to a $9.1 million increase associated with the volume of KWHs purchased due to the availability of lower cost affiliate power and a $5.1 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices.

For year-to-date 2014, purchased power expense was $131.1 million compared to $77.7 million for the corresponding period in 2013. The increase was due to a $31.5 million increase associated with the volume of KWHs purchased due to the availability of lower cost affiliate power and a $21.9 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices.

~~Other Operations and Maintenance Expenses~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$5.0 12.2 $13.5 8.7

In the third quarter 2014, other operations and maintenance expenses were $46.3 million compared to $41.3 million for the corresponding period in 2013. For year-to-date 2014, other operations and maintenance expenses were $168.4 million compared to $154.9 million for the corresponding period in 2013. The increases were primarily due to scheduled outage and maintenance related costs and increases in labor costs, as well as costs associated with the new solar plants.

~~Depreciation and Amortization~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$18.4 44.8 $36.3 28.8

In the third quarter 2014, depreciation and amortization was $59.5 million compared to $41.1 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $162.5 million compared to $126.2 million for the corresponding period in 2013. The increases were primarily due to an increase in depreciation expense related to solar facilities being placed in service in 2013 and 2014 and additional component depreciation as a result of production being greater during the summer months.

~~See Note (A) to the Condensed Financial Statements herein for additional information.~~

~~Interest Expense, Net of Amounts Capitalized~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$10.0 77.3 $13.0 24.2

In the third quarter 2014, interest expense, net of amounts capitalized was $23.0 million compared to $13.0 million for the corresponding period in 2013. For year-to-date 2014, interest expense, net of amounts capitalized was $66.9 million compared to $53.9 million for the corresponding period in 2013. The increases were primarily due to a decrease in capitalized interest due to reduced construction activities in 2014 and the issuance of senior notes in July 2013.

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~~Other Income (Expense), Net~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions) (% change) (change in millions) (% change)
$6.3 N/M $8.3 N/M

~~N/M – Not meaningful~~

In the third quarter 2014, other income (expense), net was $5.5 million compared to $(0.8) million for the corresponding period in 2013. For year-to-date 2014, other income (expense), net was $5.6 million compared to $(2.7) million for the corresponding period in 2013. The increases were primarily due to the recognition of a bargain purchase gain arising from a solar acquisition.

~~See Note (I) to the Condensed Financial Statements herein for additional information.~~

~~Income Taxes~~

Third Quarter 2014 vs. Third Quarter 2013 Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)
(% change) (change in millions) (% change)
$4.4 24.8 $(15.1) (40.5)

In the third quarter 2014, income taxes were $22.0 million compared to $17.6 million for the corresponding period in 2013. The increase was primarily due to lower ITC-related items and state apportionment changes, partially offset by lower pretax income and an increase in state income tax credits.

For year-to-date 2014, income taxes were $22.2 million compared to $37.3 million for the corresponding period in 2013. The decrease was primarily due to lower pretax income, the impact of state apportionment changes reducing Southern Power's deferred tax liabilities resulting from the addition ofsupport services, new plants placed in service in 2014 and ~~2013, a change~~2015, and transmission.

Depreciation and Amortization

In the second quarter 2015, depreciation and amortization was $60 million compared to $52 million for the corresponding period in 2014. For year-to-date 2015, depreciation and amortization was $118 million compared to $103 million for the corresponding period in 2014. The increases were primarily related to solar facilities placed in service in 2014 and 2015.

Income Taxes (Benefit)

N/M – Not meaningful

In the second quarter 2015, income taxes were $1 million compared to an income tax ~~filing method~~benefit of $3 million for ~~North Carolina, an increase~~the corresponding period in 2014. For year-to-date 2015, income taxes were $13 million. The increases were primarily due to higher pre-tax earnings in 2015 and beneficial state income tax ~~credits, and beneficial~~ changes in ~~certain state income tax laws~~2014, partially offset by ~~lower ITC-related items.~~increased federal income tax benefits related to ITCs in 2015.

See Note (G) to the Condensed Financial Statements herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors ~~include:~~include Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's ~~target~~ market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy, including successfully expanding investments in renewable energy projects, and to construct generating ~~facilities.~~facilities, including the impact of federal ITCs.

Other factors that could influence future earnings include weather, demand, cost of generating units within the power pool, and operational limitations. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that

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permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM) and the Cross State Air Pollution Rule (CSAPR).

On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, North Carolina, and ~~the EPA's proposed rules~~Texas) to revise or remove state implementation plan (SIP) provisions regarding ~~the regulation of~~ excess emissions that occur during periods of ~~startup, shutdown, or malfunction (SSM).~~SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.

On ~~April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to~~July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for ~~further proceedings. On October 23, 2014, the U.S. Court~~a number of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements,states, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama, Florida, Georgia, North Carolina, and ~~North Carolina)~~Texas. The court's decision leaves the emissions trading program in place and remands the rule to ~~revise their SSM provisions within 18 months after issuance of~~ the ~~final~~EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of ~~the proposed SSM rule~~this decision will depend on ~~the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges~~additional rulemaking and cannot be determined at this time.

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Water Quality~~Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – ~~Environmental Statutes and Regulations~~ – ~~Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.~~

~~Global Climate Issues~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters –~~ Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's ~~current and~~ proposed regulation of ~~GHG emissions under the Clean Air Act.~~CO₂ from fossil-fuel-fired electric generating units.

On ~~June 18, 2014,~~August 3, 2015, the EPA ~~published~~released pre-publication versions of two final rules that would limit CO₂ emissions from fossil fuel-fired electric generating units. One of the ~~proposed Clean Power Plan, setting forth~~final rules contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to ~~address CO~~₂ ~~emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final~~meet EPA-mandated CO₂ emission ~~rate goals~~rates for existing units. The EPA's final guidelines require state plans to ~~be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposed~~meet interim CO₂ performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through existing PPAs. However, the ultimate financial and operational impact of the final rules on Southern Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

Acquisitions

During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy, which are included in Southern Power's capital program estimates for ~~modified and~~2015.

Kay County Wind Facility

On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on

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reconstructed fossil fuel-fired electric generating units. The proposed guidelines and standards could result in operational restrictions and material compliance costs. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through market-based contracts.

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the Clean Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upon numerous factors. These factors include: the structure, timing, and content of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and court decisions; the impact of future changes in generation and emissions-related technology and costs; and the time periods over which compliance will be required.

~~Acquisitions~~

~~Adobe Solar, LLC~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Acquisitions" of Southern Power in Item 7 of the Form 10-K and Note (I) to the Condensed Financial Statements herein for additional information.~~

~~On April 17, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Adobe from Sun Edison, LLC, the original developer of the project. Adobe constructed~~performance testing. Kay Wind is constructing and owns an approximately ~~20-MW solar photovoltaic~~299-MW wind facility in ~~Kern~~Kay County, ~~California.~~Oklahoma. The ~~solar~~wind facility ~~began~~is expected to begin commercial operation ~~on May 21, 2014~~in late 2015, and the entire output of the ~~plant~~facility is contracted under aseparate 20-year ~~PPA~~PPAs with ~~SCE.~~

~~Macho Springs Solar, LLC~~Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

Lost Hills-Blackwell Solar Facilities

On ~~May 22, 2014,~~April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and ~~TRE, through STR, acquired~~the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the ~~outstanding membership interests of Macho Springs from First Solar Development, LLC,~~federal tax benefits with respect to the ~~original developer of the project. Macho Springs~~transaction. Lost Hills Blackwell constructed and owns anthe approximately ~~50-MW~~22-MW Lost Hills and the approximately 13-MW Blackwell solar ~~photovoltaic facility~~facilities in ~~Luna~~Kern County, ~~New Mexico. The~~California. These solar ~~facility~~facilities began commercial operation on ~~May 23, 2014~~April 17, 2015, and ~~the~~their entire output ~~of the plant~~ is contracted under ~~a 20-year PPA with EPE.~~ ~~See Note (I)~~PPAs, initially to the ~~Condensed Financial Statements herein for additional information.~~City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years.

~~SG2 Imperial Valley, LLC~~North Star Solar Facility

~~Subsequent to September~~On April 30, ~~2014,~~2015, Southern Power Company, through its ~~wholly-owned~~ subsidiary ~~Holdings,~~SRP, acquired ~~all~~100% of the ~~outstanding~~class A membership interests of ~~SG2~~NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the ~~project. SG2~~project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is ~~constructing~~entitled to substantially all of the ~~Imperial Facility, an~~federal tax benefits with respect to the transaction. North Star constructed and owns the approximately ~~150-MW~~61-MW North Star solar ~~photovoltaic~~ facility in ~~Southern California, which is expected to begin~~Fresno County, California. The solar facility began commercial operation ~~later in~~on June 20, 2015, and the ~~fourth quarter 2014. The Imperial Facility's~~entire output of the project is contracted under a ~~25-year~~20-year PPA with ~~San Diego~~Pacific Gas &and Electric ~~Company, a subsidiary of Sempra Energy.~~Company.

Construction Projects

In ~~connection~~December 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of five separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this acquisition, Holdings made an aggregate payment (consisting of cash consideration and a secured promissory note) of approximately $128 million to the subsidiary of First Solar and became obligated to pay the contract price as it becomes due under the construction contract for the Imperial Facility. In addition, subject to certain terms and conditions, a subsidiary of First Solar will be admitted as a minority member of Holdings, andtime.

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~~subsidiaries of each of~~ Southern Power ~~and First Solar, as members of Holdings, will make capital contributions~~Company's construction projects are detailed in the table below:

Solar Project

Seller

Nameplate Capacity

County Location in Georgia

Expected Commercial Operation Date

PPA Counterparty
for Entire Plant Output

PPA Contract Period

Estimated Construction Cost

(MW)

(in millions)

Taylor County

N/A

146

Taylor

Fourth quarter 2016

Cobb, Flint, and Sawnee Electric Membership Corporations

25 years

260

$280

Decatur Parkway

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(a)

25 years

170

$173

(b)

Decatur County

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(a)

20 years

$47

(b)

Butler

CERSM, LLC and Community Energy, Inc.

103

Taylor

December 2016

Georgia Power^(a)

30 years

220

$230

(b)

Pawpaw

Longview Solar, LLC

Taylor

December 2015

Georgia Power^(a)

30 years

$80

(b)

Butler Solar Farm

Strata Solar Development, LLC

Taylor

December 2015

Georgia Power^(a)

20 years

$48

(b)

(a) Subject to Holdings that will be used to pay off the previously issued secured promissory note and to fund the Imperial Facility's construction costs. As a result of these capital contributions, the aggregate purchase price payable by Southern Power forFERC approval.

(b) Includes the acquisition ~~is approximately $508 million. Following these capital contributions, Southern Power will indirectly own 100% of the class A membership interests of Holdings and be entitled to 51%~~price of all ~~cash distributions from Holdings, and First Solar will indirectly own 100% of the class B~~outstanding membership interests of Holdings and be entitled to 49% of all cash distributions from Holdings. In addition, Southern Power will be entitled to substantially all of the federal tax benefits with respect to this transaction.

If the Imperial Facility does not achieve substantial completion by a certain date, Southern Power may require that First Solar make a rescission payment to Southern Power in an amount equal to Southern Power's investment in Holdings, and Southern Power would be required to transfer its ownership interests in SG2 back to First Solar.

~~The ultimate outcome of this matter cannot be determined at this time.~~interests.

See ~~Note (I) to the Condensed Financial Statements~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

Power Sales Agreements

See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS~~BUSINESS – ~~FUTURE EARNINGS POTENTIAL~~"The Southern Company System – ~~"Power Sales Agreements" of~~ Southern ~~Power~~Power" in Item 71 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.

Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern ~~Power has assumed or entered into additional PPAs during~~Power's existing fleet, the ~~past nine months primarily in connection with its acquisitions of solar facilities. The~~ coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of ~~September~~June 30, ~~2014~~2015 from the period ended December 31, ~~2013.~~2014.

FERC Matters

Southern Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

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Other Matters

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has ~~increased generally~~occurred throughout the U.S. ~~In particular, personal injury, property damage, and other~~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, have become more frequent.~~matters.

The ultimate outcome of such pending or potential litigation against Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.

Recently Issued Accounting Standards

The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Southern Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU has not yet been determined.

On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Power currently reflects unamortized debt issuance costs in other deferred charges and assets – non-affiliated on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Power.

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~~policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.~~

~~Recently Issued Accounting Standards~~

~~On May 28, 2014, the Financial Accounting Standards Board issued ASC 606,~~ ~~Revenue from Contracts with Customers~~. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Southern Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at ~~September~~June 30, ~~2014.~~2015. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as ~~its~~ bank credit ~~arrangements~~agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.

Net cash provided from operating activities totaled ~~$371.0~~$251 million for the first ~~nine~~six months of ~~2014, an increase of $82.3 million as~~2015, compared to $193 million for the first ~~nine~~six months of ~~2013.~~2014. The increase in cash provided from operating activities was primarily due to ~~cash received for ITCs related to new plants placed~~lower purchased power costs and an increase in ~~service in 2013 and 2014.~~income tax benefits received. Net cash used for investing activities totaled ~~$287.6~~$570 million for the first ~~nine~~six months of ~~2014~~2015 primarily due to the Lost Hills, Blackwell, and North Star acquisitions and expenditures related to the ~~acquisitions~~construction of ~~Adobe and Macho Springs and payments pursuant to long-term service agreements.~~new solar facilities. Net cash ~~used for~~provided from financing activities totaled ~~$65.4~~$464 million for the first ~~nine~~six months of ~~2014~~2015 primarily due to the ~~payment~~issuance of ~~common stock dividends.~~additional senior notes in May 2015. Fluctuations in cash flow from financing activities vary ~~year~~from period to ~~year~~period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first ~~nine~~six months of ~~2014~~2015 include a ~~$136.0~~$300 million increase in plant in service, net of depreciation primarily due to the Lost Hills, Blackwell, and North Star acquisitions and a $190 million increase in CWIP primarily due to the construction of ~~Adobe and Macho Springs.~~new solar facilities. Other significant changes ~~which were~~include an increase in long-term debt of $642 million primarily ~~the~~as a result of the ~~timing and amount~~issuance of ~~ITCs recognized~~senior notes in 2014 as compared to 2013, include a $55.8 million increase in accumulated deferred investment tax credits, and a $25.1 million increase in accumulated deferred income taxes. Additionally, there was a $20.0 million increase in notes payable for commercial paper and a $33.2 million increase in affiliated accounts payable.May 2015.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. ~~Approximately~~Subsequent to June 30, 2015, $525 million ~~will be required through September 30, 2015 to fund~~of long-term debt was repaid at maturity. There are no other scheduled maturities of long-term ~~debt.~~debt through June 30, 2016.

The ~~construction~~capital program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to be approximately ~~$800 million~~$1.4 billion for ~~2014,~~2015, which includes ~~expenditures related to the acquisition~~approximately $1.3 billion for acquisitions and/or construction of ~~SG2 of approximately $508 million.~~new generating facilities. See Note (I) to the Condensed Financial Statements herein for additional information. Actual ~~construction~~capital costs may vary from these estimates because of changes in factors such ~~as:~~as business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

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Sources of Capital

Southern Power ~~may use~~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, ~~external funds, or~~short-term debt, securities issuances, term loans, and equity ~~capital or loans~~contributions from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks.Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.

Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. In 2015, Southern Power has utilized the capital markets to issue additional senior notes and expects to utilize the capital

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markets, bank term loans, and commercial paper markets, as the source of funds for the majority of its maturities and to meet short-term liquidity needs, including funding acquisition and construction costs.

To meet liquidity and capital resource requirements, Southern Power had at ~~September~~June 30, ~~2014~~2015 cash and cash equivalents of approximately ~~$86.8~~$220 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which ~~$499~~$466 million is unused.

The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern ~~Power Company.~~Power. Southern Power Company is currently in compliance with all covenants in the Facility.

Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power Company's commercial paper program. Subject to applicable market conditions, Southern Power Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

Southern ~~Power's~~Power Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate ~~purposes.~~purposes, including maturing debt. Subsequent to June 30, 2015, commercial paper was used to partially fund the maturity of long-term debt in July 2015.

Details of short-term borrowings were as follows:

Commercial Paper at
the End of the Period

Commercial Paper During the Period^(a)

Amount
Outstanding

Weighted
Average
Interest
Rate

Average
Outstanding

Weighted
Average
Interest
Rate

Maximum
Amount
Outstanding
(in millions) (in millions) (in millions)
September 30, 2014: $ 20
0.3 % $ 44
0.3 % $ 83



	Commercial Paper at the End of the Period				Commercial Paper During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
June 30, 2015:	$	—	—	%	$	163	0.6	%	$	339

~~(a)~~(*) Average and maximum amounts are based upon daily balances during the three-month period ended ~~September~~June 30, ~~2014.~~2015.

~~Management~~Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, ~~short-term bank notes,~~ and ~~cash.~~operating cash flows.

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.

The maximum potential collateral requirements under these contracts at June 30, 2015 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	320
Below BBB- and/or Baa3	1,081

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~The maximum potential collateral requirements under these contracts at September 30, 2014 were as follows:~~

Credit Ratings Maximum Potential
Collateral
Requirements
(in millions)
At BBB and Baa2 $ 9
At BBB- and/or Baa3 318
Below BBB- and/or Baa3 1,018

Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern ~~Power Company's~~Power's ability to access capital markets, particularly the short-term debt market.

In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern ~~Power's~~Power Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.

Financing Activities

~~During the nine months ended September 30, 2014,~~In May 2015, Southern Power ~~prepaid $0.8~~Company issued $350 million aggregate principal amount of ~~long-term debt payable to TRE and issued $3.9 million due April 30, 2034, $5.3 million due May 31, 2034, $0.8 million due April 30, 2033, and an additional $0.1 million~~Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, ~~2032 under promissory notes payable to TRE related to the financing of Adobe, Macho Springs, Campo Verde Solar, LLC, and Apex Nevada Solar, LLC, respectively.~~2015.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS

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.



Registrant	Applicable Notes

Southern Company	A, B, C, D, E, F, G, H, I, J

Alabama Power	A, B, C, E, F, G, H

Georgia Power	A, B, C, E, F, G, H

Gulf Power	A, B, C, E, F, G, H

Mississippi Power	A, B, C, E, F, G, H

Southern Power	A, B, C, D, E, G, H, I

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(UNAUDITED)


(A)	INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, ~~2013~~2014 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended ~~September~~June 30, ~~2014~~2015 and ~~2013.~~2014. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. In March 2015, in connection with this retirement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.

In June 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error, as well as the current period. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.

Recently Issued Accounting Standards

The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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(UNAUDITED)

On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of any registrant.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and ~~Alabama~~Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional ~~information.~~information regarding the EPA's regulation of CCR.

~~Asset~~On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new asset retirement obligations (ARO) for facilities that are ~~computed~~subject to the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the ~~present value~~quantities of CCR at each site, the ~~ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. In September 2014, Alabama Power performed a new ARO liability cost study related~~traditional operating companies expect to ~~Alabama Power's assets, which increased the estimated ARO liability by approximately $52 million.~~periodically update these estimates.

As of ~~September~~June 30, ~~2014 and 2013,~~2015, details of the ~~ARO~~AROs, including those related to ~~Alabama Power's assets~~the CCR Rule, included in Southern Company's and ~~Alabama Power's~~the traditional operating companies' Condensed Balance Sheets herein ~~are~~were as follows:


	2014			2013		Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)					(in millions)
Balance at beginning of year	$	730		$	589	$	2,201		$	829		$	1,255		$	17	$	48
Liabilities incurred	—			—		612			401			—			71		97
Liabilities settled	(2		)	—		(10		)	(1		)	(9		)	—		—
Accretion	33			29		53			23			28			—		1
Cash flow revisions	52			102		58			—			82			4		2
Balance at end of period	$	813		$	720	$	2,914		$	1,252		$	1,356		$	92	$	148

The ~~increase~~increases in liabilities incurred and cash flow revisions ~~as of September~~for the six months ended June 30, ~~2014~~2015 primarily ~~relates~~relate to an increase in ~~Alabama Power's~~ AROs associated with ~~asbestos at its steam generation facilities.~~facilities impacted by the CCR Rule.

In connection with a proposed settlement related to the closure of Plant Scholz, Gulf Power may incur additional AROs associated with CCR of approximately $15 million to $35 million.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~Depreciation~~

Beginning in 2014, Southern Power changed the method of depreciation for its property, plant, and equipment from composite depreciation to component depreciation. As a result, certain generation assets are depreciated on a units-of-production basis to better match outage and maintenance costs to the usage of, and revenues from, these assets. The expense will fluctuate quarterly based on unit run time, but this change in methodology is not expected to have a material impact on an annual basis on the financial statements of Southern Company or Southern Power. The book value of plant-in-service as of September 30, 2014 that is depreciated on a units of production basis was approximately $470 million.

~~Recently Issued Accounting Standards~~

~~On May 28, 2014, the Financial Accounting Standards Board issued ASC 606,~~ ~~Revenue from Contracts with Customers~~. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The registrants are currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.


(B)	CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has ~~increased generally~~occurred throughout the U.S. ~~In particular, personal injury, property damage, and other~~This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, ~~coal combustion residuals,~~CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such ~~matters, have become more frequent.~~matters.

The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.

Environmental Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions ~~seek~~sought penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) ~~has been actively litigated~~was partially settled in 2006 through a consent decree with the EPA, and additional claims remain pending in the U.S. District Court for the Northern District of ~~Alabama, resulting in~~Alabama. On June 25, 2015, the U.S. Department of Justice filed a ~~settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for~~joint stipulation between Alabama Power, onthe EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims ~~and dismissal of~~for relief alleged in the case ~~with prejudice in 2011. In September 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of~~

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

~~(UNAUDITED)~~

against Alabama ~~Power, and the case has been transferred back to~~Power. If approved by the U.S. District Court for the Northern District of Alabama, ~~for further proceedings.~~Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

Southern Company and each traditional operating company believe each such traditional operating company complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of ~~$25,000~~ to ~~$37,500~~ per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.

~~Environmental Remediation~~Performance Evaluation Plan

~~The Southern Company system must comply with environmental laws and regulations that cover~~On March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the ~~handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations,~~Mississippi PSC suspended the ~~Southern Company system could incur substantial costs~~filing to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of September 30, 2014 was $19 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claimsallow it more time for ~~recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.~~

Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to ~~$37,500~~ ~~per day for the violation and punitive damages of up to~~ ~~three~~ ~~times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.~~

In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In February 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion ruling that Georgia Power has no liability in the private action. In May 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.

review. The ultimate outcome of ~~these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and~~this matter cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $49.5 million as of September 30, 2014. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subjecttime.

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MISSISSIPPI POWER COMPANY

~~NOTES TO THE CONDENSED~~ MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL ~~STATEMENTS: (Continued)~~

~~(UNAUDITED)~~CONDITION AND RESULTS OF OPERATIONS

to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, there was no impact on net income as a result of these liabilities.Ad Valorem Tax Adjustment

~~In 2003,~~On April 23, 2015, Mississippi Power ~~and numerous other entities were designated by~~filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates. On May 26, 2015, the ~~Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled~~ Mississippi ~~Power's transformers.~~PSC suspended the filing to allow it more time to review. The TCEQ approved the final site remediation plan in December 2013 and, on March 28, 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability is $0.6 million as of September 30, 2014 and is expected to be recovered through the ECO Plan.

~~The final~~ultimate outcome of ~~these matters~~this matter cannot be determined at this time. ~~However, based on the currently known conditions at these sites and the nature and extent~~

Integrated Coal Gasification Combined Cycle

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of ~~activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and~~ Mississippi Power ~~does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements~~.

~~Nuclear Fuel Disposal Cost Litigation~~

~~Acting through the DOE~~in Item 7 and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

~~As a result of the first lawsuit, Georgia Power recovered approximately~~ ~~$27 million, based on its ownership interests, and Alabama Power recovered approximately~~ ~~$17 million~~, representing the vast majority of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In 2012, Alabama Power credited the award to cost of service for the benefit of customers. Also in 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers.

In 2008 and again on March 4, 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2005 through December 31, 2010 and from January 1, 2011 through December 31, 2013, respectively. Damages will continue to accumulate until the issue is resolved or storage is provided. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

~~On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.~~

~~FERC Matters~~

~~See~~ Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding the authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

Kemper IGCC Schedule and Cost Estimate

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the costs subject to the cost cap and the Cost Cap Exceptions remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court decision), and actual costs incurred as of June 30, 2015, as adjusted for the Court's decision, are as follows:

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Cost Category	2010 Project Estimate^(f)		Current Estimate		Actual Costs at June 30, 2015
	(in billions)
Plant Subject to Cost Cap^(a)	$	2.40	$	4.96	$	4.51
Lignite Mine and Equipment	0.21		0.23		0.23
CO₂ Pipeline Facilities	0.14		0.11		0.11
AFUDC^(b)(c)	0.17		0.62		0.52
Combined Cycle and Related Assets Placed in Service – Incremental^(d)	—		0.02		—
General Exceptions	0.05		0.10		0.08
Deferred Costs^(c)(e)	—		0.19		0.15
Total Kemper IGCC^(a)(c)	$	2.97	$	6.23	$	5.60

(a)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.

(b)


(c)	Amounts in the Current Estimate reflect estimated costs through March 31, 2016.


(d)	Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.


(e)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."


(f)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.08 billion), $2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, $16 million in other deferred charges and assets, and $24 million in AROs in the balance sheet, with $1 million previously expensed.

Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23 million ($14 million after tax) in the second quarter 2015 and $9 million ($6 million after tax) in the first quarter 2015. These amounts are in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. The increases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to equipment rework, scope modifications, and the related additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion

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MISSISSIPPI POWER COMPANY

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 construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 2015 Rate Case and any alternative proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

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estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC through the in-service date until directed to do otherwise by the Mississippi PSC.

In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.

2015 Rate Case

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May 15, 2015, Mississippi Power filed the 2015 Rate Case with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.

On July 10, 2015, Mississippi Power filed a Supplemental Notice with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal, In-Service Asset Proposal, for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.

The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

If the Mississippi PSC does not act on the Supplemental Notice or the 2015 Rate Case within 120 days of the Supplemental Notice filing, Mississippi Power expects to put one of the three viable alternative rate proposals into effect as temporary rates under bond and subject to refund pursuant to Mississippi state law.

Mississippi Power also expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 2015 of $6.23 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for

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interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.

Regulatory Assets and Liabilities

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of June 30, 2015, the regulatory asset balance associated with the Kemper IGCC was $198 million. The projected balance at March 31, 2016 is estimated to total approximately $276 million. The amortization period for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

See "2015 Mississippi Supreme Court Decision" herein for additional information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.

See Note 1 to the financial statements of Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.

Lignite Mine and CO₂ Pipeline Facilities

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO₂delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact

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on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

The ultimate outcome of these matters cannot be determined at this time.

Termination of Proposed Sale of Undivided Interest to SMEPA

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery

During 2015, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.

As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of $2.08 billion ($1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2015.

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

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Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for ~~information regarding Mississippi Power's construction~~additional information.

Asset Retirement Obligations

AROs are computed as the fair value of the ~~Kemper IGCC.~~ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.

On ~~March 31, 2014,~~April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Mississippi Power ~~reached a settlement agreement with its wholesale customers~~recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and ~~filed a request~~post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the ~~FERC~~CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Mississippi Power considers the liabilities for ~~an increase~~AROs to be critical accounting estimates.

Recently Issued Accounting Standards

The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Mississippi Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the ~~Municipal~~balance sheet as a direct deduction from the carrying amount of that debt liability and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, approved by the FERC on May 20, 2014, provides that base rates under the MRA cost-based electric tariff will increase approximately $10.1 million annually, with revised ratesis effective for ~~services rendered~~fiscal years beginning ~~May 1, 2014.~~after December 15, 2015. Mississippi Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its

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~~NOTES TO THE CONDENSED~~ MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL ~~STATEMENTS: (Continued)~~

~~(UNAUDITED)~~CONDITION AND RESULTS OF OPERATIONS

~~Retail Regulatory Matters~~balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.

~~Alabama~~FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Mississippi Power's financial condition was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections, which as of June 30, 2015 was approximately $353 million including associated carrying costs, and the termination of the Mirror CWIP rate will further adversely impact Mississippi Power's financial condition and its ability to obtain financing needed for normal business operations and completion of the Kemper IGCC. Earnings for the six months ended June 30, 2015 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. Earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

In addition to funding normal business operations and projected capital expenditures, Mississippi Power's cash requirements primarily consist of $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs. In addition, Mississippi Power issued an 18-month promissory note to Southern Company in the aggregate principal amount of approximately $301 million related to the refund to SMEPA and expects to enter into a similar promissory note with Southern Company to fund the Mirror CWIP refund. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA," "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order,"" – 2015 Mississippi Supreme Court Decision," and " – 2015 Rate Case" herein for additional information. For the three-year period from 2015 through 2017, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental equipment for existing generating units, including the Plant Daniel scrubber project, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. See "Sources of Capital" herein for additional information.

Through June 30, 2015, Mississippi Power has incurred non-recoverable cash expenditures of $1.62 billion and is expected to incur approximately $0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.

During the first six months of 2015, Mississippi Power received $75 million in equity contributions from Southern Company. In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. On June 3, 2015, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company as a result of Southern Company's refund of approximately $301 million in deposits and associated interest to SMEPA in connection with the termination of the APA. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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Net cash provided from operating activities totaled $309 million for the first six months of 2015, an increase of $131 million as compared to the corresponding period in 2014. The increase in cash provided from operating activities is primarily due to R&E tax deductions and bonus depreciation reducing tax payments, an increase in fuel recovery, and a decrease in receivables, partially offset by the timing of payments for accounts payable and fuel purchases. See Notes (B) and Note (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $460 million for the first six months of 2015 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $230 million for the first six months of 2015 primarily due to short-term bank loans, capital contributions from Southern Company, and short-term borrowings, partially offset by redemptions of long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2015 include a decrease in securities due within one year of $349 million, primarily due to refinancing or replacing maturing long-term debt with short-term loans. Additionally, long-term debt increased $301 million and interest-bearing refundable deposit decreased $275 million, due to an intercompany loan for repayment of the SMEPA deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased $439 million; other regulatory assets, deferred increased $97 million; and the Mirror CWIP regulatory liability increased $82 million primarily associated with construction, operation, and collections related to the Kemper IGCC. See – "Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current; accrued income taxes; accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and other deferred credits and liabilities increased primarily due to R&E tax deductions and the related reserve. Additional changes include increases in notes payable primarily due to new short-term bank loans and asset retirement obligations due to the CCR Rule. Total common stockholder's equity increased $164 million primarily due to the receipt of $75 million in capital contributions from Southern Company and due to net income during the second quarter 2015.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $900 million will be required through June 30, 2016 to fund maturities of bank term loans scheduled to mature on April 1, 2016 and $30 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs. See "Sources of Capital" herein for additional information.

The construction program of Mississippi Power is currently estimated to be $1.0 billion in 2015, $354 million in 2016, and $229 million for 2017, which includes expenditures related to the construction of the Kemper IGCC of $801 million in 2015 and $150 million in 2016.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (B) to the Condensed Financial Statements under "Integrated Coal

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Sources of Capital

Except as described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. Mississippi Power's financial condition was adversely affected by the issuance of an 18-month promissory note to Southern Company related to the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Mississippi Supreme Court Decision" of Mississippi Power in Item 7 of the Form 10-K and herein for additional information.

Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note 3 to the financial statements of ~~Southern Company and Alabama~~Mississippi Power under ~~"Retail Regulatory Matters~~ – ~~Alabama Power" and "Retail Regulatory Matters," respectively,~~"Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for ~~additional~~ information regarding ~~Alabama~~legislation related to the securitization of certain costs of the Kemper IGCC.

In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. As of June 30, 2015, Mississippi Power's ~~recovery~~current liabilities exceeded current assets by approximately $898 million primarily due to $900 million of ~~retail~~bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs through ~~various regulatory clauses~~June 30, 2015. Mississippi Power intends to utilize operating cash flows and ~~accounting orders. The recovery balance~~lines of ~~each regulatory clause~~credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.

At June 30, 2015, Mississippi Power had approximately $212 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2015 were as follows:

Regulatory Clause
Balance Sheet Line Item
September 30,
2014

December 31,
2013

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

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

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

27

Deferred over recovered regulatory clause revenues
—

15
Natural Disaster Reserve
Other regulatory liabilities, deferred
87

96

~~Georgia Power~~

~~Rate Plans~~



Expires								Executable Term Loans				Due Within One Year
2015		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)				(in millions)				(in millions)				(in millions)
$	40	$	255	$	295	$	265	$	30	$	40	$	70	$	225

See Note 36 to the financial statements of ~~Southern Company and Georgia~~Mississippi Power under ~~"Retail Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively,~~"Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements, as needed prior to expiration. In connection therewith, Mississippi Power may seek to extend the maturity dates and/or increase or decrease the lending commitments thereunder.

To the extent available, Mississippi Power may seek to utilize a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power would be loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 2015			Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Short-term bank debt	$	505	1.4%	$	460	1.4%	$	505


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At June 30, 2015, the maximum potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $282 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade has impacted and may continue to impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

On June 5, 2015, Fitch downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power.

Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Mississippi Power) on CreditWatch with negative implications.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In March 2015, Mississippi Power repaid at maturity a $75 million bank term loan.

In June 2015, Mississippi Power issued an 18-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposit in connection with the termination of the APA. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	250		$	260		$	481		$	538
Wholesale revenues, affiliates	85			68			199			140
Other revenues	2			1			4			2
Total operating revenues	337			329			684			680
Operating Expenses:
Fuel	105			118			243			243
Purchased power, non-affiliates	18			17			34			45
Purchased power, affiliates	4			16			14			46
Other operations and maintenance	69			69			121			122
Depreciation and amortization	60			52			118			103
Taxes other than income taxes	6			6			12			11
Total operating expenses	262			278			542			570
Operating Income	75			51			142			110
Other Income and (Expense):
Interest expense, net of amounts capitalized	(23		)	(22		)	(45		)	(44		)
Other income (expense), net	1			—			1			—
Total other income and (expense)	(22		)	(22		)	(44		)	(44		)
Earnings Before Income Taxes	53			29			98			66
Income taxes (benefit)	1			(3		)	13			—
Net Income	52			32			85			66
Less: Net income attributable to noncontrolling interests	6			1			6			2
Net Income Attributable to Southern Power Company	$	46		$	31		$	79		$	64

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income	$	52	$	32	$	85	$	66
Other comprehensive income (loss)	—		—		—		—
Less: Comprehensive income attributable to noncontrolling interests	6		1		6		2
Comprehensive Income Attributable to Southern Power Company	$	46	$	31	$	79	$	64

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	85		$	66
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	121			105
Deferred income taxes	59			(3		)
Investment tax credits	153			26
Amortization of investment tax credits	(10		)	(5		)
Deferred revenues	(21		)	(24		)
Accrued income taxes, non-current	100			—
Other, net	10			7
Changes in certain current assets and liabilities —
-Receivables	(26		)	(34		)
-Fossil fuel stock	5			(1		)
-Prepaid income taxes	(102		)	21
-Other current assets	—			(1		)
-Accounts payable	(31		)	24
-Accrued taxes	(110		)	7
-Other current liabilities	18			5
Net cash provided from operating activities	251			193
Investing Activities:
Plant acquisitions	(408		)	(213		)
Property additions	(154		)	(11		)
Change in construction payables	38			(3		)
Payments pursuant to long-term service agreements	(45		)	(23		)
Other investing activities	(1		)	(11		)
Net cash used for investing activities	(570		)	(261		)
Financing Activities:
Increase (decrease) in notes payable, net	(195		)	73
Proceeds — Senior notes	650			—
Distributions to noncontrolling interests	(1		)	—
Contributions from noncontrolling interests	78			7
Payment of common stock dividends	(65		)	(66		)
Other financing activities	(3		)	9
Net cash provided from financing activities	464			23
Net Change in Cash and Cash Equivalents	145			(45		)
Cash and Cash Equivalents at Beginning of Period	75			69
Cash and Cash Equivalents at End of Period	$	220		$	24
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $1 and $- capitalized for 2015 and 2014, respectively)	$	35		$	43
Income taxes, net	(72		)	(59		)
Noncash transactions — Accrued property additions at end of period	38			5

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



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

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2015 vs. SECOND QUARTER 2014

AND

YEAR-TO-DATE 2015 vs. YEAR-TO-DATE 2014

OVERVIEW

Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.

During the six months ended June 30, 2015, Southern Power acquired approximately 353 MWs of additional solar facilities including the five Georgia construction projects located in Taylor and Butler Counties, as well as the Lost Hills, Blackwell, and North Star projects located in California. Southern Power also entered into an agreement to acquire an approximately 299-MW wind facility, located in Oklahoma, contingent upon certain construction and project milestones. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

Southern Power continues to focus on several key performance indicators. These indicators include peak season equivalent forced outage rate, contract availability, and net income. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Net income attributable to Southern Power for the second quarter 2015 was $46 million compared to $31 million for the corresponding period in 2014. The increase was primarily due to increased revenue and lower fuel and purchased power expenses.

Net income attributable to Southern Power for year-to-date 2015 was $79 million compared to $64 million for the corresponding period in 2014. The increase was primarily due to a decrease in purchased power expenses, partially offset by increases in depreciation and income taxes.

Wholesale Revenues–Non-Affiliates

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale revenues from non-affiliates for the second quarter 2015 were $250 million compared to $260 million for the corresponding period in 2014. The decrease was due to a $5 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and new solar PPAs. The decrease in energy revenues reflects a 14% decrease in the average price of energy, partially offset by a 12% increase in KWH sales. In addition, capacity revenues decreased $5 million primarily due to PPA expirations.

Wholesale revenues from non-affiliates for year-to-date 2015 were $481 million compared to $538 million for the corresponding period in 2014. The decrease was due to a $44 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and new solar PPAs. The decrease in energy revenues reflects a 17% decrease in the average price of energy, partially offset by a 5% increase in KWH sales. In addition, capacity revenues decreased $13 million primarily due to PPA expirations.

Wholesale Revenues–Affiliates

Wholesale revenues from affiliates for the second quarter 2015 were $85 million compared to $68 million for the corresponding period in 2014. The increase was the result of a $10 million increase in energy revenues and a $7 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 61% increase in KWH sales, partially offset by a 21% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.

Wholesale revenues from affiliates for year-to-date 2015 were $199 million compared to $140 million for the corresponding period in 2014. The increase was the result of a $50 million increase in energy revenues and a $9 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 110% increase in KWH sales, partially offset by a 22% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.

Fuel and Purchased Power Expenses



	Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(13	)	(11.0)	$	—		—
Purchased power – non-affiliates	1			5.9	(11		)	(24.4	)
Purchased power – affiliates	(12		)	(75.0)	(32		)	(69.6	)
Total fuel and purchased power expenses	$	(24	)		$	(43	)

Southern Power's PPAs for natural gas-fired generation generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in such fuel cost is generally

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

accompanied by an increase or decrease in related fuel revenues under the PPAs and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.

In the second quarter 2015, total fuel and purchased power expenses were $127 million compared to $151 million for the corresponding period in 2014. The decrease was the result of a $58 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $34 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.

For year-to-date 2015, total fuel and purchased power expenses were $291 million compared to $334 million for the corresponding period in 2014. The decrease was a result of a $154 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $111 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.

Fuel

In the second quarter 2015, fuel expense was $105 million compared to $118 million for the corresponding period in 2014. The decrease was due to a 36.1% decrease associated with the average cost of natural gas per KWH generated, partially offset by a 40.6% increase associated with the volume of KWHs generated, primarily as a result of increased demand resulting from lower natural gas prices.

For year-to-date 2015 and for the corresponding period in 2014, fuel expense was $243 million. While there was no overall change, a $152 million increase in the total cost of fuel attributable to the volume of KWHs generated was offset by a $152 million decrease in the average cost of natural gas per KWH generated.

Purchased Power – Non-Affiliates and Affiliates

In the second quarter 2015, purchased power expense was $22 million compared to $33 million for the corresponding period in 2014. For year-to-date 2015, purchased power expense was $48 million compared to $91 million for the corresponding period in 2014. The decreases were primarily the result of 37.4% and 45.6% decreases in the volume of KWHs purchased in the second quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices which resulted in higher use of Southern Power Company's generation resources.

Other Operations and Maintenance Expenses

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

largely offset by a $16 million increase in expenses associated with support services, new plants placed in service in 2014 and 2015, and transmission.

Depreciation and Amortization

Income Taxes (Benefit)

N/M – Not meaningful

In the second quarter 2015, income taxes were $1 million compared to an income tax benefit of $3 million for the corresponding period in 2014. For year-to-date 2015, income taxes were $13 million. The increases were primarily due to higher pre-tax earnings in 2015 and beneficial state income tax changes in 2014, partially offset by increased federal income tax benefits related to ITCs in 2015.

See Note (G) to the Condensed Financial Statements herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy, including successfully expanding investments in renewable energy projects, and to construct generating facilities, including the impact of federal ITCs.

Environmental Matters

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Air Quality

On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, North Carolina, and Texas) to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSM by no later than November 22, 2016. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of CO₂ from fossil-fuel-fired electric generating units.

On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO₂ emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO₂ emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO₂ performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Power's ~~2013 ARP.~~results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through existing PPAs. However, the ultimate financial and operational impact of the final rules on Southern Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

Acquisitions

Kay County Wind Facility

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

Lost Hills-Blackwell Solar Facilities

On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years.

North Star Solar Facility

On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately 61-MW North Star solar facility in Fresno County, California. The solar facility began commercial operation on June 20, 2015, and the entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company.

Construction Projects

In December 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of five separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this time.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Power Company's construction projects are detailed in the table below:

Solar Project

Seller

Nameplate Capacity

County Location in Georgia

Expected Commercial Operation Date

PPA Counterparty
for Entire Plant Output

PPA Contract Period

Estimated Construction Cost

(MW)

(in millions)

Taylor County

N/A

146

Taylor

Fourth quarter 2016

Cobb, Flint, and Sawnee Electric Membership Corporations

25 years

260

$280

Decatur Parkway

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(a)

25 years

170

$173

(b)

Decatur County

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(a)

20 years

$47

(b)

Butler

CERSM, LLC and Community Energy, Inc.

103

Taylor

December 2016

Georgia Power^(a)

30 years

220

$230

(b)

Pawpaw

Longview Solar, LLC

Taylor

December 2015

Georgia Power^(a)

30 years

$80

(b)

Butler Solar Farm

Strata Solar Development, LLC

Taylor

December 2015

Georgia Power^(a)

20 years

$48

(b)

(a) Subject to FERC approval.

(b) Includes the acquisition price of all outstanding membership interests.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

Power Sales Agreements

See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.

Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern Power's existing fleet, the coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of June 30, 2015 from the period ended December 31, 2014.

FERC Matters

Southern Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the ~~terms of the 2013 ARP, on October 3, 2014, Georgia~~traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the ~~following tariff adjustments~~energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the ~~Georgia PSC to become effective January 1, 2015 pending its approval:~~

~~Increase the traditional base tariffs by approximately $107 million to cover additional capacity costs;~~

~~Increase the environmental compliance cost recovery tariff by approximately $32 million;~~

~~Increase the demand-side management tariffs by approximately $3 million; and~~

~~Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.~~

FERC. The ultimate outcome of this matter cannot be determined at this time.

~~Renewables Development~~

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~~See~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation against Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Southern ~~Company and Georgia~~ Power ~~under "Retail Regulatory Matters – Georgia Power – Renewables Development" and "Retail Regulatory Matters – Renewables Development," respectively,~~ in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for ~~additional information.~~a complete discussion of Southern Power's critical accounting policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.

Recently Issued Accounting Standards

On ~~May 20, 2014,~~February 18, 2015, the ~~Georgia PSC approved Georgia Power's application~~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 ~~certification~~primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of ~~two PPAs executed~~this ASU has not yet been determined.

On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in ~~April 2013~~the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Power currently reflects unamortized debt issuance costs in other deferred charges and assets – non-affiliated on its balance sheet. Upon adoption, the ~~purchase~~reclassification will not have a material impact on the results of ~~energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.~~

~~As a result~~operations, financial position, or cash flows of amendments executed during 2014, the biomass PPAs classified as non-affiliate capital leases with related long-term obligations totaling $641 million as of December 31, 2013 no longer meet the definition of a lease or will be accounted for as operating leases. Due to these amendments, as well as others executed during 2014, total non-affiliate operating lease long-term obligations increased by $103 million. As such, estimated long-term obligations for non-affiliate operating leases have been updated to $113 million for 2015, $117 million for 2016, $145 million for 2017, $150 million for 2018, and $1.7 billion for 2019 and thereafter. Estimated long-termSouthern Power.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at June 30, 2015. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.

Net cash provided from operating activities totaled $251 million for the first six months of 2015, compared to $193 million for the first six months of 2014. The increase in cash provided from operating activities was primarily due to lower purchased power costs and an increase in income tax benefits received. Net cash used for investing activities totaled $570 million for the first six months of 2015 primarily due to the Lost Hills, Blackwell, and North Star acquisitions and expenditures related to the construction of new solar facilities. Net cash provided from financing activities totaled $464 million for the first six months of 2015 primarily due to the issuance of additional senior notes in May 2015. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2015 include a $300 million increase in plant in service, net of depreciation primarily due to the Lost Hills, Blackwell, and North Star acquisitions and a $190 million increase in CWIP primarily due to the construction of new solar facilities. Other significant changes include an increase in long-term debt of $642 million primarily as a result of the issuance of senior notes in May 2015.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. Subsequent to June 30, 2015, $525 million of long-term debt was repaid at maturity. There are no other scheduled maturities of long-term debt through June 30, 2016.

The capital program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to be approximately $1.4 billion for 2015, which includes approximately $1.3 billion for acquisitions and/or construction of new generating facilities. See Note (I) to the Condensed Financial Statements herein for additional information. Actual capital costs may vary from these estimates because of changes in factors such as business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

Sources of Capital

Southern Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, securities issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

To meet liquidity and capital resource requirements, Southern Power had at June 30, 2015 cash and cash equivalents of approximately $220 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $466 million is unused.

The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power Company is currently in compliance with all covenants in the Facility.

Southern Power Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Subsequent to June 30, 2015, commercial paper was used to partially fund the maturity of long-term debt in July 2015.

Details of short-term borrowings were as follows:



	Commercial Paper at the End of the Period				Commercial Paper During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
June 30, 2015:	$	—	—	%	$	163	0.6	%	$	339

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.

Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and operating cash flows.

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

The maximum potential collateral requirements under these contracts at June 30, 2015 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	320
Below BBB- and/or Baa3	1,081

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Power's ability to access capital markets, particularly the short-term debt market.

In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.

Financing Activities

In May 2015, Southern Power Company issued $350 million aggregate principal amount of Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS



Note		Page Number
A	Introduction	150
B	Contingencies and Regulatory Matters	152
C	Fair Value Measurements	168
D	Stockholders' Equity	173
E	Financing	175
F	Retirement Benefits	177
G	Income Taxes	180
H	Derivatives	181
I	Acquisitions	190
J	Segment and Related Information	193

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.



Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I, J
Alabama Power	A, B, C, E, F, G, H
Georgia Power	A, B, C, E, F, G, H
Gulf Power	A, B, C, E, F, G, H
Mississippi Power	A, B, C, E, F, G, H
Southern Power	A, B, C, D, E, G, H, I

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

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

(UNAUDITED)


(A)	INTRODUCTION

~~obligations did not change for 2014.~~ The ~~counterparties of the aforementioned PPAs have posted collateral as required. See Note 7 to the~~condensed quarterly financial statements of ~~Georgia Power under "Commitments – Fuel~~each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and ~~Purchased Power Agreements"~~regulations of the SEC. The Condensed Balance Sheets as of December 31, 2014 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2015 and 2014. Certain information and footnote disclosures normally included in ~~Item 8~~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 ~~for additional information.~~

~~Integrated Resource Plan~~

~~See Note 3 to~~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 ~~of Southern Company~~ and ~~Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" and "Retail Regulatory Matters – Integrated Resource Plans," respectively,~~the notes thereto included in ~~Item 8~~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 ~~Form 10-K~~operating results to be expected for ~~additional information.~~the full year.

~~Georgia~~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 ~~filed a request with the Georgia PSC on January 10, 2014~~announced plans to ~~cancel the proposed biomass fuel conversion of~~retire its coal-fired generation at Plant ~~Mitchell Unit 3 (155~~Smith Units 1 and 2 (357 MWs) because it would not be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3by March 31, 2016. In March 2015, in connection with this retirement, Gulf Power reclassified the ~~triennial Integrated Resource Plan~~net carrying value of these units from plant in ~~2016.~~service, net of depreciation, to other utility plant, net. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.

In June 2015, Georgia Power ~~plans~~identified an error affecting the billing to ~~continue~~a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to ~~operate~~June 30, 2015. In the ~~unit as needed until the Mercury and Air Toxics Standards rule becomes effective in April 2015.~~

~~Fuel Cost Recovery~~

~~See Note 3 to the financial statements of Southern Company and~~second quarter 2015, Georgia Power ~~under "Retail Regulatory Matters –~~recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power ~~– Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8~~evaluated the effects of ~~the Form 10-K for additional information.~~

As of September 30, 2014, Georgia Power's under recovered fuel balance totaled $175 million and is included in deferred charges and other assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. As of December 31, 2013, Georgia Power's over recovered fuel balance totaled $58 million and is included in current liabilities and other deferred credits and liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein. Georgia Power's next fuel case is expected to be filed with the Georgia PSC by February 27, 2015.

~~Fuel cost recovery revenues as recorded~~this error on the ~~financial statements are adjusted for differences in actual recoverable fuel costs~~interim and ~~amounts billed in current regulated rates. Accordingly, changes in~~annual periods that included the billing ~~factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.~~

~~Storm Damage Recovery~~

~~See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.~~

~~Nuclear Construction~~

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, and pending litigation.

Recently Issued Accounting Standards

The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for ~~change orders, and performance bonuses~~revenue recognition effective for ~~early~~fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~completion and unit performance. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed~~On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the ~~Contractor under~~Consolidation Analysis, which makes certain changes to both the ~~Vogtle 3~~variable interest model and ~~4 Agreement. Georgia Power's proportionate share~~the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.

On April 7, 2015, the FASB issued ASU No. 2015-03, ~~45.7%~~Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ~~Vogtle 3~~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 ~~4 Agreement provides~~is effective for ~~liquidated damages upon~~fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the ~~Contractor's failure to fulfill~~reclassification will not have a material impact on the ~~schedule and performance guarantees. The Contractor's liability~~results of operations, financial position, or cash flows of any registrant.

Asset Retirement Obligations

See Note 1 to the ~~Vogtle Owners~~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 ~~schedule~~additional information regarding the EPA's regulation of CCR.

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and ~~performance liquidated damages and warranty claims is~~Mississippi Power recorded new asset retirement obligations (ARO) for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a ~~cap.~~

~~Certain payment obligations~~result of ~~Westinghouse and Stone & Webster, Inc. under~~state requirements in Georgia which closely align with the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breachesrequirements of the ~~Vogtle 3~~CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and ~~4 Agreement~~post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates.

As of June 30, 2015, details of the AROs, including those related to the CCR Rule, included in Southern Company's and the traditional operating companies' Condensed Balance Sheets herein were as follows:



	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Balance at beginning of year	$	2,201		$	829		$	1,255		$	17	$	48
Liabilities incurred	612			401			—			71		97
Liabilities settled	(10		)	(1		)	(9		)	—		—
Accretion	53			23			28			—		1
Cash flow revisions	58			—			82			4		2
Balance at end of period	$	2,914		$	1,252		$	1,356		$	92	$	148

The increases in liabilities incurred and cash flow revisions for the six months ended June 30, 2015 primarily relate to an increase in AROs associated with facilities impacted by the ~~Vogtle Owners, Vogtle Owner insolvency, and certain other events.~~CCR Rule.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challengesconnection with a proposed settlement related to the ~~construction and licensing~~closure of Plant ~~Vogtle Units 3 and 4, at the federal and state level, and~~Scholz, Gulf Power may incur additional ~~challenges are expected as construction proceeds.~~

In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariffAROs associated with CCR of approximately ~~$223~~$15 million, ~~$35 million~~, ~~$50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On October 31, 2014, Georgia Power filed~~ to increase the NCCR tariff by approximately $27 million effective January 1, 2015 pending Georgia PSC approval. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately ~~$91 million~~ ~~of financing costs, capitalized in 2009 and 2010, over the~~ ~~five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2014, approximately $23 million of these 2009 and 2010 costs remained unamortized in CWIP.~~

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


(B)	CONTINGENCIES AND REGULATORY MATTERS

~~with~~See Note 3 to the ~~eleventh VCM report filed on August 28, 2014, which requests approval~~financial statements of ~~an additional $0.2 billion~~the registrants in ~~costs incurred from January 1, 2014 through June 30, 2014.~~Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In ~~2012, the Vogtle Owners~~addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the ~~Contractor began negotiations regarding~~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 ~~costs associated~~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 ~~design changes~~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 ~~DCD and the delays~~financial statements of each registrant in ~~the timing of approval~~Item 8 of the ~~DCD~~Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.

Environmental Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and ~~issuance~~Georgia Power alleging violations of the ~~COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms~~New Source Review (NSR) provisions of the ~~Vogtle 3~~Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and ~~4 Agreement. Also in 2012,~~Mississippi Power. These civil actions sought penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power ~~and the other Vogtle Owners filed suit against the Contractor~~(including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the ~~Southern~~Northern District of Georgia ~~seeking~~since 2001. The case against Alabama Power (including claims involving a ~~declaratory judgment that~~unit co-owned by Mississippi Power) was partially settled in 2006 through a consent decree with the ~~Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power~~EPA, and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. The portion of additional ~~costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately~~ ~~$425 million~~ ~~(in 2008 dollars). The Contractor also asserted it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the suit~~claims remain pending in the U.S. District Court for the ~~Southern~~Northern District of ~~Georgia alleging that (i)~~Alabama. On June 25, 2015, the ~~design changes~~U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the ~~DCD imposed~~2006 consent decree to resolve all remaining claims for relief alleged in the case against Alabama Power. If approved by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations, but the Contractor subsequently asserted, and may from time to time continue to assert, that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power does not agree with either the proposed cost or schedule adjustments or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in the fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessaryU.S. District Court for the ~~operation~~Northern District of ~~Plant Vogtle Units 3~~Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and ~~4, or other issues could arise~~a cap on certain units and ~~may further impact project schedule~~requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and ~~cost. While Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule~~Barry; pay a $100,000 civil penalty; and ~~believes the Contractor is responsible for any related costs, Contractor performance and progress~~invest $1.5 million in ~~recent months on the assembly and installation of the shield building and structural modules have resulted in additional schedule pressure.~~

The ultimate outcome of these matters cannot be determined at this time.

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~~Gulf Power~~

~~Retail Base Rate Case~~

~~See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.~~

In December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $5.4 million reduction in depreciation expense in the first nine months of 2014.

~~Cost Recovery Clauses~~

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The recovery balance of each regulatory clause follows:

Recovery Clause
Balance Sheet Location
September 30, 2014
December 31, 2013

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

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

—
Purchased Power Capacity Recovery – Under
Under recovered regulatory clause revenues
—

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

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

7.0

On October 22, 2014, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2015. The net effect of the approved changes is a $41.2 million increase in annual revenue for 2015. The increased revenues will not have a significant impact on net income since most of the revenues will be offset by expenses.

~~Retail Fuel Cost Recovery~~

See Note 1 and Note 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

Gulf Power has established fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first half of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested for 2014. Under recovered fuel costs at September 30, 2014 totaled $41.3 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.

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~~Mississippi Power~~

~~Energy Efficiency~~

~~See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information.~~

On June 3, 2014, the Mississippi PSC approved Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. On October 17, 2014, Mississippi Power filed a revised compliance filing, which proposed an increase of $6.7 million in retail revenues for the period December 2014 through December 2015. The Mississippi PSC approved the revised filing on November 4, 2014.

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

The ultimate outcome of ~~these matters~~this matter cannot be determined at this time.

~~System Restoration Rider~~

~~See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – System Restoration Rider" in Item 8 of the Form 10-K for additional information.~~

~~On April 1, 2014, the Mississippi PSC approved Mississippi Power's request to continue a zero System Restoration Rider rate for 2014 and to accrue approximately~~ ~~$3.3 million~~ ~~to the property damage reserve in 2014.~~

~~Environmental Compliance Overview Plan~~

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC.

In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with ~~50%~~ ~~ownership each. The estimated total cost of the project is approximately~~ ~~$660 million, with Mississippi Power's portion being~~ ~~$330 million~~, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project in December 2015. As of September 30, 2014, total project expenditures were $464.1 million, of which Mississippi Power's portion was $236.3 million, plus AFUDC of $16.1 million.

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~~(UNAUDITED)~~CONDITION AND RESULTS OF OPERATIONS

~~CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On August 28, 2014, the Chancery Court dismissed the appeal.~~

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. As of September 30, 2014, $5.5 million of Plant Greene County CWIP had been reclassified as a regulatory asset. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Greene County and Watson. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Southern Company's and Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Fuel Cost Recovery~~

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Mississippi Power's fuel cost recovery.

~~At September 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $13.1 million compared to over recovered retail fuel costs of~~ ~~$14.5 million~~ ~~at December 31, 2013.~~

Ad Valorem Tax Adjustment

~~See Note 3 to the financial statements of~~On April 23, 2015, Mississippi Power ~~under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information.~~

Integrated Coal Gasification Combined Cycle

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of ~~Southern Company and~~ Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC ~~Project Approval~~Overview

Kemper IGCC Schedule and Cost Estimate

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN, which the Mississippi Supreme Court granted on September 11, 2014. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

~~Kemper IGCC Schedule and Cost Estimate~~IGCC.

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was ~~$2.4~~$2.4 billion,, net of ~~$245.3~~$245 million of ~~grants awarded to the Kemper IGCC project by the~~ DOE ~~under the Clean Coal Power Initiative Round 2 (DOE Grants)~~Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline

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~~(UNAUDITED)~~

facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to ~~$2.88~~$2.88 billion,, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. ~~Exceptions to the~~ ~~$2.88 billion~~ ~~cost cap include the cost of the lignite mine and equipment, the cost of the CO~~₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions), as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

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

~~The ultimate outcome of this matter cannot be determined at this time.~~

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~~(UNAUDITED)~~

Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court decision), and actual costs incurred as of ~~September~~June 30, ~~2014~~2015, as adjusted for the ~~Kemper IGCC~~Court's decision, are as follows:

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Cost Category	2010 Project Estimate^(f)		Current Estimate		Actual Costs at September 30, 2014		2010 Project Estimate^(f)		Current Estimate		Actual Costs at June 30, 2015
	(in billions)						(in billions)
Plant Subject to Cost Cap^(a)	$	2.40	$	4.86	$	4.06	$	2.40	$	4.96	$	4.51
Lignite Mine and Equipment	0.21		0.23		0.23		0.21		0.23		0.23
CO₂ Pipeline Facilities	0.14		0.11		0.10		0.14		0.11		0.11
AFUDC^(b)(c)	0.17		0.62		0.41		0.17		0.62		0.52
Combined Cycle and Related Assets Placed in Service – Incremental^(d)	—		—		—		—		0.02		—
General Exceptions	0.05		0.10		0.07		0.05		0.10		0.08
Regulatory Asset^(c)(e)	—		0.18		0.10
Deferred Costs^(c)(e)							—		0.19		0.15
Total Kemper IGCC^(a)(c)	$	2.97	$	6.10	$	4.97	$	2.97	$	6.23	$	5.60

(a)

(b)


(c)	Amounts in the Current Estimate reflect estimated costs through March 31, 2016.


(d)	Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service onin August 9, 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.


(e)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."


(f)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of ~~September~~June 30, ~~2014, $2.88~~2015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of ~~$1.98~~$2.08 billion), ~~$104.3~~$2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, ~~and $3.9~~$16 million in other deferred charges and assets, and $24 million in ~~Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and $1.1~~AROs in the balance sheet, with $1 million ~~was~~ previously expensed.

Mississippi Power does not intend to seek any rate recovery ~~or joint owner contributions~~ for any costs related ~~costs~~to the construction of the Kemper IGCC that exceed the ~~$2.88~~$2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. ~~Southern Company and~~ Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of ~~$418.0~~$23 million ($~~258.1~~14 million after tax) in the ~~third~~second quarter ~~2014~~2015 and ~~$380.0~~$9 million ($~~234.7~~6 million after tax) in the first quarter ~~2014.~~2015. These amounts are in addition to charges totaling ~~$1.18 billion~~$868 million ($~~728.7~~536 million after tax) ~~recognized through December 31, 2013.~~, $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. The ~~first quarter 2014 revised~~increases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to decreases in construction labor productivity at the Kemper IGCC due in large part to adverse weather, unexpected excessive craft labor turn-over, and unanticipated installation inefficiencies, as well as additional risk related to the expected in-service date. The third quarter 2014 revised cost estimate primarily reflects costs related to the extension of the project schedule for the remainder of the Kemper IGCC (including the gasifierequipment rework, scope modifications, and the ~~gas clean-up facilities) as a result~~related additional labor costs in support of ~~matters related to the time expected to be required for~~ start-up ~~activities~~ and operational readiness ~~including enhancing the scope of specialized operator training.~~activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately ~~$20~~$25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion

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~~(UNAUDITED)~~

inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational ~~performance, operational~~ readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or ~~operations.~~operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the ~~$2.88~~$2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in ~~Southern Company's statements of income and~~ Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on ~~Southern Company's and~~ Mississippi Power's results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, ~~establishes~~established the process for resolving matters regarding cost recovery related to the Kemper IGCC ~~and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order~~ (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the ~~$2.4~~$2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the ~~$2.88~~$2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also ~~allows~~allowed Mississippi Power to secure alternate financing for costs ~~that are~~ not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

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estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the ~~Seven-Year~~proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate ~~Plan (described below)~~Mitigation Plan) as approved by the Mississippi PSC. The ~~rate recovery necessary~~Court's decision did not impact Mississippi Power's ability to recover the annual costs of securitization is expected to be filed and become effective following completion of the Mississippi PSC's prudence review of the costs to be securitized. With the extension of the Kemper IGCC in-service date, under certain potential scenarios, the amount eligible to be securitized may exceed $1.0 billion. In that event, Mississippi Power would expect to pursue rate recovery of any additional eligible costs.

~~The 2013 Settlement Agreement provides that Mississippi Power may terminate the 2013 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure~~utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 2013 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the 2013 Settlement

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~~(UNAUDITED)~~

~~Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS) to implement the requirements of the 2013 Settlement Agreement.~~additional information.

2013 MPSC Rate Order

In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively ~~are~~were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order). For the first nine months of 2014, $121.9 million has been collected, with $16.8 million recognized in retail revenues in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein. Since March 2013, $220.0 million has been collected, with $27.1 million recognized in retail revenues in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein.

service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the ~~$2.88~~$2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC ~~and to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates~~ through the in-service date ~~unless~~until directed to do otherwise by the Mississippi PSC.

In ~~March 2013, a legal challenge to the 2013 MPSC Rate Order was filed by Thomas A. Blanton with the Mississippi Supreme Court, which remains pending against~~August 2014, Mississippi Power ~~and~~provided an analysis of the Mississippi PSC. On April 22, 2014, the Mississippi Supreme Court requested further briefing in this proceeding on a number of substantive issues relating to the 2013 MPSC Rate Order. An adverse outcome could affect the rates that went into effect on March 19, 2013 and January 1, 2014 and the related amounts deferred as a regulatory liability.

~~See "Regulatory Assets and Liabilities" herein for additional information.~~

~~Seven-Year Rate Plan~~

In March 2013, Mississippi Power, in compliance with the 2013 MPSC Rate Order, filed a revision to the proposed rate recovery plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (Seven-Year Rate Plan), which is still under review by the Mississippi PSC. In the Seven-Year Rate Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately ~~$156 million~~ ~~of Kemper IGCC-related operational~~ costs and ~~rate base amounts, including plant costs equal to the~~ ~~$2.4 billion~~ ~~certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization~~benefits of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC will review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" herein for additional information.

~~The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a~~ ~~15%~~ ~~undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of~~

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~~(UNAUDITED)~~

~~2012 (ATRA), which currently requires that assets be placed in service in 2014. While Mississippi Power placed~~placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, onincluding the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.

In addition, Mississippi Power's August 9, 2014 ~~extension~~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 ~~for~~of the remainder of the Kemper ~~IGCC beyond 2014~~IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Mississippi Power.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the ~~loss~~legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of ~~tax benefits~~Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to ~~bonus depreciation~~the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under ~~current law. The estimated value~~the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to ~~retail customers~~the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.

2015 Rate Case

As a result of the ~~bonus depreciation tax benefits not~~2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC ~~is approximately $130 million~~related to ~~$160 million.~~

~~Mississippi Power plans to further revise~~ the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to investment tax credits, various other revenue requirement items, and other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated15% undivided interest that was previously projected to be ~~an increase~~purchased by SMEPA. See "Termination of ~~approximately $60 million~~Proposed Sale of Undivided Interest to $70 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power, including Section 174 Research and Experimental (R&E) tax deductions, that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan. See "Income Tax Matters"SMEPA" herein for additional information.

Mississippi Power ~~would~~also expects to seek additional rate relief to address recovery ~~through alternate means, which could include a traditional rate case.~~

Prudence Reviews

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.

Regulatory Assets and Liabilities

~~160~~

~~Table of Contents~~

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

~~(UNAUDITED)~~

Lignite Mine and CO₂ Pipeline Facilities

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

The ultimate outcome of these matters cannot be determined at this time.

Termination of Proposed Sale of Undivided Interest to SMEPA

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Asset Retirement Obligations

Recently Issued Accounting Standards

The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Mississippi Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Mississippi Power's financial condition was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections, which as of June 30, 2015 was approximately $353 million including associated carrying costs, and the termination of the Mirror CWIP rate will further adversely impact Mississippi Power's financial condition and its ability to obtain financing needed for normal business operations and completion of the Kemper IGCC. Earnings for the six months ended June 30, 2015 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. Earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $900 million will be required through June 30, 2016 to fund maturities of bank term loans scheduled to mature on April 1, 2016 and $30 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs. See "Sources of Capital" herein for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (B) to the Condensed Financial Statements under "Integrated Coal

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sources of Capital

Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. As of June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $898 million primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs through June 30, 2015. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.

At June 30, 2015, Mississippi Power had approximately $212 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2015 were as follows:



Expires								Executable Term Loans				Due Within One Year
2015		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)				(in millions)				(in millions)				(in millions)
$	40	$	255	$	295	$	265	$	30	$	40	$	70	$	225

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

To the extent available, Mississippi Power may seek to utilize a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power would be loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 2015			Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Short-term bank debt	$	505	1.4%	$	460	1.4%	$	505


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At June 30, 2015, the maximum potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $282 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade has impacted and may continue to impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

On June 5, 2015, Fitch downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power.

Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Mississippi Power) on CreditWatch with negative implications.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In March 2015, Mississippi Power repaid at maturity a $75 million bank term loan.

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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	250		$	260		$	481		$	538
Wholesale revenues, affiliates	85			68			199			140
Other revenues	2			1			4			2
Total operating revenues	337			329			684			680
Operating Expenses:
Fuel	105			118			243			243
Purchased power, non-affiliates	18			17			34			45
Purchased power, affiliates	4			16			14			46
Other operations and maintenance	69			69			121			122
Depreciation and amortization	60			52			118			103
Taxes other than income taxes	6			6			12			11
Total operating expenses	262			278			542			570
Operating Income	75			51			142			110
Other Income and (Expense):
Interest expense, net of amounts capitalized	(23		)	(22		)	(45		)	(44		)
Other income (expense), net	1			—			1			—
Total other income and (expense)	(22		)	(22		)	(44		)	(44		)
Earnings Before Income Taxes	53			29			98			66
Income taxes (benefit)	1			(3		)	13			—
Net Income	52			32			85			66
Less: Net income attributable to noncontrolling interests	6			1			6			2
Net Income Attributable to Southern Power Company	$	46		$	31		$	79		$	64

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income	$	52	$	32	$	85	$	66
Other comprehensive income (loss)	—		—		—		—
Less: Comprehensive income attributable to noncontrolling interests	6		1		6		2
Comprehensive Income Attributable to Southern Power Company	$	46	$	31	$	79	$	64

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	85		$	66
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	121			105
Deferred income taxes	59			(3		)
Investment tax credits	153			26
Amortization of investment tax credits	(10		)	(5		)
Deferred revenues	(21		)	(24		)
Accrued income taxes, non-current	100			—
Other, net	10			7
Changes in certain current assets and liabilities —
-Receivables	(26		)	(34		)
-Fossil fuel stock	5			(1		)
-Prepaid income taxes	(102		)	21
-Other current assets	—			(1		)
-Accounts payable	(31		)	24
-Accrued taxes	(110		)	7
-Other current liabilities	18			5
Net cash provided from operating activities	251			193
Investing Activities:
Plant acquisitions	(408		)	(213		)
Property additions	(154		)	(11		)
Change in construction payables	38			(3		)
Payments pursuant to long-term service agreements	(45		)	(23		)
Other investing activities	(1		)	(11		)
Net cash used for investing activities	(570		)	(261		)
Financing Activities:
Increase (decrease) in notes payable, net	(195		)	73
Proceeds — Senior notes	650			—
Distributions to noncontrolling interests	(1		)	—
Contributions from noncontrolling interests	78			7
Payment of common stock dividends	(65		)	(66		)
Other financing activities	(3		)	9
Net cash provided from financing activities	464			23
Net Change in Cash and Cash Equivalents	145			(45		)
Cash and Cash Equivalents at Beginning of Period	75			69
Cash and Cash Equivalents at End of Period	$	220		$	24
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $1 and $- capitalized for 2015 and 2014, respectively)	$	35		$	43
Income taxes, net	(72		)	(59		)
Noncash transactions — Accrued property additions at end of period	38			5

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



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

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



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

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2015 vs. SECOND QUARTER 2014

AND

YEAR-TO-DATE 2015 vs. YEAR-TO-DATE 2014

OVERVIEW

Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.

RESULTS OF OPERATIONS

Net Income

Wholesale Revenues–Non-Affiliates

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues–Affiliates

Wholesale revenues from affiliates for year-to-date 2015 were $199 million compared to $140 million for the corresponding period in 2014. The increase was the result of a $50 million increase in energy revenues and a $9 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 110% increase in KWH sales, partially offset by a 22% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.

Fuel and Purchased Power Expenses



	Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(13	)	(11.0)	$	—		—
Purchased power – non-affiliates	1			5.9	(11		)	(24.4	)
Purchased power – affiliates	(12		)	(75.0)	(32		)	(69.6	)
Total fuel and purchased power expenses	$	(24	)		$	(43	)

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel

Purchased Power – Non-Affiliates and Affiliates

Other Operations and Maintenance Expenses

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

largely offset by a $16 million increase in expenses associated with support services, new plants placed in service in 2014 and 2015, and transmission.

Depreciation and Amortization

Income Taxes (Benefit)

N/M – Not meaningful

See Note (G) to the Condensed Financial Statements herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy, including successfully expanding investments in renewable energy projects, and to construct generating facilities, including the impact of federal ITCs.

Environmental Matters

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Air Quality

Global Climate Issues

On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO₂ emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO₂ emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO₂ performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through existing PPAs. However, the ultimate financial and operational impact of the final rules on Southern Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

Acquisitions

Kay County Wind Facility

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Lost Hills-Blackwell Solar Facilities

North Star Solar Facility

Construction Projects

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Power Company's construction projects are detailed in the table below:

Solar Project

Seller

Nameplate Capacity

County Location in Georgia

Expected Commercial Operation Date

PPA Counterparty
for Entire Plant Output

PPA Contract Period

Estimated Construction Cost

(MW)

(in millions)

Taylor County

N/A

146

Taylor

Fourth quarter 2016

Cobb, Flint, and Sawnee Electric Membership Corporations

25 years

260

$280

Decatur Parkway

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(a)

25 years

170

$173

(b)

Decatur County

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(a)

20 years

$47

(b)

Butler

CERSM, LLC and Community Energy, Inc.

103

Taylor

December 2016

Georgia Power^(a)

30 years

220

$230

(b)

Pawpaw

Longview Solar, LLC

Taylor

December 2015

Georgia Power^(a)

30 years

$80

(b)

Butler Solar Farm

Strata Solar Development, LLC

Taylor

December 2015

Georgia Power^(a)

20 years

$48

(b)

(a) Subject to FERC approval.

(b) Includes the acquisition price of all outstanding membership interests.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

Power Sales Agreements

FERC Matters

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Recently Issued Accounting Standards

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FINANCIAL CONDITION AND LIQUIDITY

Overview

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. Subsequent to June 30, 2015, $525 million of long-term debt was repaid at maturity. There are no other scheduled maturities of long-term debt through June 30, 2016.

Sources of Capital

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power Company is currently in compliance with all covenants in the Facility.

Details of short-term borrowings were as follows:



	Commercial Paper at the End of the Period				Commercial Paper During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
June 30, 2015:	$	—	—	%	$	163	0.6	%	$	339

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.

Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and operating cash flows.

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

The maximum potential collateral requirements under these contracts at June 30, 2015 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	320
Below BBB- and/or Baa3	1,081

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Power's ability to access capital markets, particularly the short-term debt market.

Financing Activities

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS



Note		Page Number
A	Introduction	150
B	Contingencies and Regulatory Matters	152
C	Fair Value Measurements	168
D	Stockholders' Equity	173
E	Financing	175
F	Retirement Benefits	177
G	Income Taxes	180
H	Derivatives	181
I	Acquisitions	190
J	Segment and Related Information	193

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.



Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I, J
Alabama Power	A, B, C, E, F, G, H
Georgia Power	A, B, C, E, F, G, H
Gulf Power	A, B, C, E, F, G, H
Mississippi Power	A, B, C, E, F, G, H
Southern Power	A, B, C, D, E, G, H, I

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(UNAUDITED)


(A)	INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2014 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2015 and 2014. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Recently Issued Accounting Standards

The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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(UNAUDITED)

On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of any registrant.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new asset retirement obligations (ARO) for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates.



	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Balance at beginning of year	$	2,201		$	829		$	1,255		$	17	$	48
Liabilities incurred	612			401			—			71		97
Liabilities settled	(10		)	(1		)	(9		)	—		—
Accretion	53			23			28			—		1
Cash flow revisions	58			—			82			4		2
Balance at end of period	$	2,914		$	1,252		$	1,356		$	92	$	148

The increases in liabilities incurred and cash flow revisions for the six months ended June 30, 2015 primarily relate to an increase in AROs associated with facilities impacted by the CCR Rule.

In connection with a proposed settlement related to the closure of Plant Scholz, Gulf Power may incur additional AROs associated with CCR of approximately $15 million to $35 million.

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(UNAUDITED)


(B)	CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

Environmental Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions sought penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) was partially settled in 2006 through a consent decree with the EPA, and additional claims remain pending in the U.S. District Court for the Northern District of Alabama. On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case against Alabama Power. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

The ultimate outcome of these matters cannot be determined at this time.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of June 30, 2015 was $40 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act

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(UNAUDITED)

(CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.

Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.

In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In 2013, the U.S. District Court for the Eastern District of North Carolina Western Division ruled that Georgia Power has no liability in the private action and, on March 20, 2015, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court's ruling. Therefore, the private action is now concluded.

The ultimate outcome of these remaining matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $47 million as of June 30, 2015. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

In 2003, Mississippi Power and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers. The TCEQ approved the final site remediation plan in 2013 and, in March 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability was $0.3 million as of June 30, 2015 and is expected to be recovered through the ECO Plan.

The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

Nuclear Fuel Disposal Cost Litigation

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

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(UNAUDITED)

In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. The judgment amounts were paid on March 19, 2015. In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. The final outcome of this matter for Alabama Power cannot be determined at this time; however, no material impact on Southern Company's or Alabama Power's net income is expected as the damage amounts collected from the government are expected to be used for the benefit of customers.

In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of June 30, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

FERC Matters

Municipal and Rural Associations Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.

On March 31, 2015, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgo the Municipal and Rural Associations cost-based electric tariff increase reflected in the filing by, among other things, increasing the accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, which was accepted by the FERC on May 13, 2015, provides that the additional accrual of AFUDC was effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $11 million annually, of which $8 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.

Market-Based Rate Authority

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(UNAUDITED)

for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The recovery balance of each regulatory clause follows:



Regulatory Clause	Balance Sheet Line Item	June 30, 2015		December 31, 2014
		(in millions)
Rate CNP Compliance – Under^*	Deferred under recovered regulatory clause revenues	$	25	$	2
	Under recovered regulatory clause revenues, current	29		47
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	72		29
	Under recovered regulatory clause revenues, current	—		27
Retail Energy Cost Recovery – Over	Deferred over recovered regulatory clause revenues	72		47
Natural Disaster Reserve	Other regulatory liabilities, deferred	81		84

* Formerly Known As Rate CNP Environmental

Rate CNP

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" and of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism and the normal purchases and normal sales (NPNS) exception for wind PPAs.

On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $30 million of non-environmental compliance costs during the first six months of 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under recovered position for Rate CNP Compliance during 2015.

In April 2015, the FASB proposed new accounting guidance to allow the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power currently accounts for its two wind PPAs. On July 9, 2015, the FASB ratified the consensus reached by the Emerging Issues Task Force to allow the exception in such cases and voted to issue a final accounting standard.

Environmental Accounting Order

In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Subject to the final approval of the New Source Review stipulation, Alabama Power will also

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(UNAUDITED)

retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See "Environmental Matters – New Source Review Actions" herein for additional information regarding the NSR actions.

In accordance with an accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's or Alabama Power's financial statements.

Georgia Power

Integrated Resource Plan

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

Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

As of June 30, 2015 and December 31, 2014, Georgia Power's under recovered fuel balance totaled $106 million and $199 million, respectively. For June 30, 2015 and December 31, 2014, the balance is included in current assets and current assets and other deferred charges and assets, respectively, on Southern Company's and Georgia Power's Condensed Balance Sheets herein. Georgia Power expects to file its next fuel case in September 2015. The ultimate outcome of this matter cannot be determined at this time.

Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.

Nuclear Construction

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to

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(UNAUDITED)

Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.

Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million in 2008 dollars (approximately $591 million in 2015 dollars).The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor subsequently asserted estimated minimum damages related to the amended counterclaim (based on Georgia Power's ownership interest) of approximately $113 million in 2014 dollars (approximately $118 million in 2015 dollars).In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.

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(UNAUDITED)

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Georgia Power's eighth VCM report filed in 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

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such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

The ultimate outcome of these matters cannot be determined at this time.

Gulf Power

Retail Base Rate Case

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.

In December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $19.6 million reduction in depreciation expense in the first six months of 2015.

Cost Recovery Clauses



Recovery Clause	Balance Sheet Location	June 30, 2015		December 31, 2014
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	24	$	40
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	2		—
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	7		10
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	—		3

Mississippi Power

2015 Rate Case

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

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Performance Evaluation Plan

On March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow it more time for review. The ultimate outcome of this matter cannot be determined at this time.

System Restoration Rider

See Note 1 to the financial statements of Mississippi Power under "Provision for Property Damage" in Item 8 of the Form 10-K for additional information.

On February 2, 2015, Mississippi Power submitted its 2015 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2015 SRR rate remain level at zero and Mississippi Power be allowed to accrue $3 million to the property damage reserve in 2015. On March 3, 2015, the Mississippi PSC suspended the filing to allow it more time for review. The ultimate outcome of this matter cannot be determined at this time.

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" and "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC and information on Plant Watson Units 4 and 5.

In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which are scheduled to be placed in service in September and November 2015, respectively. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of June 30, 2015, total project expenditures were $604 million, of which Mississippi Power's portion was $308 million, excluding AFUDC of $27 million.

On February 25, 2015, Mississippi Power submitted its annual ECO filing for 2015, which indicated an annual increase in revenues of approximately $8 million. On February 27, 2015, the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.

On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million excluding the reserve for cost of removal and has been reclassified to other regulatory assets, deferred, on Mississippi Power's Condensed Balance Sheet herein in accordance with an accounting order from the Mississippi PSC. Mississippi Power expects to recover through its rates the remaining book value of the retired assets and certain costs, including unusable inventory, associated with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.

Fuel Cost Recovery

At June 30, 2015, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $24 million compared to under-recovered retail fuel costs of $2 million at December 31, 2014.

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Ad Valorem Tax Adjustment

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information.

On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates. On May 26, 2015 the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

Kemper IGCC Schedule and Cost Estimate

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the Kemper IGCC costs subject to the cost cap and the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of June 30, 2015, as adjusted for the Court's decision, are as follows:

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Cost Category	2010 Project Estimate^(f)		Current Estimate		Actual Costs at June 30, 2015
	(in billions)
Plant Subject to Cost Cap^(a)	$	2.40	$	4.96	$	4.51
Lignite Mine and Equipment	0.21		0.23		0.23
CO₂ Pipeline Facilities	0.14		0.11		0.11
AFUDC^(b)(c)	0.17		0.62		0.52
Combined Cycle and Related Assets Placed in Service – Incremental^(d)	—		0.02		—
General Exceptions	0.05		0.10		0.08
Deferred Costs^(c)(e)	—		0.19		0.15
Total Kemper IGCC^(a)(c)	$	2.97	$	6.23	$	5.60

(a)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of theasset purchase agreement (APA) and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.

(b)


(c)	Amounts in the Current Estimate reflect estimated costs through March 31, 2016.


(d)	Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.


(e)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."


(f)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificatedestimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23 million ($14 million after tax) in the second quarter 2015 and $9 million ($6 million after tax) in the first quarter 2015. These amounts are in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $868 million ($536 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively. The increases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to equipment rework, scope modifications, and the related additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up

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and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 2015 Rate Case and any alternative proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements.

2013 Settlement Agreement

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intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

2013 MPSC Rate Order

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.

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2015 Rate Case

As a result of the 2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On May 15, 2015, Mississippi Power sought alternate rate recovery and filed a rate case (2015 Rate Case) with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.

On July 10, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (the Supplemental Notice) with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal (In-Service Asset Proposal) for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.

Prudence Reviews

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Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.

Regulatory Assets and Liabilities

See Note 1 to the financial statements of Southern Company and Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.

Lignite Mine and CO₂ Pipeline Facilities

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affect pricing or minimum purchase quantities. Any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

The ultimate outcome of these matters cannot be determined at this time.

Termination of Proposed Sale of Undivided Interest to SMEPA

In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an ~~asset purchase agreement (APA)~~APA whereby SMEPA agreed to purchase a ~~17.5%~~ ~~undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the~~ ~~17.5%~~ ~~undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a~~ ~~17.5%~~ ~~to a~~ ~~15%~~ undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the April 2011 power supply agreement were $17.5 million in 2013. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014.

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~~(UNAUDITED)~~

~~In 2012 and on January 2, 2014, Mississippi Power received~~ ~~$150 million~~ and $75 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within ~~15 days~~ of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposits have been presented as a current liability in Southern Company's and Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Southern Company's and Mississippi Power's Condensed Statements of Cash Flows herein. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

~~By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle with respect to SMEPA's proposed purchase of~~ a 15% undivided interest in the Kemper IGCC. ~~The parties agreed to further amend~~On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA ~~as follows: (1)~~between Mississippi Power ~~agreed to cap at~~ ~~$2.88 billion~~ ~~the portion~~and SMEPA. Mississippi Power previously received a total of ~~the purchase price for development and construction costs, net~~$275 million of ~~the Cost Cap Exceptions; title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2)~~deposits from SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the plant's in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continuethat were required to be accrued on the capped development and construction costs, the Cost Cap Exceptions and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment ofreturned to SMEPA with interest ~~on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date.~~

~~On October 9, 2014, Mississippi Power received an additional $50 million deposit from SMEPA to be applied to the purchase.~~

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Baseload Act~~

In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with ~~such cancelled generating plant. There are legal challenges to~~ the ~~constitutionality~~termination of the ~~Baseload Act currently pending before~~APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the ~~Mississippi Supreme Court. The ultimate outcome~~aggregate principal amount of ~~any legal challenges~~approximately $301 million to ~~this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.~~Southern Company.

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~~(UNAUDITED)~~

Investment Tax Credits ~~and Bonus Depreciation~~

The IRS allocated ~~$279~~$279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through ~~September~~June 30, ~~2014,~~2015, Mississippi Power had recorded tax benefits totaling ~~$276.4~~$276 million for the Phase II credits, of which approximately ~~$140~~$242 million ~~have~~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 Kemper IGCC during operations in accordance with the Internal Revenue Code. ~~A portion of the Phase II tax credits will be subject~~Mississippi Power currently expects to ~~recapture upon completion of SMEPA's purchase of an undivided interest in~~place the Kemper IGCC ~~as described above.~~

~~In January 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended~~ ~~50%~~ ~~bonus depreciation for property placed~~ in service in ~~2013 (and for certain long-term production-period projects to be placed in service in 2014), which will apply primarily to~~ the ~~combined cycle and associated common facilities portion~~first half of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million. See "Rate Recovery of Kemper IGCC Costs – Seven-Year Rate Plan" herein for additional information.

2016. The ultimate outcome of ~~these matters~~this matter cannot be determined at this time.

~~Other Matters~~Section 174 Research and Experimental Deduction

~~Sierra Club Settlement Agreement~~

~~On August 1, 2014,~~Southern Company, on behalf of Mississippi Power, ~~entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club~~reflected deductions for research and experimental (R&E) expenditures related to ~~dismiss or withdraw all pending legal and regulatory challenges of~~ the Kemper IGCC in its federal income tax calculations for 2013 and ~~the scrubber project at Plant Daniel Units 1 and 2.~~2014. In ~~addition, the Sierra Club agreed~~May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to ~~refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings~~include deductions for ~~the~~ Kemper ~~IGCC, including, but not limited~~IGCC-related R&E expenditures. Due to the ~~prudence review,~~uncertainty related to this tax position, Southern Company and ~~Plant Daniel for a period~~Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of ~~three years from~~June 30, 2015. See Note 5 to the ~~date~~financial statements of Southern Company and Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the ~~Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw all appeals associated with certification of the Kemper IGCC~~Form 10-K and ~~the Plant Daniel Units 1~~Note (G) herein under "Unrecognized Tax Benefits – Section 174 Research and ~~2 scrubber project, which the applicable courts granted in the third quarter 2014.~~

Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a 15-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In accordance with the Sierra Club Settlement Agreement, Mississippi Power paid $7 million in the third quarter 2014, recognized in other income (expense), net in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" hereinExperimental Deduction" for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

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(C)	FAIR VALUE MEASUREMENTS

As of ~~September~~June 30, ~~2014,~~2015, assets and liabilities measured at fair value on a recurring basis during the period, together with the associated level of the fair value hierarchy, ~~in which they fall,~~ were as follows:


	Fair Value Measurements Using								Fair Value Measurements Using
As of September 30, 2014:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of June 30, 2015:									Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)								(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12	$	—	$	5	$	—	$	5
Interest rate derivatives									—		11		—		11
Nuclear decommissioning trusts^(a)	632		875		2		1,509		677		887		7		1,571
Cash equivalents	955		—		—		955		533		—		—		533
Other investments	9		—		1		10		9		—		1		10
Total	$	1,596	$	887	$	3	$	2,486	$	1,219	$	903	$	8	$	2,130
Liabilities:
Energy-related derivatives	$	—	$	53	$	—	$	53	$	—	$	180	$	—	$	180
Interest rate derivatives	—		2		—		2		—		14		—		14
Total	$	—	$	55	$	—	$	55	$	—	$	194	$	—	$	194

Alabama Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	5	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts^(b)
Domestic equity	399		78		—		477		381		78		—		459
Foreign equity	34		65		—		99		51		50		—		101
U.S. Treasury and government agency securities	—		34		—		34		—		36		—		36
Corporate bonds	—		98		—		98		10		121		—		131
Mortgage and asset backed securities	—		19		—		19		—		17		—		17
Other	—		8		2		10		—		6		7		13
Cash equivalents	543		—		—		543		81		—		—		81
Total	$	976	$	307	$	2	$	1,285	$	523	$	310	$	7	$	840
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	11	$	—	$	48	$	—	$	48
Interest rate derivatives	—		1		—		1		—		7		—		7
Total	$	—	$	12	$	—	$	12	$	—	$	55	$	—	$	55

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(UNAUDITED)


	Fair Value Measurements Using								Fair Value Measurements Using
As of September 30, 2014:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of June 30, 2015:									Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)								(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1	$	—	$	3	$	—	$	3
Interest rate derivatives									—		5		—		5
Nuclear decommissioning trusts^{(b) (c)}
Domestic equity	191		2		—		193		182		1		—		183
Foreign equity	—		132		—		132		—		125		—		125
U.S. Treasury and government agency securities	—		126		—		126		—		95		—		95
Municipal bonds	—		25		—		25		—		78		—		78
Corporate bonds	—		169		—		169		—		169		—		169
Mortgage and asset backed securities	—		114		—		114		—		108		—		108
Other	8		5		—		13		53		3		—		56
Total	$	199	$	574	$	—	$	773	$	235	$	587	$	—	$	822
Liabilities:
Energy-related derivatives	$	—	$	12	$	—	$	12	$	—	$	17	$	—	$	17
Interest rate derivatives									—		4		—		4
Total									$	—	$	21	$	—	$	21

Gulf Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Cash equivalents	18		—		—		18		$	18	$	—	$	—	$	18
Total	$	18	$	3	$	—	$	21
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	19	—		74		—		74

Mississippi Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents	45		—		—		45		$	182	$	—	$	—	$	182
Total	$	45	$	2	$	—	$	47
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	10	—		41		—		41

Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents	80		—		—		80		$	206	$	—	$	—	$	206
Total	$	80	$	1	$	—	$	81
Liabilities:
Energy-related derivatives	$	—	$	1	$	—	$	1


(a)	For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.


(b)	Excludes receivables related to investment income, pending investment sales, ~~and~~ payables related to pending investment ~~purchases.~~purchases, and currencies.


(c)	Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2015, approximately $39 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

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(UNAUDITED)


~~(c)~~	Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of September 30, 2014, approximately $58 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate ~~and foreign currency~~ derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. ~~Inputs for foreign currency derivatives are from observable market sources.~~ See Note (H) herein for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts, ~~specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External~~external pricing vendors are designated for each ~~of the~~ asset ~~classes in the nuclear decommissioning trusts~~class with each security ~~discriminately~~specifically assigned a primary pricing ~~source, based on similar characteristics.~~source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgment, are also obtained when available.

Investments in private equity and real estate within ~~the~~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 nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

"Other investments" include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. For investments that are not traded in the open ~~market, the price paid will~~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 ~~execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed.~~executions.

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(UNAUDITED)

As of ~~September~~June 30, ~~2014,~~2015, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

As of September 30, 2014:

Fair

Value

Unfunded

Commitments

Redemption

Frequency

Redemption

Notice Period

As of June 30, 2015:

Fair

Value

Unfunded

Commitments

Redemption

Frequency

Redemption

Notice Period

(in millions)

Southern Company

Nuclear decommissioning trusts:

Foreign equity funds

132

None

Monthly

5 days

125

None

Monthly

5 days

Equity - commingled funds

None

Daily/Monthly

Daily/7 days

None

Daily

Debt - commingled funds

None

Daily

5 days

Other - commingled funds

None

Daily

Not applicable

None

Daily

Not applicable

Other - money market funds

None

Daily

Not applicable

None

Daily

Not applicable

Trust-owned life insurance

112

None

Daily

15 days

117

None

Daily

15 days

Cash equivalents:

Money market funds

955

None

Daily

Not applicable

533

None

Daily

Not applicable

Alabama Power

Nuclear decommissioning trusts:

Equity - commingled funds

None

Daily/Monthly

Daily/7 days

None

Daily

Debt - commingled funds

None

Daily

5 days

Trust-owned life insurance

112

None

Daily

15 days

117

None

Daily

15 days

Cash equivalents:

Money market funds

543

None

Daily

Not applicable

None

Daily

Not applicable

Georgia Power

Nuclear decommissioning trusts:

Foreign equity funds

132

None

Monthly

5 days

125

None

Monthly

5 days

Other - commingled funds

None

Daily

Not applicable

None

Daily

Not applicable

Other - money market funds

None

Daily

Not applicable

None

Daily

Not applicable

Gulf Power

Cash equivalents:

Money market funds

None

Daily

Not applicable

None

Daily

Not applicable

Mississippi Power

Cash equivalents:

Money market funds

None

Daily

Not applicable

182

None

Daily

Not applicable

Southern Power

Cash equivalents:

Money market funds

None

Daily

Not applicable

206

None

Daily

Not applicable

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts ~~including~~(including American depositary receipts, European depositary receipts, and global depositary ~~receipts,~~receipts), and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to

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(UNAUDITED)

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

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

~~(UNAUDITED)~~

The ~~commingled~~other-commingled funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio ~~including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences~~ of ~~indebtedness with a maturity not exceeding 13 months from~~high-quality, short-term, liquid debt securities. The funds represent cash collateral received under the ~~date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days~~ Funds' managers' securities lending program and/or ~~less. The assets may be longer term~~excess cash held within each separate investment ~~grade fixed income obligations with maturity shortening provisions.~~account. The primary objective ~~for~~of the ~~commingled~~ funds is to provide a high level of current income consistent with stability of principal and liquidity. ~~Included~~The funds invest primarily in, commingled funds as of September 30, 2014 is $5 million representing the investment of cash collateral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. The money market fund within Georgia Power's nuclear decommissioning trusts represents the short-term investment of the trusts' excess cash with the goal of providing the highest possible level of income while preserving capital and maintaining liquidity. The fund's positions are in high-quality, short-term, liquid money market instruments including, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government ~~and~~or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt ~~securities. The fund maintains a dollar-weighted average maturity of 60~~securities that mature in 90 days or ~~less and is regulated by, and subject to, the money market regulatory requirements set by the SEC.~~less. Redemptions are available on a same day basis up to the full amount of the investment in the fund. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Alabama Power's nuclear decommissioning ~~trust includes~~trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning ~~trust invests~~trusts invest in the TOLI in order to minimize the impact of taxes on the ~~portfolio~~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 ~~trust does~~trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. ~~The~~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 ~~to some degree,~~ mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three and ~~nine~~six months ended ~~September~~June 30, ~~2014,~~2015, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, ~~decreased~~increased by ~~$13~~$44 million and ~~increased by $70~~$109 million, respectively, at Southern Company. For the three and ~~nine~~six months ended ~~September~~June 30, ~~2014,~~2015, Alabama Power recorded ~~a decrease~~an increase in fair value of $8$50 million and ~~an increase of $39~~$97 million, respectively, as an increase in regulatory liabilities. For the three and six months ended June 30, 2015, Georgia Power recorded a decrease in fair value of $5$6 million and an increase of ~~$31~~$12 million, respectively, as a reduction of its regulatory asset related to its ARO.

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.

~~168~~172

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of ~~September~~June 30, ~~2014,~~2015, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)				(in millions)
Long-term debt:
Long-term debt, including securities due within one year:
Southern Company	$	23,936	$	25,318	$	26,156	$	26,973
Alabama Power	$	6,625	$	7,195	$	7,295	$	7,621
Georgia Power	$	9,597	$	10,167	$	10,379	$	10,767
Gulf Power	$	1,444	$	1,517	$	1,370	$	1,438
Mississippi Power	$	2,365	$	2,397	$	2,275	$	2,246
Southern Power	$	1,629	$	1,745	$	2,262	$	2,302

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates ~~offered~~available 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 ~~effects~~effect of both stock options and performance share award units ~~were~~was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:


	Three Months Ended September 30, 2014	Three Months Ended September 30, 2013	Nine Months Ended September 30, 2014	Nine Months Ended September 30, 2013	Three Months Ended June 30, 2015	Three Months Ended June 30, 2014	Six Months Ended June 30, 2015	Six Months Ended June 30, 2014
	(in millions)				(in millions)
As reported shares	898	878	894	874	909	895	910	892
Effect of options and performance share award units	4	3	4	5	3	4	4	4
Diluted shares	902	881	898	879	912	899	914	896

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 1615 million and 1 million for the three and six months ended June 30, 2015, respectively, and were 8 million and 17 million for the three and ~~nine~~six months ended ~~September~~June 30, 2014, ~~respectively, and were 16 million and 1 million for the three and nine months ended September 30, 2013.~~respectively.

~~169~~173

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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					Issued				Total Stockholders' Equity			Treasury				Noncontrolling Interest^(*)				Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
														(in thousands)					Common Stockholders' Equity		(in millions)
Balance at December 31, 2014														908,502		(725	)		$	19,949		$	756		$	221		$	20,926
Net income after dividends on preferred and preference stock														—		—			1,138			—			—			1,138
Other comprehensive income (loss)														—		—			7			—			—			7
Stock issued														3,222		—			117			—			—			117
Stock-based compensation														—		—			66			—			—			66
Stock repurchased, at cost														—		(2,599	)		(115		)	—			—			(115		)
Cash dividends on common stock														—		—			(972		)	—			—			(972		)
Preference stock redemption														—		—			—			(150		)	—			(150		)
Contributions from noncontrolling interest														—		—			—			—			135			135
Distributions to noncontrolling interest														—		—			—			—			(5		)	(5		)
Net income attributable to noncontrolling interest														—		—			—			—			4			4
Other														—		25			(8		)	3			—			(5		)
Balance at June 30, 2015														911,724		(3,299	)		$	20,182		$	609		$	355		$	21,146
	(in thousands)			Common Stockholders' Equity						(in millions)
Balance at December 31, 2013	892,733	(5,647	)	$	19,008			Preferred and Preference Stock of Subsidiaries	$	756		$	19,764		892,733		(5,647	)		$	19,008		$	756		$	—		$	19,764
Net income after dividends on preferred and preference stock	—	—		1,680				—			1,680			—		—			962			—			—			962
Other comprehensive income (loss)	—	—		6				—			6			—		—			4			—			—			4
Treasury stock re-issued	—	4,996		225				—			225			—		4,739			216			—			—			216
Stock issued	7,781	—		332				—			332			3,898		—			161			—			—			161
Stock repurchased, at cost	—	—		(5		)		—			(5		)	—		—			(5		)	—			—			(5		)
Cash dividends on common stock	—	—		(1,390		)		—			(1,390		)	—		—			(920		)	—			—			(920		)
Other	—	(51	)	1				—			1			—		(27	)		—			—			—			—
Balance at September 30, 2014	900,514	(702	)	$	19,857			$	756		$	20,613

Balance at December 31, 2012	877,803	(10,035	)	$	18,297			$	707		$	19,004
Net income after dividends on preferred and preference stock	—	—		1,230				—			1,230
Other comprehensive income (loss)	—	—		11				—			11
Treasury stock re-issued	—	1,956		89				—			89
Stock issued	12,046	—		484				49			533
Stock repurchased, at cost	—	—		(19		)		—			(19		)
Cash dividends on common stock	—	—		(1,314		)		—			(1,314		)
Other	—	(30	)	—				—			—
Balance at September 30, 2013	889,849	(8,109	)	$	18,778			$	756		$	19,534
Balance at June 30, 2014														896,631		(935	)		$	19,426		$	756		$	—		$	20,182

(*) Primarily related to Southern Power Company.

Stock Repurchased

On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through June 30, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market

~~170~~174

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.


(E)	FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of ~~September~~June 30, ~~2014~~2015 was approximately ~~$1.8 billion.~~$1.9 billion (comprised of approximately $810 million at Alabama Power, $970 million at Georgia Power, $69 million at Gulf Power, and $40 million at Mississippi Power). In addition, at ~~September~~June 30, ~~2014,~~2015, the traditional operating companies had ~~$423~~approximately $368 million (comprised of approximately $200 million at Alabama Power, $122 million at Georgia Power, and $46 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that ~~will be~~were required to be ~~remarketed~~reoffered within the next 12 months. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information. In addition, $98 million of certain pollution control revenue bonds of Georgia Power have been reclassified to securities due within one year in anticipation of redemption in connection with unit retirement decisions. See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" and "Retail Regulatory Matters – Integrated Resource Plans," respectively, in Item 8 of the Form 10-K"Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of ~~September~~June 30, ~~2014:~~2015:


	Expires														Executable Term Loans				Due Within One Year				Expires												Executable Term Loans				Due Within One Year
Company	2014		2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out		2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)										(in millions)				(in millions)				(in millions)				(in millions)								(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	70		158		50		—		1,030		1,308		1,308		58		—		58		170		154		124		—		1,030		1,308		1,307		58		—		58		170
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—		—		150		—		1,600		1,750		1,737		—		—		—		150
Gulf Power	20		60		165		30		—		275		275		50		—		50		30		20		225		30		—		275		275		50		—		50		195
Mississippi Power	15		120		165		—		—		300		300		25		40		65		70		40		255		—		—		295		265		30		40		70		225
Southern Power	—		—		—		—		500		500		499		—		—		—		—		—		—		—		500		500		466		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		50		25		45		—		—		70		70		20		—		20		50
Total	$	105	$	408	$	530	$	30	$	4,130	$	5,203	$	5,188	$	153	$	40	$	193	$	320	$	239	$	799	$	30	$	4,130	$	5,198	$	5,120	$	158	$	40	$	198	$	790

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

~~171~~175

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first ~~nine~~six months of ~~2014:~~2015:


Company(a)	Senior Note Issuances		Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds^(a)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions^(b)			Senior Note Issuances		Senior Note Redemptions		Revenue Bond Issuances and Reofferings of Purchased Bonds^(b)		Revenue Bond Maturities and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(c)
	(in millions)														(in millions)
Southern Company	$	750	$	350	$	—	$	—	$	—		$	—		$	600	$	—	$	—	$	—	$	—	$	—
Alabama Power	400		—		—		—		—			—			975		250		80		134		—		—
Georgia Power	—		—		40		37		1,000			4			—		125		170		65		600		5
Gulf Power	200		—		42		29		—			—
Mississippi Power	—		—		—		—		493			222			—		—		—		—		—		351
Southern Power	—		—		—		—		10			1			650		—		—		—		—		—
Other	—		—		—		—		—			15			—		—		—		—		—		9
Elimination^(c)	—		—		—		—		(220		)	(220		)
Total	$	1,350	$	350	$	82	$	66	$	1,283		$	22		$	2,225	$	375	$	250	$	199	$	600	$	365


(a)	~~Includes remarketing by~~ Gulf Power did not issue or redeem any long-term debt during the first six months of ~~$13~~2015.

(b)


~~(b)~~(c)	Includes reductions in capital lease obligations resulting from cash payments under capital leases.


~~(c)~~	~~Intercompany loan from Southern Company to Mississippi Power eliminated in Southern Company's Condensed Consolidated Financial Statements. This loan was repaid on September 29, 2014.~~

Southern Company

Alabama Power

~~Georgia Power~~

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee.

The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB. On February 20, 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount ofprogram.

~~172~~176

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~$1.0 billion.~~ Georgia Power's reimbursement obligations to the DOE are full recourse and also secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. Power

In ~~connection with its entry into the agreements with the DOE and the FFB,~~April 2015, Georgia Power ~~incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.~~

~~See Note 6 to the financial statements of Southern Company~~purchased and ~~Georgia Power in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.~~

~~In July 2014, Georgia Power reoffered to the public $40~~held $65 million aggregate principal amount of Development Authority of ~~Monroe~~Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant ~~Scherer~~Vogtle Project), Second Series 2008. Georgia Power reoffered these bonds to the public in May 2015.

In May 2015, Georgia Power reoffered to the public $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series ~~2009,~~2013, which had been previously purchased and held by Georgia Power since ~~2010.~~

~~Gulf Power~~2013.

In ~~April 2014, Gulf~~June 2015, Georgia Power ~~executed a loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075 million~~made additional borrowings under the FFB Credit Facility in an aggregate principal amount of ~~Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 for~~$600 million. The interest rate applicable to the ~~benefit of Gulf Power. The proceeds were used to redeem $29.075~~$600 million ~~aggregate~~ principal amount ~~of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).~~

~~In June 2014, Gulf Power reoffered~~is 3.283% for an interest period that extends to the ~~public $13 million aggregate principal amount~~final maturity date of ~~MBFC Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 2012 (Gulf Power Company Project), which had been previously purchased and held by Gulf Power since December 2013.~~

~~In September 2014, Gulf Power issued $200 million aggregate principal amount of Series 2014A 4.55% Senior Notes due October 1,~~February 20, 2044. The proceeds were used to ~~repay~~reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. Georgia Power settled $350 million of interest rate swaps related to this borrowing for approximately $6 million, which will be amortized to interest expense over 10 years.

Mississippi Power

In April 2015, Mississippi Power entered into two floating rate bank loans with a ~~portion~~maturity date of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power's continuous construction program, and subsequent to September 30, 2014, for repayment at maturity $75 millionApril 1, 2016, in an aggregate principal amount of ~~Gulf Power's Series K 4.90% Senior Notes due October 1, 2014.~~

~~Mississippi Power~~

~~In January 2014, Mississippi Power entered into an 18-month floating rate bank loan~~$475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term ~~loan was for $250 million~~loans in an aggregate principal amount ~~and proceeds were used for~~of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ~~continuous~~ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

In ~~January 2014 and subsequent to September 30, 2014,~~June 2015, Mississippi Power ~~received~~issued an ~~additional $75~~18-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, ~~and $50 million, respectively,~~the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of ~~interest-bearing refundable deposits from SMEPA to be applied to~~ the ~~sale price for~~return of SMEPA's deposit in connection with the ~~pending sale~~termination of ~~an undivided interest in~~ the ~~Kemper IGCC.~~APA. See Note ~~3 to the financial statements of Southern Company and Mississippi Power in Item 8 of the Form 10-K~~(B) under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

As reflected in the table above in "Other Long-Term Debt Issuances," in May 2014, Mississippi Power issued a 19-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loan was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program. This loan was repaid on September 29, 2014.

In May 2014 and August 2014, the MBFC issued $12.3 million and $10.5 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of

~~173~~

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

~~(UNAUDITED)~~

Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose.

~~Southern Power~~

During the nine months ended September 30, 2014, Southern Power prepaid $0.8 million of long-term debt payable to Turner Renewable Energy, LLC (TRE) and issued $3.9 million due April 30, 2034, $5.3 million due May 31, 2034, $0.8 million due April 30, 2033, and an additional $0.1 million due June 15, 2032 under promissory notes payable to TRE related to the financing of Adobe Solar, LLC (Adobe), Macho Springs Solar, LLC (Macho Springs), Campo Verde Solar, LLC, and Apex Nevada Solar, LLC, respectively.


~~(F)~~	~~RETIREMENT BENEFITS~~

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

~~See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.~~

~~174~~

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

~~(UNAUDITED)~~

~~Components of the net periodic benefit costs for the three and nine months ended September 30, 2014 and 2013 were as follows:~~

Pension Plans
Southern
Company

Alabama
Power

Georgia
Power

Gulf
Power

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

~~175~~

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

~~(UNAUDITED)~~

Postretirement Benefits
Southern
Company

Alabama
Power

Georgia
Power

Gulf
Power

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

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

~~(UNAUDITED)~~


~~(G)~~	~~EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS~~

~~Effective Tax Rate~~

~~See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.~~

~~Southern Company~~

~~Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity.~~

Southern Company's effective tax rate was 33.9% for the nine months ended September 30, 2014 compared to 33.9% for the corresponding period in 2013. The effective tax rate was impacted by the offsetting increases resulting from higher net income and less benefit related to investment tax credits, and decreases resulting from more non-taxable AFUDC equity, changes in state apportionment, and beneficial changes in certain state income tax laws.

~~Alabama Power~~

~~Alabama Power's effective tax rate was 39.0% for the nine months ended September 30, 2014 compared to 39.3% for the corresponding period in 2013.~~

~~Georgia Power~~

~~Georgia Power's effective tax rate was 37.2% for the nine months ended September 30, 2014 compared to 38.0% for the corresponding period in 2013.~~

~~Gulf Power~~

~~Gulf Power's effective tax rate was 37.4% for the nine months ended September 30, 2014 compared to 37.6% for the corresponding period in 2013.~~

~~Mississippi Power~~

Mississippi Power's effective tax rate was (45.5)% for the nine months ended September 30, 2014 compared to (42.1)% for the corresponding period in 2013. The change in the tax benefit was primarily due to an increase in non-taxable AFUDC equity related to the construction of the Kemper IGCC, partially offset by a lower net loss for the current period compared to the corresponding period in 2013.

Southern Power


(F)	RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Components of the net periodic benefit costs for the three and six months ended June 30, 2015 and 2014 were as follows:



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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)



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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


(G)	INCOME TAXES

Current and Deferred Income Taxes

State of Georgia Tax Benefits

During the second quarter 2015, an agreement was reached with the Georgia Department of Revenue that will allow Southern Company to utilize a net operating loss carryforward over a four-year period beginning in 2017. Consequently, Southern Company reversed the related valuation allowance and recognized approximately $24 million in net tax benefits as of June 30, 2015. See Note 5 to the financial statements of Southern Company under "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.

Southern Power ITC Carryforwards

Southern Power had federal ITC carryforwards which are expected to result in $428 million of federal income tax benefits as of June 30, 2015, compared to $305 million as of December 31, 2014. The carryforwards as of June 30, 2015 expire between 2031 and 2035 and are expected to be utilized by the end of 2016.

Effective Tax Rate

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Mississippi Power

Mississippi Power's effective tax rate was 19.0% for the six months ended June 30, 2015 compared to (51.1)% for the corresponding period in 2014. The increase was primarily due to higher net income, partially offset by a decrease in non-taxable AFUDC equity related to the construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was ~~14.4%~~13.7% for the ~~nine~~six months ended ~~September~~June 30, ~~2014~~2015 compared to ~~20.5%~~0.3% for the corresponding period in ~~2013.~~2014. The ~~decrease~~increase was primarily due to ~~the impact of state apportionment~~beneficial changes ~~which reduced Southern Power's deferred tax liabilities, a change in filing method for North Carolina income tax, an increase in~~that impacted 2014 state income ~~tax credits, and beneficial changes in certain state income tax laws. The decrease was~~taxes, which were partially offset by ~~less~~increased federal income tax ~~benefit~~benefits related to ~~investment tax credits~~ITCs in the current year.

Unrecognized Tax Benefits

~~For~~See Note 5 to the ~~2013 tax year,~~financial statements of Southern Company under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.

Changes during 2015 for unrecognized tax benefits were as follows:



	Mississippi Power			Southern Power		Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2014	$	165		$	5	$	170
Tax positions from current periods	—			2		2
Tax positions from prior periods	230			—		231
Reductions due to settlements	(5		)	—		(5		)
Balance as of June 30, 2015	$	390		$	7	$	398

The tax positions from prior periods relate primarily to 2008 through 2013 amended federal income tax returns that were filed to include deductions for Kemper IGCC-related R&E expenditures. See "Section 174 Research and Experimental Deduction" herein for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The impact on the effective tax rate, if recognized, was as follows:



	As of June 30, 2015						As of December 31, 2014
	Mississippi Power		Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	—	$	7	$	8	$	10
Tax positions not impacting the effective tax rate	390		—		390		160
Balance of unrecognized tax benefits	$	390	$	7	$	398	$	170

The tax positions impacting the effective tax rate primarily relate to federal income tax benefits related to ITCs. The tax positions not impacting the effective tax rate relate to deductions for Kemper IGCC-related R&E expenditures. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Section 174 Research and Experimental Deduction

Southern Company reduced tax payments for 2014, and included in its 2013 consolidated federal income tax return ~~a deduction~~deductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures.

The Kemper IGCC is based on first-of-a-kind technology, and Mississippi Power and Southern Company believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position, Mississippi Power and Southern Company ~~recorded an~~had related unrecognized tax ~~benefit~~benefits associated with these R&E deductions of approximately ~~$100~~$390 million and associated interest of $2$5 million as of ~~September~~June 30, ~~2014.~~2015.

The ultimate outcome of this matter cannot be determined at this time.

~~177~~

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

~~(UNAUDITED)~~


(H)	DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate ~~risk, and occasionally foreign currency~~ risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note (C) herein for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating ~~activities and the cash impacts of settled foreign currency derivatives are recorded as investing~~ activities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel

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(UNAUDITED)

prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, ~~Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales from its uncontracted generating capacity. Further,~~ the traditional operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for under one of three methods:

Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

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~~(UNAUDITED)~~

At ~~September~~June 30, ~~2014,~~2015, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:


	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)			(in millions)
Southern Company	232	2018	2017	220	2020	2017
Alabama Power	57	2017	—	49	2018	—
Georgia Power	47	2017	—	47	2017	—
Gulf Power	77	2018	—	80	2020	—
Mississippi Power	49	2017	—	43	2018	—
Southern Power	2	—	2017	1	2015	2017

In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 75 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 43 million mmBtu for Georgia Power, and 1 million mmBtu for Southern Power.

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending ~~September~~June 30, ~~2015~~2016 are immaterial for all registrants.

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Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.

At ~~September~~June 30, ~~2014,~~2015, the following interest rate derivatives were outstanding:

Notional
Amount

Interest
Rate
Received

Weighted
Average
Interest
Rate Paid

Hedge
Maturity
Date

Fair Value
Gain (Loss)
September 30,
2014
(in millions) (in millions)
Cash flow hedges of forecasted debt
Alabama Power $ 100
3-month
LIBOR 3.07% October 2025 $ (1 )
Fair value hedges on existing debt
Southern Company 250
1.30% 3-month
LIBOR + 0.17% August 2017 (1 )
Total $ 350
$ (2 )

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~~(UNAUDITED)~~

Subsequent to September 30, 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $100 million.

Subsequent to September 30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amounts of the swaps totaled $900 million.



	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2015
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power	$	200	3-month LIBOR	2.93%	October 2025	$	(7	)
Georgia Power	350		3-month LIBOR	2.57%	November 2025	(1		)
Cash Flow Hedges of Existing Debt
Georgia Power	250		3-month LIBOR + 0.32%	0.75%	March 2016	—
Georgia Power	200		3-month LIBOR + 0.40%	1.01%	August 2016	—
Fair Value Hedges on Existing Debt
Southern Company	250		1.30%	3-month LIBOR + 0.17%	August 2017	2
Southern Company	300		2.75%	3-month LIBOR + 0.92%	June 2020	1
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	1
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	1
Total	$	2,000				$	(3	)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending ~~September~~June 30, ~~2015~~2016 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2037.

~~Foreign Currency Derivatives~~

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset.

~~At September 30, 2014, there were no foreign currency derivatives outstanding.~~

~~Derivative Financial Statement Presentation and Amounts~~

At September 30, 2014, the fair value of energy-related derivatives (excluding regulatory hedges) was immaterial. At September 30, 2014, the fair value of energy-related derivatives designated as hedging instruments for regulatory purposes and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at September 30, 2014
Fair Value
Derivative Category and Balance Sheet Location
Southern
Company

Alabama
Power

Georgia
Power

Gulf
Power

Mississippi
Power

Southern
Power
(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets $ 9
$ 4
$ 1
$ 2
$ 2

Other deferred charges and assets 2
1
—
1
—

Total derivatives designated as hedging instruments for regulatory purposes $ 11
$ 5
$ 1
$ 3
$ 2
N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets $ 2
$ —
$ —
$ —
$ —
$ —
Total asset derivatives $ 13
$ 5
$ 1
$ 3
$ 2
$ —

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(UNAUDITED)

Derivative Financial Statement Presentation and Amounts

At June 30, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Liability Derivatives at September 30, 2014
Fair Value
Derivative Category and
Balance Sheet Location

Southern
Company

Alabama
Power

Georgia
Power

Gulf
Power

Mississippi
Power

Southern
Power
(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities ^(a)
$ 27
$ 5
$ 10
$ 7
$ 5

Other deferred credits and liabilities 25
6
2
12
5

Total derivatives designated as hedging instruments for regulatory purposes $ 52
$ 11
$ 12
$ 19
$ 10
N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other deferred credits and liabilities $ 4
$ 1
$ —
$ —
$ —
$ —
Total liability derivatives $ 56
$ 12
$ 12
$ 19
$ 10
$ —



Asset Derivatives at June 30, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	5	$	2	$	3	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	11	$	—	$	5	$	—	$	—	$	—
Total asset derivatives	$	16	$	2	$	8	$	—	$	—	$	—


~~(a)~~	~~Georgia Power includes liabilities from risk management activities in other current liabilities.~~



Liability Derivatives at June 30, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current liabilities^(*)	$	99		$	31	$	15	$	32	$	21
Other deferred credits and liabilities	81			17		2		42		20
Total derivatives designated as hedging instruments for regulatory purposes	$	180		$	48	$	17	$	74	$	41	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities^(*)	$	8	��	$	7	$	1	$	—	$	—	$	—
Other deferred credits and liabilities	6			—		3		—		—		—
Total derivatives designed as hedging instruments in cash flow and fair value hedges	$	14		$	7	$	4	$	—	$	—	$	—
Total liability derivatives	$	194		$	55	$	21	$	74	$	41	$	—

(*) Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

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(UNAUDITED)

At December 31, ~~2013,~~2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:


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

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(UNAUDITED)



Liability Derivatives at December 31, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current liabilities^(*)	$	118	$	32	$	23	$	37	$	26
Other deferred credits and liabilities	79		21		4		35		19
Total derivatives designated as hedging instruments for regulatory purposes	$	197	$	53	$	27	$	72	$	45	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities^(*)	$	17	$	8	$	9	$	—	$	—	$	—
Other deferred credits and liabilities	7		—		5		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	24	$	8	$	14	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities	$	4	$	—	$	—	$	—	$	—	$	4
Total liability derivatives	$	225	$	61	$	41	$	72	$	45	$	4

Liability Derivatives at December 31, 2013
Fair Value
Derivative Category and
Balance Sheet Location

Southern
Company

Alabama
Power

Georgia
Power

Gulf
Power

Mississippi
Power
Southern Power
(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities ^(a)
$ 26
$ 3
$ 13
$ 6
$ 4

Other deferred credits and liabilities 29
5
8
11
6

Total derivatives designated as hedging instruments for regulatory purposes $ 55
$ 8
$ 21
$ 17
$ 10
N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities $ 1
$ —
$ —
$ —
$ —
$ 1
Total liability derivatives $ 56
$ 8
$ 21
$ 17
$ 10
$ 1

~~(a) Georgia~~(*) Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management ~~activities in other current liabilities.~~activities."

The derivative contracts of Southern Company, the traditional operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and are reported gross on each registrant's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at ~~September~~June 30, ~~2014~~2015 and December 31, ~~2013~~2014 are presented in the following tables. ~~Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.~~

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(UNAUDITED)


Derivative Contracts at September 30, 2014
Derivative Contracts at June 30, 2015																		Derivative Contracts at June 30, 2015
	Fair Value																		Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power		Southern Power
	(in millions)																		(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	12		$	5		$	1		$	3		$	2		$	1		$	5		$	2		$	3		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet ^(b)	(11		)	(4		)	(1		)	(3		)	(2		)	—			(5		)	(2		)	(3		)	—		—		—
Net energy-related derivative assets	$	1		$	1		$	—		$	—		$	—		$	1		$	—		$	—		$	—		$	—	$	—	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet ^(a)																			$	11		$	—		$	5		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet ^(b)																			(8		)	—			(3		)	—		—		—
Net interest rate derivative assets																			$	3		$	—		$	2		$	—	$	—	$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	53		$	11		$	12		$	19		$	10		$	1		$	180		$	48		$	17		$	74	$	41	$	—
Gross amounts not offset in the Balance Sheet ^(b)	(11		)	(4		)	(1		)	(3		)	(2		)	—			(5		)	(2		)	(3		)	—		—		—
Net energy-related derivative liabilities	$	42		$	7		$	11		$	16		$	8		$	1		$	175		$	46		$	14		$	74	$	41	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet ^(a)																			$	14		$	7		$	4		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet ^(b)																			(8		)	—			(3		)	—		—		—
Net interest rate derivative liabilities																			$	6		$	7		$	1		$	—	$	—	$	—

(a) None of the registrants ~~offset~~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.

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(UNAUDITED)


Derivative Contracts at December 31, 2013
Derivative Contracts at December 31, 2014																		Derivative Contracts at December 31, 2014
	Fair Value																		Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company			Alabama Power		Georgia Power			Gulf Power		Mississippi Power		Southern Power
	(in millions)																		(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	24		$	7		$	5		$	7		$	5		$	1		$	13		$	1	$	7		$	—	$	—	$	5
Gross amounts not offset in the Balance Sheet ^(b)	(22		)	(5		)	(5		)	(6		)	(4		)	—			(9		)	—		(7		)	—		—		—
Net energy-related derivative assets	$	2		$	2		$	—		$	1		$	1		$	1		$	4		$	1	$	—		$	—	$	—	$	5
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet ^(a)																			$	8		$	—	$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet ^(b)																			(8		)	—		(6		)	—		—		—
Net interest rate derivative assets																			$	—		$	—	$	—		$	—	$	—	$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	56		$	8		$	21		$	17		$	10		$	1		$	201		$	53	$	27		$	72	$	45	$	4
Gross amounts not offset in the Balance Sheet ^(b)	(22		)	(5		)	(5		)	(6		)	(4		)	—			(9		)	—		(7		)	—		—		—
Net energy-related derivative liabilities	$	34		$	3		$	16		$	11		$	6		$	1		$	192		$	53	$	20		$	72	$	45	$	4
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet ^(a)																			$	24		$	8	$	14		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet ^(b)																			(8		)	—		(6		)	—		—		—
Net interest rate derivative liabilities																			$	16		$	8	$	8		$	—	$	—	$	—

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

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(UNAUDITED)

At ~~September~~June 30, ~~2014~~2015 and December 31, ~~2013,~~2014, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred ~~on the balance sheets~~ were as follows:


Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at September 30, 2014
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 2015																Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 2015
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power				Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)																(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(27	)	$	(5	)	$	(10	)	$	(7	)	$	(5	)		$	(99	)	$	(31	)	$	(15	)	$	(32	)	$	(21	)
Other regulatory assets, deferred	(25		)	(6		)	(2		)	(12		)	(5		)		(81		)	(17		)	(2		)	(42		)	(20		)
Other regulatory liabilities, current(a)	9			4			1			2			2				5			2			3			—			—
Other regulatory liabilities, deferred ^(a)(b)	2			1			—			1			—				—			—			—			—			—
Total energy-related derivative gains (losses)	$	(41	)	$	(6	)	$	(11	)	$	(16	)	$	(8	)		$	(175	)	$	(46	)	$	(14	)	$	(74	)	$	(41	)


~~(a)~~	~~Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.~~

(a) Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.



Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2014
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(118	)	$	(32	)	$	(23	)	$	(37	)	$	(26	)
Other regulatory assets, deferred	(79		)	(21		)	(4		)	(35		)	(19		)
Other regulatory liabilities, current ^(a)	7			1			6			—			—
Other regulatory liabilities, deferred ^(b)	—			—			1			—			—
Total energy-related derivative gains (losses)	$	(190	)	$	(52	)	$	(20	)	$	(72	)	$	(45	)

(a) Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

For the three months ended June 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:



Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships					Statements of Income Location	Amount
	2015		2014			2015			2014
	(in millions)					(in millions)
Southern Company
Interest rate derivatives	$	31	$	—	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Alabama Power
Interest rate derivatives	$	7	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
Georgia Power
Interest rate derivatives	$	24	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
Mississippi Power
Interest rate derivatives	$	—	$	—	Interest expense, net of amounts capitalized	$	—		$	(1	)
Southern Power
Interest rate derivatives	$	—	$	—	Interest expense, net of amounts capitalized	$	—		$	(1	)

~~183~~189

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2013
Derivative Category and Balance Sheet
Location

Southern
Company

Alabama
Power

Georgia
Power

Gulf
Power

Mississippi
Power
(in millions)
Energy-related derivatives:
Other regulatory assets, current $ (26 ) $ (3 ) $ (13 ) $ (6 ) $ (4 )
Other regulatory assets, deferred (29 ) (5 ) (8 ) (11 ) (6 )
Other regulatory liabilities, current 16
5
3
5
3
Other regulatory liabilities, deferred ^(a)
7
2
2
2
2
Total energy-related derivative gains (losses) $ (32 ) $ (1 ) $ (16 ) $ (10 ) $ (5 )


~~(a)~~	~~Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.~~

For the ~~three and nine~~six months ended ~~September~~June 30, ~~2014~~2015 and ~~2013,~~2014, the pre-tax effects of interest rate and foreign currency derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for all registrants. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on the statements of income were offset by changes to the carrying value of long-term debt and the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on the statements of income were offset by changes in the fair value of the purchase commitment related to equipment purchases.

~~For the three and nine months ended September 30, 2014 and 2013, the pre-tax effects of energy-related derivatives and~~ interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

For the three and six months ended June 30, 2015 and 2014, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

For the three and six months ended June 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2014~~2015 and ~~2013,~~2014, the pre-tax effects of ~~energy-related and foreign currency derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.~~

~~For Southern Power's~~ energy-related derivatives not designated as hedging instruments a portion of the pre-tax realized and unrealized gains and losses was associated with hedging fuel price risk of certain PPA customers and had no impact on net income or on fuel expense as presented in Southern Company's and Southern Power's statements of incomewere immaterial for ~~the three and nine months ended September 30, 2014 and 2013. This third party hedging activity has been discontinued.~~all registrants.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At ~~September~~June 30, ~~2014,~~2015, the registrants' collateral posted with their derivative counterparties was immaterial.

At ~~September~~June 30, ~~2014,~~2015, the fair value of derivative liabilities with contingent features was ~~$26~~$49 million for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were ~~$26~~$49 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have

~~184~~

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

~~(UNAUDITED)~~

investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.


(I)	ACQUISITIONS

~~Adobe Solar, LLC~~

See Note 2 to the financial statements of Southern Power under ~~"Adobe Solar,~~"2014 – SG2 Imperial Valley, LLC" in Item 8 of the Form 10-K for additional information.

~~On April 17, 2014, Southern Power and TRE, through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, acquired all of~~ During the ~~outstanding membership interests of Adobe from Sun Edison, LLC,~~second quarter 2015, the original developer of the project. Adobe constructed and owns an approximately 20-MW solar photovoltaic facility in Kern County, California. The solar facility began commercial operation on May 21, 2014 and the entire output of the plant is contracted under a 20-year PPA with Southern California Edison Company. The acquisition was in accordance with Southern Power's overall growth strategy.

~~Southern Power's acquisition of Adobe included cash consideration of approximately $96.2 million. The~~ fair values of the assets ~~liabilities,~~acquired of SG2 Imperial Valley, LLC were finalized and ~~intangibles acquired were~~ recorded as follows: ~~$83.5~~$707 million toas property, plant, and equipment ~~$14.5~~and $20 million ~~to receivables~~as prepayments related to ~~reimbursable~~ transmission ~~costs and $6.3 million~~services.

During 2015, Southern Power Company acquired or contracted to ~~PPA intangible, resulting~~acquire the following projects in ~~a $5.1 million bargain purchase gain~~accordance with a $2.9 million deferred tax liability. The bargain purchase gain is included in other income (expense), net in Southern Company's and Southern Power's Condensed Consolidated Statements of Income herein.its overall growth strategy. Acquisition-related costs were expensed as incurred and were not material.

~~Macho Springs Solar, LLC~~Kay County Wind Facility

On ~~May 22, 2014,~~February 24, 2015, Southern Power ~~and TRE,~~Company, through ~~STR, acquired~~its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of ~~Macho Springs~~ ~~from First Solar Development,~~ Kay Wind, LLC ~~the original developer of the project. Macho Springs constructed~~(Kay Wind) for approximately $492 million, with potential purchase price adjustments based on performance testing. Kay Wind is constructing and owns an approximately 50~~-MW solar photovoltaic~~299-MW wind facility in ~~Luna~~Kay County, ~~New Mexico.~~Oklahoma. The ~~solar~~wind facility ~~began~~is expected to begin commercial operation ~~on May 23,~~ ~~2014~~in late 2015, and the entire output of the ~~plant~~facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time.

Lost Hills-Blackwell Solar Facilities

On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a 20~~-year PPA~~wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with ~~El Paso~~ respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company,~~. The acquisition was in accordance with Southern Power's overall growth strategy.~~

~~Southern Power's acquisition of Macho Springs included cash consideration of~~ that together extend approximately ~~$130.0 million.~~29 years. As of ~~September~~June 30, ~~2014,~~2015, the fair ~~value~~values of the assets acquired ~~was~~were recorded ~~primarily~~as follows: $98 million as property, plant, and ~~equipment;~~equipment and $9 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration. ~~Acquisition-related costs were expensed as incurred and were not material.~~

~~SG2 Imperial Valley, LLC~~North Star Solar Facility

~~Subsequent to September~~On April 30, ~~2014,~~2015, Southern Power Company, through its ~~wholly-owned~~ subsidiary ~~SG2 Holdings, LLC (Holdings),~~SRP, acquired ~~all~~100% of the ~~outstanding~~class A membership interests of ~~SG2 Imperial Valley,~~NS Solar Holdings, LLC ~~(SG2)~~(North Star) from a wholly-owned subsidiary of First Solar, ~~Inc. (First Solar),~~ the developer of the ~~project. SG2~~project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is ~~constructing an~~entitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately ~~150-MW~~61-MW North Star solar ~~photovoltaic~~ facility in ~~Southern California (Imperial Facility), which is expected to begin~~Fresno County, California. The solar facility began commercial operation ~~later in~~on June 20, 2015, and the ~~fourth quarter 2014. The Imperial Facility's~~entire output of the project is contracted under a ~~25-year~~20-year PPA with ~~San Diego~~Pacific Gas &and Electric ~~Company, a subsidiary~~Company. As of ~~Sempra Energy. This PPA will be accounted for~~June 30, 2015, the fair values of the assets acquired were recorded as follows: $266 million as property, plant, and equipment, $24 million as an ~~operating lease.~~intangible asset, and $21 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration.

Construction Projects

~~In connection with~~strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this acquisition, Holdings made an aggregate payment (consisting of cash consideration and a secured promissory note) of approximately $128 million to the subsidiary of First Solar and became obligated to pay the contract price as it becomes due under the construction contract for the Imperial Facility. The allocation oftime.

~~185~~191

Table of Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

the purchase price to individual assets has not been finalized. In addition, subject to certain terms and conditions, a subsidiary of First Solar will be admitted as a minority member of Holdings, and as the members of Holdings will make additional agreed upon capital contributions to Holdings that will be used to pay off the previously issued secured promissory note and to fund the Imperial Facility's construction costs. As a result of these capital contributions, the aggregate purchase price payable by Southern Power ~~for~~Company's construction projects are detailed in the table below:

Solar Project

Seller

Nameplate Capacity

County Location in Georgia

Expected Commercial Operation Date

PPA Counterparty for Entire Plant Output

PPA Contract Period

Estimated Construction Cost

(MW)

(in millions)

Taylor County

N/A

146

Taylor

Fourth quarter 2016

Cobb, Flint, and Sawnee Electric Membership Corporations

25 years

260

$280

Decatur Parkway

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(a)

25 years

170

$173

(b)

Decatur County

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(a)

20 years

$47

(b)

Butler

CERSM, LLC and Community Energy, Inc.

103

Taylor

December 2016

Georgia Power^(a)

30 years

220

$230

(b)

Pawpaw

Longview Solar, LLC

Taylor

December 2015

Georgia Power^(a)

30 years

$80

(b)

Butler Solar Farm

Strata Solar Development, LLC

Taylor

December 2015

Georgia Power^(a)

20 years

$48

(b)

(a) Subject to FERC approval.

~~If the Imperial Facility does not achieve substantial~~completion by a certain date, Southern Power may require that First Solar make a rescission payment to Southern Power in an amount equal to Southern Power's investment in Holdings, and Southern Power would be required to transfer its ownership interests in SG2 back to First Solar (the Rescission Payment and Transfer).

~~The ultimate outcome of this matter cannot be determined at this time; however, Holdings believes the likelihood of the Rescission Payment and Transfer to be remote at the acquisition date.~~interests.

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Table of Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(J) SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were ~~$103~~$85 million and ~~$243~~$199 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2014,~~2015, respectively, and ~~$97~~$68 million and ~~$264~~$140 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2013,~~2014, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the three and ~~nine~~six months ended ~~September~~June 30, ~~2014~~2015 and ~~2013~~2014 was as follows:


	Electric Utilities																	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated		Traditional Operating Companies		Southern Power		Eliminations			Total		All Other		Eliminations			Consolidated
	(in millions)																	(in millions)
Three Months Ended September 30, 2014:
Three Months Ended June 30, 2015:
Operating revenues	$	5,007	$	435	$	(115	)	$	5,327	$	34		$	(22	)	$	5,339	$	4,077	$	337	$	(90	)	$	4,324	$	43	$	(30	)	$	4,337
Segment net income (loss)^(a)(b)	658		64		—			722		(2		)	(2		)	718		561		46		—			607		18		4			629
Nine Months Ended September 30, 2014:
Six Months Ended June 30, 2015:
Operating revenues	$	13,594	$	1,115	$	(301	)	$	14,408	$	114		$	(72	)	$	14,450	$	8,025	$	684	$	(213	)	$	8,496	$	83	$	(59	)	$	8,520
Segment net income (loss)^(a)(c)	1,557		128		—			1,685		—			(5		)	1,680		1,038		79		—			1,117		21		—			1,138
Total assets at September 30, 2014	$	62,419	$	4,609	$	(166	)	$	66,862	$	1,304		$	(512	)	$	67,654
Three Months Ended September 30, 2013:
Total assets at June 30, 2015																		$	67,362	$	6,226	$	(277	)	$	73,311	$	1,360	$	(490	)	$	74,181
Three Months Ended June 30, 2014:
Operating revenues	$	4,744	$	365	$	(104	)	$	5,005	$	35		$	(23	)	$	5,017	$	4,209	$	329	$	(84	)	$	4,454	$	39	$	(26	)	$	4,467
Segment net income (loss)^(b)(a)	765		85		—			850		(1		)	3			852		580		31		—			611		2		(2		)	611
Nine Months Ended September 30, 2013:
Six Months Ended June 30, 2014:
Operating revenues	$	12,430	$	975	$	(285	)	$	13,120	$	108		$	(68	)	$	13,160	$	8,587	$	680	$	(186	)	$	9,081	$	80	$	(50	)	$	9,111
Segment net income (loss)^(a)(c)	1,099		142		—			1,241		(12		)	1			1,230		899		64		—			963		2		(3		)	962
Total assets at December 31, 2013	$	59,447	$	4,429	$	(101	)	$	63,775	$	1,077		$	(306	)	$	64,546
Total assets at December 31, 2014																		$	64,644	$	5,550	$	(131	)	$	70,063	$	1,156	$	(296	)	$	70,923

(a) After dividends on preferred and preference stock of subsidiaries.

(b) Segment net income (loss) for the traditional operating companies for the three months ended ~~September~~June 30, ~~2014 and September 30, 2013~~2015 includes a ~~$418.0~~$23 million pre-tax charge ($~~258.1~~14 million after tax) ~~and a $150.0 million pre-tax charge ($92.6 million after tax), respectively,~~ for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

(c) Segment net income (loss) for the traditional operating companies for the ~~nine~~six months ended ~~September~~June 30, 2015 and June 30, 2014 ~~and September 30, 2013~~ includes ~~$798.0~~a $32 million in pre-tax ~~charges~~charge ($~~492.8~~20 million after tax) and ~~$1.14 billion in~~a $380 million pre-tax ~~charges~~charge ($~~704.0~~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.

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Table of Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services

Electric Utilities' Revenues
Period Retail Wholesale Other Total
(in millions)
Three Months Ended September 30, 2014 $ 4,558
$ 600
$ 169
$ 5,327
Three Months Ended September 30, 2013 4,319
520
166
5,005

Nine Months Ended September 30, 2014 $ 12,186
$ 1,719
$ 503
$ 14,408
Nine Months Ended September 30, 2013 11,237
1,406
477
13,120



	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2015	$	3,714	$	448	$	162	$	4,324
Three Months Ended June 30, 2014	3,770		515		169		4,454

Six Months Ended June 30, 2015	$	7,256	$	915	$	325	$	8,496
Six Months Ended June 30, 2014	7,628		1,119		334		9,081

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Table of Contents

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

Item ~~6. Exhibits.~~2. Unregistered Sales of Equity Securities and Use of Proceeds



2015	Total Number of Shares Purchased^(*)	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ^(*)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs ^(*)
April 1 – April 30	—	N/A	N/A	N/A
May 1 – May 31	—	N/A	N/A	N/A
June 1 – June 30	—	N/A	N/A	N/A
Total	—	N/A	N/A	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. There were no repurchases under this program in the second quarter 2015. As of June 30, 2015, Southern Company had repurchased a total of 2,599,366 shares under this program.

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Table of Contents

Item 6. Exhibits.

The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.



		(3) Articles of Incorporation and By-Laws

		(a)1	-	By-laws of Southern Company as amended effective May 27, 2015, and as presently in effect. (Designated in Form 8-K dated May 27, 2015, File No. 1-3526, as Exhibit 3.1.)

		(4) Instruments Describing Rights of Security Holders, Including Indentures

		Southern Company

		(a)1	-	~~Ninth~~Eleventh Supplemental Indenture to ~~the~~ Senior Note Indenture dated as of ~~August 22, 2014,~~June 12, 2015, providing for the issuance of the Series ~~2014A 1.30%~~2015A 2.750% Senior Notes due ~~August~~June 15, ~~2017.~~2020. (Designated in Form 8-K dated ~~August 19, 2014,~~June 9, 2015, File No. 1-3526, as Exhibit ~~4.2(a).~~4.2.)

	~~(a)2~~	Southern Power

		(f)1	-	~~Tenth~~Sixth Supplemental Indenture to ~~the~~ Senior Note Indenture dated as of ~~August 22, 2014,~~May 20, 2015, providing for the issuance of the Series ~~2014B 2.15%~~2015A 1.500% Senior Notes due ~~September~~June 1, ~~2019.~~2018. (Designated in Form 8-K dated ~~August 19, 2014,~~May 14, 2015, File No. ~~1-3526,~~333-98553, as Exhibit ~~4.2(b)~~4.4(a).)

		(f)2	-	Seventh Supplemental Indenture to Senior Note Indenture dated as of May 20, 2015, providing for the issuance of the Series 2015B 2.375% Senior Notes due June 1, 2020. (Designated in Form 8-K dated May 14, 2015, File No. 333-98553, as Exhibit 4.4(b).)

		(10) Material Contracts

		Southern Company

#		(a)1	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)

#	*	(a)2	-	First Amendment to the Deferred Compensation Plan for Outside Directors of The Southern Company, effective April 1, 2015.

		Alabama Power

#	*	(b)1	-	~~Fifty-Second Supplemental Indenture~~First Amendment to the ~~Senior Note Indenture dated as~~Deferred Compensation Plan for Outside Directors of ~~August 26, 2014, providing~~Alabama Power Company, effective June 1, 2015.
#		(b)2	-	Outside Directors Stock Plan for ~~the issuance of the Series 2014A 4.150% Senior Notes due August 15, 2044.~~The Southern Company and its Subsidiaries. (Designated in ~~Form 8-K dated August 20, 2014,~~Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. ~~1-3164,~~1-3526, as ~~Exhibit 4.6.~~Appendix A.)

		Georgia Power

	*	(c)1	-	Amendment No. 1 to Loan Guarantee Agreement between Georgia Power and the DOE, dated as of June 4, 2015.
#		(c)2	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)

		Gulf Power

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Table of Contents



#	*	(d)1	-	~~Twenty-First Supplemental Indenture~~First Amendment to the ~~Senior Note Indenture dated as~~Deferred Compensation Plan for Outside Directors of ~~September 23, 2014, providing~~Gulf Power Company, effective April 1, 2015.
#		(d)2	-	Outside Directors Stock Plan for ~~the issuance of the Series 2014A 4.55% Senior Notes due October 1, 2044.~~The Southern Company and its Subsidiaries. (Designated in ~~Form 8-K dated September 16, 2014,~~Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. ~~001-31737,~~1-3526, as ~~Exhibit 4.2.~~Appendix A.)

		Mississippi Power

#	*	(e)1	-	First Amendment to the Deferred Compensation Plan for Outside Directors of Mississippi Power Company, effective April 1, 2015.
#		(e)2	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)

		(24) Power of Attorney and Resolutions

		Southern Company

		(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, ~~2013,~~2014, File No. 1-3526 as Exhibit 24(a) ~~and incorporated herein by reference.~~.)

		Alabama Power

		(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, ~~2013,~~2014, File No. 1-3164 as Exhibit 24(b) ~~and incorporated herein by reference.~~.)

	~~(b)2~~	-	~~Power of Attorney for Mark A. Crosswhite. (Designated in the Form 10-Q for the quarter ended March 31, 2014, File No. 1-3164 as Exhibit 24(b)2 and incorporated herein by reference.)~~

	Georgia Power

		(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, ~~2013,~~2014, File No. 1-6468 as Exhibit 24(c) ~~and incorporated herein by reference.~~.)

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~~Table of Contents~~



Gulf Power

	(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, ~~2013,~~2014, File No. 001-31737 as Exhibit 24(d)~~(1) and incorporated herein by reference.~~.)

*	(d)2	-	Power of Attorney for Xia Liu.

	Mississippi Power

	(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, ~~2013,~~2014, File No. 001-11229 as Exhibit 24(e) ~~and incorporated herein by reference.~~.)

	Southern Power

	(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, ~~2013,~~2014, File No. 333-98553 as Exhibit 24(f) ~~and incorporated herein by reference.~~.)

	(31) Section 302 Certifications

	Southern Company

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

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

	Alabama Power

*	(b)1	-	Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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*	(b)2	-	Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

	Georgia Power

*	(c)1	-	Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

*	(c)2	-	Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

	Gulf Power

*	(d)1	-	Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

*	(d)2	-	Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

	Mississippi Power

*	(e)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

*	(e)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

	Southern Power

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

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

~~190~~

~~Table of Contents~~



(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.

198

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	Southern Power

*	(f)	-	Certificate of Southern ~~Power's~~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

~~191~~199

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THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.



		THE SOUTHERN COMPANY

By		Thomas A. Fanning
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)

By		Art P. Beattie
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: ~~November 6, 2014~~August 5, 2015

~~192~~200

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ALABAMA POWER COMPANY

SIGNATURES



		ALABAMA POWER COMPANY

By		Mark A. Crosswhite
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)

By		Philip C. Raymond
		Executive Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: ~~November 6, 2014~~August 5, 2015

~~193~~201

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GEORGIA POWER COMPANY

SIGNATURES



		GEORGIA POWER COMPANY

By		W. Paul Bowers
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)

By		W. Ron Hinson
		Executive Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: ~~November 6, 2014~~August 5, 2015

~~194~~202

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GULF POWER COMPANY

SIGNATURES



		GULF POWER COMPANY

By		S. W. Connally, Jr.
		President and Chief Executive Officer
		(Principal Executive Officer)

By		~~Richard S. Teel~~Xia Liu
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: ~~November 6, 2014~~August 5, 2015

~~195~~203

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MISSISSIPPI POWER COMPANY

SIGNATURES



		MISSISSIPPI POWER COMPANY

By		G. Edison Holland, Jr.
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)

By		Moses H. Feagin
		Vice President, Treasurer, and Chief Financial Officer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: ~~November 6, 2014~~August 5, 2015

~~196~~204

Table of Contents

SOUTHERN POWER COMPANY

SIGNATURES



		SOUTHERN POWER COMPANY

By		Oscar C. Harper IV
		President and Chief Executive Officer
		(Principal Executive Officer)

By		William C. Grantham
		Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: ~~November 6, 2014~~August 5, 2015

~~197~~205



	Commercial Paper at the End of the Period				Commercial Paper During the Period^(a)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
September 30, 2014:	$	20	0.3	%	$	44	0.3	%	$	83



Regulatory Clause	Balance Sheet Line Item	September 30, 2014		December 31, 2013
		(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	—	$	7
	Under recovered regulatory clause revenues, current	25		—
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	46		18
	Under recovered regulatory clause revenues, current	9		—
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	44		27
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	87		96



Recovery Clause	Balance Sheet Location	September 30, 2014		December 31, 2013
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	41.3	$	21.0
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	6.8		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	6.3		14.4
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	2.6		7.0



Asset Derivatives at September 30, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	9	$	4	$	1	$	2	$	2
Other deferred charges and assets	2		1		—		1		—
Total derivatives designated as hedging instruments for regulatory purposes	$	11	$	5	$	1	$	3	$	2	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	2	$	—	$	—	$	—	$	—	$	—
Total asset derivatives	$	13	$	5	$	1	$	3	$	2	$	—

Second Quarter 2015 vs. Second Quarter 2014

Year-to-Date 2015 vs. Year-to-Date 2014

(change in millions)

(% change)

(change in millions)

(% change)