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 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 30, ~~2014~~2015
The Southern Company	Par Value $5 Per Share	~~899,812,716~~908,938,919
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 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	3945
	Condensed Statements of Comprehensive Income	3945
	Condensed Statements of Cash Flows	4046
	Condensed Balance Sheets	4147
	Management's Discussion and Analysis of Financial Condition and Results of Operations	4349
	Georgia Power Company
	Condensed Statements of Income	5765
	Condensed Statements of Comprehensive Income	5765
	Condensed Statements of Cash Flows	5866
	Condensed Balance Sheets	5967
	Management's Discussion and Analysis of Financial Condition and Results of Operations	6169
	Gulf Power Company
	Condensed Statements of Income	7989
	Condensed Statements of Comprehensive Income	7989
	Condensed Statements of Cash Flows	8090
	Condensed Balance Sheets	8191
	Management's Discussion and Analysis of Financial Condition and Results of Operations	8393
	Mississippi Power Company
	Condensed Statements of Operations	98109
	Condensed Statements of Comprehensive Income (Loss)	98109
	Condensed Statements of Cash Flows	99110
	Condensed Balance Sheets	~~100~~111
	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~102~~113
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	~~129~~143
	Condensed Consolidated Statements of Comprehensive Income	~~129~~143
	Condensed Consolidated Statements of Cash Flows	~~130~~144
	Condensed Consolidated Balance Sheets	~~131~~145
	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~133~~147
	Notes to the Condensed Financial Statements	~~144~~159
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3743
Item 4.	Controls and Procedures	3743

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 30, ~~2014~~2015



		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	~~189~~212
Item 1A.	Risk Factors	~~189~~212
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~Inapplicable~~ 215
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	~~189~~216
	Signatures	~~192~~219

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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
AGL Resources	AGL Resources Inc., a Georgia corporation
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~~Bridge Agreement	~~Chancery Court~~Senior unsecured Bridge Credit Agreement, dated as of ~~Harrison County, Mississippi~~September 30, 2015, among Southern Company, the lenders identified therein, and Citibank, N.A.
CCR	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
~~Mississippi Power~~MATS rule	~~Mississippi Power~~Mercury and Air Toxics Standards rule
Merger	The merger of Merger Sub with and into AGL Resources on the terms and subject to the conditions set forth in the Merger Agreement, with AGL Resources continuing as the surviving corporation and a wholly-owned direct subsidiary of Southern Company
~~mmBtu~~Merger Agreement	~~Million British thermal unit~~
~~Moody's~~	~~Moody's Investors Service, Inc.~~
MW	~~Megawatt~~
~~NCCR~~	~~Nuclear Construction Cost Recovery~~
~~NRC~~	~~U.S. Nuclear Regulatory Commission~~
~~OCI~~	~~Other comprehensive income~~Agreement and Plan of Merger, dated as of August 23, 2015, among Southern Company, AGL Resources, and Merger Sub

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DEFINITIONS

(continued)



Term	Meaning

Merger Sub	AMS Corp., a Georgia corporation and a wholly-owned direct subsidiary of Southern Company
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 units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
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
Tranquillity	RE Tranquillity Holdings, LLC
Tranquillity Credit Agreement	Secured Credit Agreement, dated as of July 31, 2015, by and among RE Tranquillity LLC, an indirect subsidiary of Southern Power Company, the several lenders and issuing banks party thereto, and Norddeutsche Landesbank Girozentrale, New York Branch, as Administrative Agent
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 potential financing of the Merger, the expected timing of the completion of the Merger, the proposed settlement agreement between the Vogtle Owners and the Contractor, 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 contributions, financing activities, completion dates of acquisitions, construction projects, and changing fuel sources, filings with state and federal regulatory authorities, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•

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

current and future litigation, regulatory investigations, proceedings, or inquiries, including FERC matters and IRS and state tax audits;

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

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

available sources and costs of fuels;

effects of inflation;

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

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

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

advances in technology;

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

the ability to complete the proposed settlement among the Vogtle Owners and the Contractor, including the satisfaction of conditions to such settlement;

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

actions related to cost recovery for the ~~outcome~~Kemper IGCC, including the ultimate impact of ~~any~~the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's August 2015 interim rate order, and related legal or regulatory proceedings, ~~regarding any settlement agreement between~~ Mississippi ~~Power~~PSC review of the prudence of Kemper IGCC costs and approval of permanent rate recovery plans, actions relating to proposed securitization, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2015, satisfaction of requirements to utilize ITCs and grants, and the ~~Mississippi PSC,~~ultimate impact of the ~~March 2013 rate order approving retail rate increases consistent with~~termination of the ~~terms~~proposed sale of ~~any settlement agreement, or~~an interest in the ~~Baseload Act;~~Kemper IGCC to SMEPA;

the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;

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

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

internal restructuring or other restructuring options that may be pursued;

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

the expected timing, likelihood, and benefits of completion of the Merger, including the failure to receive, on a timely basis or otherwise, the required approvals by AGL Resources' shareholders and government or regulatory agencies (including the terms of such approvals), the possibility that long-term financing for the Merger may not be put in place prior to the closing, the risk that a condition to closing of the Merger or funding of the Bridge Agreement may not be satisfied, the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and AGL Resources will be greater than expected, the credit ratings of the combined company or its subsidiaries may be different from what the parties expect, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, the diversion of management time on Merger-related issues, and the impact of legislative, regulatory, and competitive changes;

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

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

the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist ~~incidents, 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 September 30,						For the Nine Months Ended September 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		$	4,701		$	4,558		$	11,958		$	12,186
Wholesale revenues	600			520			1,719			1,406			520			600			1,435			1,719
Other electric revenues	169			166			503			477			169			169			494			503
Other revenues	12			12			42			40			11			12			34			42
Total operating revenues	5,339			5,017			14,450			13,160			5,401			5,339			13,921			14,450
Operating Expenses:
Fuel	1,656			1,580			4,765			4,216			1,520			1,656			3,932			4,765
Purchased power	194			145			514			367			193			194			507			514
Other operations and maintenance	1,021			928			3,026			2,849			1,097			1,021			3,320			3,026
Depreciation and amortization	514			480			1,515			1,422			528			514			1,515			1,515
Taxes other than income taxes	258			243			751			710			264			258			761			751
Estimated loss on Kemper IGCC	418			150			798			1,140			150			418			182			798
Total operating expenses	4,061			3,526			11,369			10,704			3,752			4,061			10,217			11,369
Operating Income	1,278			1,491			3,081			2,456			1,649			1,278			3,704			3,081
Other Income and (Expense):
Allowance for equity funds used during construction	63			53			182			139			60			63			163			182
Interest expense, net of amounts capitalized	(207		)	(202		)	(623		)	(628		)	(218		)	(207		)	(612		)	(623		)
Other income (expense), net	(7		)	(5		)	(20		)	(31		)	(21		)	(7		)	(41		)	(20		)
Total other income and (expense)	(151		)	(154		)	(461		)	(520		)	(179		)	(151		)	(490		)	(461		)
Earnings Before Income Taxes	1,127			1,337			2,620			1,936			1,470			1,127			3,214			2,620
Income taxes	392			468			889			657			500			392			1,076			889
Consolidated Net Income	735			869			1,731			1,279			970			735			2,138			1,731
Dividends on Preferred and Preference Stock of Subsidiaries	17			17			51			49			11			17			42			51
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	718		$	852		$	1,680		$	1,230		$	959		$	718		$	2,096		$	1,680
Common Stock Data:
Earnings per share (EPS) -
Earnings per share (EPS) —
Basic EPS	$	0.80		$	0.97		$	1.88		$	1.41		$	1.05		$	0.80		$	2.30		$	1.88
Diluted EPS	$	0.80		$	0.97		$	1.87		$	1.40		$	1.05		$	0.80		$	2.30		$	1.87
Average number of shares of common stock outstanding (in millions)
Basic	898			878			894			874			910			898			910			894
Diluted	902			881			898			879			912			902			913			898
Cash dividends paid per share of common stock	$	0.5250		$	0.5075		$	1.5575		$	1.5050		$	0.5425		$	0.5250		$	1.6100		$	1.5575

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 September 30,						For the Nine Months Ended September 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		$	970		$	735		$	2,138		$	1,731
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 $(11), $-, $(10) and $-, respectively													(18		)	—			(16		)	—
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $3 and $2, respectively													1			1			4			4
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, $3 and $2, respectively													2			1			5			2
Total other comprehensive income (loss)	2			2			6			11			(15		)	2			(7		)	6
Dividends on preferred and preference stock of subsidiaries	(17		)	(17		)	(51		)	(49		)	(11		)	(17		)	(42		)	(51		)
Comprehensive Income	$	720		$	854		$	1,686		$	1,241		$	944		$	720		$	2,089		$	1,686

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 Nine Months Ended September 30,
	2014			2013			2015			2014
	(in millions)						(in millions)
Operating Activities:
Consolidated net income	$	1,731		$	1,279		$	2,138		$	1,731
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,798			1,725			1,787			1,798
Deferred income taxes	330			263			821			330
Investment tax credits							319			(70		)
Allowance for equity funds used during construction	(182		)	(139		)	(163		)	(182		)
Stock based compensation expense	51			48			77			51
Estimated loss on Kemper IGCC	798			1,140			182			798
Income taxes receivable, non-current							(444		)	—
Other, net	(74		)	76			7			(116		)
Changes in certain current assets and liabilities —
-Receivables	(640		)	(407		)	(118		)	(640		)
-Fossil fuel stock	522			471			239			522
-Materials and supplies	(45		)	33			(22		)	(45		)
-Other current assets	(29		)	(1		)	(18		)	(29		)
-Accounts payable	(92		)	(140		)	(266		)	(92		)
-Accrued taxes	403			268			408			403
-Accrued compensation	96			(198		)	(129		)	96
-Mirror CWIP							99			112
-Other current liabilities	20			(7		)	171			20
Net cash provided from operating activities	4,687			4,411			5,088			4,687
Investing Activities:
Plant acquisitions							(1,128		)	(218		)
Property additions	(3,903		)	(3,978		)	(3,490		)	(3,686		)
Investment in restricted cash	(11		)	(169		)	—			(11		)
Distribution of restricted cash	37			94
Nuclear decommissioning trust fund purchases	(635		)	(744		)	(1,164		)	(635		)
Nuclear decommissioning trust fund sales	633			742			1,159			633
Cost of removal, net of salvage	(106		)	(90		)	(118		)	(106		)
Change in construction payables, net							20			11
Prepaid long-term service agreement	(145		)	(79		)	(166		)	(145		)
Other investing activities	(27		)	122			7			—
Net cash used for investing activities	(4,157		)	(4,102		)	(4,880		)	(4,157		)
Financing Activities:
Decrease in notes payable, net	(1,117		)	(70		)
Increase (decrease) in notes payable, net							662			(1,117		)
Proceeds —
Long-term debt issuances	2,715			2,421			3,992			2,715
Interest-bearing refundable deposit	75			—			—			75
Preference stock	—			50
Common stock issuances	484			479			136			484
Redemptions —
Short-term borrowings							280			—
Redemptions and repurchases —
Long-term debt	(437		)	(1,767		)	(2,562		)	(437		)
Common stock repurchased	(5		)	(19		)
Interest-bearing refundable deposits							(275		)	—
Preferred and preference stock							(412		)	—
Common stock							(115		)	(5		)
Short-term borrowings							(255		)	—
Payment of common stock dividends	(1,391		)	(1,314		)	(1,465		)	(1,391		)
Payment of dividends on preferred and preference stock of subsidiaries	(51		)	(49		)	(48		)	(51		)
Other financing activities	(48		)	14			253			(48		)
Net cash provided from (used for) financing activities	225			(255		)
Net cash provided from financing activities							191			225
Net Change in Cash and Cash Equivalents	755			54			399			755
Cash and Cash Equivalents at Beginning of Period	659			628			710			659
Cash and Cash Equivalents at End of Period	$	1,414		$	682		$	1,109		$	1,414
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 $88 and $80 capitalized for 2015 and 2014, respectively)							$	590		$	560
Income taxes, net	263			149			(13		)	263
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							483			415

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 BALANCE SHEETS (UNAUDITED)


Assets	At September 30, 2014			At December 31, 2013			At September 30, 2015			At December 31, 2014
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	1,414		$	659		$	1,109		$	710
Receivables —
Customer accounts receivable	1,439			1,027			1,432			1,090
Unbilled revenues	476			448			488			432
Under recovered regulatory clause revenues	104			58			126			136
Other accounts and notes receivable	259			304			248			307
Accumulated provision for uncollectible accounts	(20		)	(18		)	(19		)	(18		)
Fossil fuel stock, at average cost	817			1,339			691			930
Materials and supplies, at average cost	1,018			959			1,046			1,039
Vacation pay	170			171			177			177
Prepaid expenses	387			489			248			665
Deferred income taxes, current							258			506
Other regulatory assets, current	147			124			421			346
Other current assets	47			39			45			50
Total current assets	6,258			5,599			6,270			6,370
Property, Plant, and Equipment:
In service	68,545			66,021			71,929			70,013
Less accumulated depreciation	23,846			23,059			24,190			24,059
Plant in service, net of depreciation	44,699			42,962			47,739			45,954
Other utility plant, net	218			240			73			211
Nuclear fuel, at amortized cost	840			855			869			911
Construction work in progress	7,410			7,151			9,562			7,792
Total property, plant, and equipment	53,167			51,208			58,243			54,868
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,510			1,465			1,473			1,546
Leveraged leases	680			665			752			743
Miscellaneous property and investments	245			218			489			203
Total other property and investments	2,435			2,348			2,714			2,492
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,488			1,432			1,553			1,510
Prepaid pension costs	438			419
Unamortized debt issuance expense	206			139			203			202
Unamortized loss on reacquired debt	274			293			232			243
Other regulatory assets, deferred	2,624			2,557			4,733			4,334
Income taxes receivable, non-current							444			—
Other deferred charges and assets	764			551			823			904
Total deferred charges and other assets	5,794			5,391			7,988			7,193
Total Assets	$	67,654		$	64,546		$	75,215		$	70,923

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 BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholders' Equity	At September 30, 2014			At December 31, 2013			At September 30, 2015			At December 31, 2014
	(in millions)						(in millions)
Current Liabilities:
Securities due within one year	$	2,398		$	469		$	3,313		$	3,333
Interest-bearing refundable deposit	225			150
Interest-bearing refundable deposits							—			275
Notes payable	361			1,482			1,490			803
Accounts payable	1,381			1,376			1,419			1,593
Customer deposits	386			380			400			390
Accrued taxes —
Accrued income taxes	238			13			404			151
Other accrued taxes	558			456			566			487
Accrued interest	270			251			223			295
Accrued vacation pay	213			217			223			223
Accrued compensation	423			303			462			576
Other regulatory liabilities, current	84			92
Mirror CWIP							369			271
Other current liabilities	353			347			820			570
Total current liabilities	6,890			5,536			9,689			8,967
Long-term Debt	21,699			21,344			22,326			20,841
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,817			10,563			11,990			11,568
Deferred credits related to income taxes	191			202			183			192
Accumulated deferred investment tax credits	1,006			966			1,004			1,208
Employee benefit obligations	1,474			1,461			2,408			2,432
Asset retirement obligations	2,133			2,006			2,952			2,168
Unrecognized tax benefits							369			4
Other cost of removal obligations	1,341			1,270			1,210			1,215
Other regulatory liabilities, deferred	566			475			399			398
Other deferred credits and liabilities	549			584			603			590
Total deferred credits and other liabilities	18,077			17,527			21,118			19,775
Total Liabilities	46,666			44,407			53,133			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 — September 30, 2015: 912 million shares
— December 31, 2014: 909 million shares
Treasury — September 30, 2015: 3.3 million shares
— December 31, 2014: 0.7 million shares
Par value	4,500			4,461			4,558			4,539
Paid-in capital	5,652			5,362			6,150			5,955
Treasury, at cost	(25		)	(250		)	(141		)	(26		)
Retained earnings	9,800			9,510			10,233			9,609
Accumulated other comprehensive loss	(70		)	(75		)	(136		)	(128		)
Total Common Stockholders' Equity	19,857			19,008			20,664			19,949
Preferred and Preference Stock of Subsidiaries	756			756			609			756
Noncontrolling Interest							650			221
Total Stockholders' Equity	20,613			19,764			21,923			20,926
Total Liabilities and Stockholders' Equity	$	67,654		$	64,546		$	75,215		$	70,923

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER ~~2014~~2015 vs. THIRD 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.

Proposed Merger with AGL Resources

On August 23, 2015, Southern Company, AGL Resources, and Merger Sub entered into the Merger Agreement. Under the terms of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned direct subsidiary of Southern Company. Upon the consummation of the Merger, each share of common stock of AGL Resources issued and outstanding immediately prior to the effective time of the Merger (Effective Time), other than shares owned by AGL Resources as treasury stock, shares owned by a subsidiary of AGL Resources, and shares owned by shareholders who have properly exercised and perfected dissenters' rights, will be converted into the right to receive $66 in cash, without interest and less any applicable withholding taxes (Merger Consideration). Other equity-based securities of AGL Resources will be cancelled for cash consideration or converted into new awards from Southern Company as described in the Merger Agreement.

Southern Company intends to initially fund the cash consideration for the Merger using approximately $7.0 billion of debt and $1.0 billion of equity. Southern Company expects to issue approximately $2.0 billion of additional equity through 2019 to offset a portion of the debt issued to fund the cash consideration for the Merger. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available.

Consummation of the Merger is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval of the Merger Agreement by AGL Resources' shareholders, which is scheduled for vote on November 19, 2015, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, (iii) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC, New Jersey Board of Public Utilities, and Virginia State Corporation Commission, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources and any other approval which Southern Company and AGL Resources agree are ~~constructing~~required, (iv) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (v) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement. Southern Company expects to complete the required state regulatory filings in the fourth quarter 2015.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied. Upon termination of the Merger Agreement under certain specified circumstances, AGL Resources will be required to pay Southern Company a termination fee of $201 million or reimburse Southern Company’s expenses up to $5 million (which reimbursement shall reduce on a dollar-for-dollar basis any termination fee subsequently payable by AGL Resources). Southern Company currently expects to complete the transaction in the second half of 2016.

Prior to the Merger, Southern Company and AGL Resources will continue to operate as separate companies. Accordingly, except for specific references to the pending Merger, the descriptions of strategy and outlook and the risks and challenges Southern Company faces, and the discussion and analysis of results of operations and financial condition set forth herein relate solely to Southern Company. See Note (I) to the Condensed Financial Statements and RISK FACTORS in Item 1A herein for additional information regarding the Merger and the various risks related thereto.

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

Construction Program

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.

Key Performance Indicators

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects, and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7 of the Form 10-K. 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 quarter ~~2014~~2015 net income after dividends on preferred and preference stock of subsidiaries was ~~$718~~$959 million ($~~0.80~~1.05 per share) compared to ~~$852~~$718 million ($~~0.97~~0.80 per share) for the third quarter ~~2013.~~2014. The ~~decrease~~increase was primarily related to lower pre-tax charges of $150 million ($93 million after tax) in the third quarter 2015 compared to a pre-tax charge of $418 million ($258 million after tax) in the third quarter 2014 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC and an increase in retail base rates. The increases were partially offset by increases in non-fuel operations and maintenance expenses.

Southern Company's year-to-date 2015 net income after dividends on preferred and preference stock of subsidiaries was $2.1 billion ($2.30 per share) compared to $1.7 billion ($1.88 per share) for the corresponding period in 2014. The increase was primarily the result of ~~a $418~~lower pre-tax charges of $182 million ($112 million after tax) recorded in 2015 compared to pre-tax ~~charge~~charges of $798 million ($~~258~~493 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 to an increase in revenues due to retail base rate increases as well as 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, 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 quarter 2014, retail revenues were $4.6 billion compared to $4.3 billion for the corresponding period in 2013. For year-to-date 2014, retail revenues were $12.2 billion compared to $11.2 billion for the corresponding period in 2013.

~~Details of the changes in retail revenues were as follows:~~

Third
Quarter 2014

Year-to-Date
2014
(in millions) (% change) (in millions) (% change)
Retail – prior year $ 4,319
$ 11,237

Estimated change resulting from –
Rates and pricing 89
2.1
242
2.1
Sales growth 9
0.2
29
0.3
Weather 87
2.0
238
2.1
Fuel and other cost recovery 54
1.2
440
3.9
Retail – current year $ 4,558
5.5 % $ 12,186
8.4 %

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2014 when compared to the corresponding periods in 2013 primarily due to retail rate increases at all of the traditional operating companies. The increases in revenues at Georgia Power were primarily due to base tariff increases effective January 1, 2014, as approved by the Georgia PSC in 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 commercial and industrial customers. Also contributing to the increases were increased revenues at Alabama Power associated with Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets 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~~ – ~~Georgia Power~~ – ~~Rate Plans," "Retail Regulatory Matters – Alabama Power~~ – ~~Rate CNP," and "Retail Regulatory Matters~~ – Gulf Power – Retail Base Rate Case" 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 quarter and year-to-date 2014 when compared to the corresponding periods in 2013. Industrial KWH energy sales increased 4.8% in the third quarter and 3.6% for year-to-date 2014 primarily due to increased sales in the primary metals, chemicals, paper, non-manufacturing, transportation, and stone, clay, and glass sectors. Weather-adjusted commercial KWH energy sales decreased 1.1% in the third quarter and 0.5% for year-to-date 2014 primarily due to decreased customer usage, partially offset by

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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 residential KWH sales remained relatively flat~~IGCC, as well as an increase in retail base rates. The increases were partially offset by increases in non-fuel operations and maintenance expenses.

Retail Revenues

In the third quarter 2015, retail revenues were $4.7 billion compared to $4.6 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $12.0 billion compared to $12.2 billion for the corresponding period in 2014.

Details of the changes in retail revenues were as follows:



	Third Quarter 2015					Year-to-Date 2015
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	4,558				$	12,186
Estimated change resulting from –
Rates and pricing	130			2.9		237			1.9
Sales growth	11			0.2		52			0.4
Weather	50			1.1		59			0.5
Fuel and other cost recovery	(48		)	(1.1	)	(576		)	(4.7	)
Retail – current year	$	4,701		3.1	%	$	11,958		(1.9	)%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2015 when compared to the corresponding periods in 2014 primarily due to increased revenues at Alabama Power associated with an increase in rates under rate stabilization and equalization (Rate RSE) and at Georgia Power related to base tariff increases approved under the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, all effective January 1, 2015, as well as higher contributions from variable demand-driven pricing from commercial and industrial customers. The year-to-date 2015 increase was partially offset by 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 at Georgia Power. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate RSE" and "Retail Regulatory Matters – Georgia Power – Rate Plans" 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 quarter 2015 when compared to the corresponding period in 2014. Weather-adjusted commercial KWH sales increased 1.0% in the third quarter 2015 primarily due to customer growth and increased customer usage. Weather-adjusted residential KWH sales increased 0.1% in the third quarter 2015 due to customer growth, partially offset by decreased customer usage. Industrial KWH sales decreased 0.6% in the third quarter 2015 primarily due to decreased sales in the chemicals, paper, primary metals, and non-manufacturing sectors, partially offset by increased sales in the transportation, stone, clay, and glass, lumber, and pipeline sectors. A strong dollar, low oil prices, and weak global growth conditions have constrained growth in the industrial sector.

Revenues attributable to changes in sales increased for year-to-date ~~2014~~2015 when compared to the corresponding period in 2014. Weather-adjusted commercial KWH sales increased 0.8% for year-to-date 2015 primarily due to customer growth and increased customer usage. Weather-adjusted residential KWH sales increased 0.5% for year-to-date 2015 as a result of customer growth, partially offset by decreased customer usage. ~~Household income, one~~Industrial KWH sales increased 0.5% for year-to-date 2015 primarily due to increased sales in the transportation, stone, clay, and glass,

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

pipeline, lumber, and petroleum sectors, partially offset by decreased sales in the primary ~~drivers~~metals, chemicals, and paper sectors.

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 third quarter and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without this adjustment, third quarter 2015 weather-adjusted residential ~~customer usage, has been flat~~sales increased 0.1%, weather-adjusted commercial sales increased 1.2%, and industrial KWH sales decreased 0.6% as compared to the corresponding period in 2014. Also, without this adjustment, year-to-date 2015 weather-adjusted residential sales increased 0.4%, weather-adjusted commercial sales increased 0.7%, and industrial KWH sales increased 0.4% as compared to the corresponding period in 2014.

Fuel and other cost recovery revenues ~~increased $54~~decreased $48 million and $576 million in the third 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 quarter ~~2014,~~2015, wholesale revenues were ~~$600~~$520 million compared to ~~$520~~$600 million for the corresponding period in ~~2013 primarily~~2014 related to ~~an $82~~a $52 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 $28 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~~$1.4 billion compared to ~~$1.4~~$1.7 billion for the corresponding period in ~~2013, reflecting~~2014 related to a ~~$303~~$214 million ~~increase~~decrease in energy revenues and a ~~$10~~$70 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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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			Third Quarter 2015 vs. Third 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	$	(136	)	(8.2)	$	(833	)	(17.5)
Purchased power	49		33.8	147		40.1	(1		)	(0.5)	(7		)	(1.4)
Total fuel and purchased power expenses	$	125		$	696		$	(137	)		$	(840	)

In the third quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$1.9~~$1.7 billion compared to ~~$1.7~~$1.9 billion for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily the result of a $139 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 natural gas ~~prices. These increases were partially offset by~~prices and a ~~$41~~$26 million decrease in the volume of KWHs generated, partially offset by a $28 million increase in the volume of KWHs purchased.

For year-to-date 2015, total fuel and purchased aspower expenses were $4.4 billion compared to $5.3 billion for the ~~marginal~~corresponding period in 2014. The decrease was primarily the result of a $918 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices and a $22 million decrease in the ~~Southern Company system's generation available was lower than~~volume of KWHs generated, partially offset by a $100 million increase in the ~~market cost~~volume of ~~available energy.~~KWHs purchased.

Fuel and purchased power energy transactions at the traditional operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – ~~"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:



	Third Quarter 2015	Third Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (billions of KWHs)	53	54	146	147
Total purchased power (billions of KWHs)	4	3	10	9
Sources of generation (percent) —
Coal	40	44	37	45
Nuclear	15	15	16	16
Gas	43	40	44	36
Hydro	1	1	2	3
Renewables	1	—	1	—
Cost of fuel, generated (cents per net KWH) —
Coal	3.86	3.63	3.65	3.87
Nuclear	0.84	0.84	0.78	0.87
Gas	2.71	3.42	2.72	3.77
Average cost of fuel, generated (cents per net KWH)	2.90	3.13	2.78	3.34
Average cost of purchased power (cents per net KWH)^(*)	5.95	6.77	6.13	7.60


(*)	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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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 quarter ~~2014,~~2015, fuel expense was ~~$1.7~~$1.5 billion compared to ~~$1.6~~$1.7 billion for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~68.3%~~20.8% decrease in the average cost of natural gas per KWH generated and a 9.4% decrease in the volume of KWHs generated by ~~hydro facilities resulting from less rainfall and~~coal, partially offset by a ~~9.9%~~7.8% increase in the volume of KWHs generated by ~~fossil fuel, partially offset by~~natural gas and a ~~10.6% decrease~~6.3% increase in the average cost of coal per KWH generated.

For year-to-date ~~2014,~~2015, fuel expense was ~~$4.8~~$3.9 billion compared to ~~$4.2~~$4.8 billion for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~21.6% increase in the volume of KWHs generated by coal, a 14.2% increase~~27.9% decrease in the average cost of natural gas per KWH generated, ~~and~~ a ~~31.5%~~17.0% decrease in the volume of KWHs generated by ~~hydro facilities resulting from less rainfall.~~coal, and a 5.7% decrease in the average cost of coal per KWH generated, partially offset by a 22.5% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the third quarter ~~2014,~~2015, purchased power expense was ~~$194~~$193 million compared to ~~$145~~$194 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~19.6% increase~~12.1% decrease in the average cost per KWH purchased primarily as a result of ~~higher~~lower natural gas prices, ~~and~~partially offset by an ~~8.3%~~11.3% increase in the volume of KWHs ~~purchased primarily as a result of increased demand from warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.~~purchased.

For year-to-date ~~2014,~~2015, purchased power expense was ~~$514~~$507 million compared to ~~$367~~$514 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~45.6% increase~~19.3% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by ~~an 8.3% decrease~~a 15.2% 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.

Other Operations and Maintenance Expenses

In the third quarter 2015, other operations and maintenance expenses were $1.1 billion compared to $1.0 billion for the corresponding period in 2014. The increase was primarily due to a $31 million increase in employee compensation and benefits including pension costs, a $26 million increase in generation expenses primarily related to non-outage operations and maintenance, $11 million related to AGL Resources acquisition costs, and a $5 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, partially offset by a $19 million decrease in transmission and distribution costs primarily related to overhead line maintenance and an $11 million decrease in scheduled outage and maintenance costs at generation facilities. In addition, in the third quarter 2014, Alabama Power deferred approximately $16 million of certain non-nuclear outage expenditures under an accounting order.

For year-to-date 2015, other operations and maintenance expenses were $3.3 billion compared to $3.0 billion for the corresponding period in 2014. The increase was primarily due to an $88 million increase in employee compensation and benefits including pension costs, a $69 million increase in generation expenses primarily related to non-outage operations and maintenance, a $26 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, a $19 million increase in scheduled outage and maintenance costs at generation facilities, and $11 million related to AGL Resources acquisition costs, partially offset by a $16 million decrease in transmission and distribution costs primarily related to overhead line maintenance. In addition, in the first nine months of 2014, Alabama Power deferred approximately $57 million of certain non-nuclear outage expenditures under an accounting order.

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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 quarter 2014, other operations and maintenance expenses were $1.0 billion compared to $928 million for the corresponding period in 2013. The increase was primarily due to a $30 million increase in transmission and distribution costs primarily related to overhead line maintenance, a $29 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 partially offset by a $16 million deferral of certain non-nuclear outage expenditures under an accounting order at Alabama Power.

For year-to-date 2014, other operations and maintenance expenses were $3.0 billion compared to $2.8 billion for the corresponding period in 2013. The increase was primarily due to an $80 million increase in scheduled outage and maintenance costs at generation facilities, 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 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs, and a $7 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.

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,~~2015, depreciation and amortization was ~~$514~~$528 million compared to ~~$480~~$514 million for the corresponding period in ~~2013. For year-to-date 2014, depreciation and amortization~~2014. The increase was ~~$1.5 billion compared to $1.4 billion for the corresponding period in 2013. The increases were~~ primarily due to ana $27 million increase inrelated to additional plant in service at the traditional operating companies and Southern Power ~~related to~~and a $9 million increase in amortization of regulatory assets associated with the ~~additions of solar facilities in 2013 and 2014 and additional component depreciation~~Kemper IGCC at ~~Southern~~Mississippi Power primarily as a result of ~~production being greater during~~interim rates that became effective with the ~~summer months, as well as the completion of amortization of a regulatory liability related to state income tax credits~~first billing cycle 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.~~September (on August 19). These increases were partially offset by a $23 million decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015.

For year-to-date 2015, depreciation and amortization was flat compared to the corresponding period in 2014

primarily due to a $74 million increase related to additional plant in service at ~~Georgia~~the traditional operating companies and Southern Power and a $10 million increase in amortization of regulatory assets associated with the Kemper IGCC at Mississippi Power primarily as a result of interim rates that became effective with the first billing cycle in September (on August 19). These increases were offset by a $72 million decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015 and a $15 million reduction in depreciation at Gulf Power, as ~~authorized in~~approved by the ~~2013 ARP.~~Florida PSC. See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate CNP"~~Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" in Item 78 of the Form 10-K ~~for additional information regarding Alabama Power's revision to Rate CNP Environmental. Also see~~and Note ~~(A)~~(B) to the Condensed Financial Statements under ~~"Depreciation"~~"Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" herein for additional ~~information related~~information.

Also see Note (B) to ~~component depreciation at Southern Power.~~

~~Table of Contents~~

~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~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)
$15 6.2 $41 5.8

In the ~~third quarter 2014, taxes other than income taxes were $258 million compared to $243 million~~Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for the corresponding period in 2013. For year-to-date 2014, taxes other than income taxes were $751 million compared to $710 million for the corresponding period in 2013. The increases were primarily the result of increases of $7 million and $29 million in municipal franchise fees related 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.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 quarter ~~2014~~2015 and ~~2013,~~2014, estimated probable losses on the Kemper IGCC of ~~$418~~$150 million and ~~$150~~$418 million, respectively, were recorded at Southern Company. For year-to-date ~~2014~~2015 and ~~2013,~~2014, estimated probable losses on the Kemper IGCC of ~~$798~~$182 million and ~~$1.1 billion,~~$798 million, respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE 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 quarter 2014, AFUDC equity was $63 million compared to $53 million for the corresponding period in 2013. The increase was primarily related to additional capital expenditures at Alabama Power.

For year-to-date 2014, AFUDC equity was $182 million compared to $139 million for the corresponding period in 2013. The increase was primarily due to an increase in CWIP related to Mississippi Power's Kemper IGCC and additional capital expenditures at Alabama Power. 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

For year-to-date 2015, AFUDC equity was $163 million compared to $182 million for the corresponding period in 2014. The decrease was primarily due to Mississippi Power placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014, partially offset by environmental and transmission projects under construction by 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.

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 quarter ~~2014,~~2015, interest expense, net of amounts capitalized was ~~$207~~$218 million compared to ~~$202~~$207 million in the corresponding period in ~~2013.~~2014. The increase was primarily due to ~~a $17 million~~an increase ~~related to a higher amount of~~in outstanding long-term ~~debt, partially offset by a $12 million decrease related to the refinancing of long-term debt at lower rates.~~debt.

For year-to-date ~~2014,~~2015, interest expense, net of amounts capitalized was ~~$623~~$612 million compared to ~~$628~~$623 million in the corresponding period in ~~2013.~~2014. The decrease was primarily due to a ~~$30~~$50 million decrease related to the ~~refinancing~~termination of ~~long-term debt~~the asset purchase agreement (APA) between Mississippi Power and SMEPA which also required the return of SMEPA's deposits at a lower ~~rates and a $13 million increase in capitalized~~rate of interest than accrued, partially offset by ~~a $34 million~~an increase ~~related to a higher amount of~~in 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.debt. 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

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,~~In the third quarter 2015, other income (expense), net was ~~$(20)~~$(21) million compared to ~~$(31)~~$(7) million for the corresponding period in ~~2013.~~2014. The ~~decrease in expense~~change was primarily due to a ~~$26 million charge related to the restructuring~~decrease in sales of ~~a leveraged lease investment~~non-utility property in ~~the first quarter 2013, partially offset by a $7 million charge related to a settlement with the Sierra Club~~2015 at ~~Mississippi Power in 2014. See Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.~~Alabama Power.

~~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, other income ~~taxes were $392~~(expense), net was $(41) million compared to ~~$468~~$(20) million for the corresponding period in ~~2013.~~2014. The ~~decrease~~change was primarily due to ~~higher~~an increase in donations and a decrease in sales of non-utility property in 2015 at Alabama Power.

Income Taxes

In the third quarter 2015, income taxes were $500 million compared to $392 million for the corresponding period in 2014. The increase primarily reflects a reduction in tax benefits ~~in 2014~~ related to the estimated probable losses ~~recorded~~ on Mississippi Power's construction of the Kemper IGCC ~~partially offset by~~recorded in 2014 and higher pre-tax earnings.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date ~~2014,~~2015, income taxes were ~~$889 million~~$1.1 billion compared to ~~$657~~$889 million for the corresponding period in ~~2013.~~2014. The increase ~~was~~ primarily ~~due to higher pre-tax earnings and lower~~reflects a reduction in tax benefits ~~in 2014~~ related to the estimated probable losses ~~recorded~~ on Mississippi Power's construction of the Kemper ~~IGCC.~~IGCC recorded in 2014 and beneficial changes that impacted 2014 state income taxes, partially offset by state income tax benefits realized in 2015 and increased federal income tax benefits related to ITCs on Southern Power solar projects in 2015.

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

FUTURE EARNINGS POTENTIAL

~~Table of Contents~~

~~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 and other 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 regulatory matters, creditworthiness of customers, total generating capacity available and related costs, future acquisitions and 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~~Demand for electricity for the traditional operating companies and Southern Power ~~as the~~is partially driven by economic growth. The pace of ~~the~~ economic ~~recovery remains uncertain. The timing and extent of the economic recovery will impact~~ growth and electricity demand may be affected by changes in regional and global economic conditions, which 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 August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the joint stipulation among Alabama Power, the EPA, and the U.S. Department of Justice modifying the 2006 consent decree to resolve all remaining claims for relief alleged in the case. Under the modified consent decree, Alabama Power will, without admitting liability, operate certain units subject to emission rates and an annual emissions cap; use only natural gas at certain other units, including a unit co-owned by Mississippi Power; retire certain units at

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

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, the Cross State Air Pollution Rule (CSAPR), and the ~~EPA's proposed rules~~eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.

On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, Mississippi, North Carolina, and 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~~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 and is dependent on~~time.

On July 28, 2015, the ~~outcome~~U.S. Court 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~~Appeals for the ~~SSM rule. The EPA previously entered into~~District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a ~~revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require~~number of states, ~~subject to the rule (including~~including Alabama, Florida, Georgia, ~~Mississippi,~~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.

On October 26, 2015, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. The ultimate ~~outcome~~impact of ~~these matters~~this matter will depend on any legal challenges and implementation of the final rule 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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.

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 as proposed could have significant impacts on economic development projects which could affect customer demand growth. The ultimate 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.

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

~~Global Climate Issues~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern 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 CO~~₂ ~~emissions from existing 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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of transmission and distribution lines. The rule became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the final rule will depend on the outcome of this and other pending 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.

On November 3, 2015, the EPA published final revisions to technology-based limits for certain wastestreams from steam electric power plants. These revisions impose stringent steam effluent guidelines and technology requirements for wastewater discharges at affected units. Compliance with these revisions could result in significant additional capital expenditures and could affect future unit retirement and replacement decisions. The ultimate impact of these revisions will depend on any legal challenges and implementation of the final revisions 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 Southern Company 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, which became effective on October 19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ash ponds pursuant to the CCR Rule, during the second quarter 2015, Southern Company recorded incremental asset retirement obligations (ARO) of approximately $700 million related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional operating companies expect to continue to periodically update these estimates. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. See Note (A) to the Condensed Financial Statements herein for additional information regarding Southern Company's AROs as of September 30, 2015.

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 proposed regulation of CO₂ from fossil-fuel-fired electric generating units.

On October 23, 2015, two final actions by the EPA that would limit CO₂ emissions from fossil fuel-fired electric generating units were published in the Federal Register. One of the final actions contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final action 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, a proposed federal plan and proposed model rule were published 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, including legal challenges filed by the traditional operating companies; individual state implementation of the EPA's final ~~guidelines; individual state implementation of these~~ guidelines, including the potential that state ~~implementation~~ plans impose different

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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.

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

Construction Program

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 Mississippi Power's 582-MW Kemper IGCC. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements herein.

Key Performance Indicators

RESULTS OF OPERATIONS

Net Income

Southern Company's third quarter 2015 net income after dividends on preferred and preference stock of subsidiaries was $959 million ($1.05 per share) compared to $718 million ($0.80 per share) for the third quarter 2014. The increase was primarily related to lower pre-tax charges of $150 million ($93 million after tax) in the third quarter 2015 compared to a pre-tax charge of $418 million ($258 million after tax) in the third quarter 2014 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC and an increase in retail base rates. The increases were partially offset by increases in non-fuel operations and maintenance expenses.

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IGCC, as well as an increase in retail base rates. The increases were partially offset by increases in non-fuel operations and maintenance expenses.

Retail Revenues

Details of the changes in retail revenues were as follows:



	Third Quarter 2015					Year-to-Date 2015
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	4,558				$	12,186
Estimated change resulting from –
Rates and pricing	130			2.9		237			1.9
Sales growth	11			0.2		52			0.4
Weather	50			1.1		59			0.5
Fuel and other cost recovery	(48		)	(1.1	)	(576		)	(4.7	)
Retail – current year	$	4,701		3.1	%	$	11,958		(1.9	)%

Revenues attributable to changes in sales increased for year-to-date 2015 when compared to the corresponding period in 2014. Weather-adjusted commercial KWH sales increased 0.8% for year-to-date 2015 primarily due to customer growth and increased customer usage. Weather-adjusted residential KWH sales increased 0.5% for year-to-date 2015 as a result of customer growth, partially offset by decreased customer usage. Industrial KWH sales increased 0.5% for year-to-date 2015 primarily due to increased sales in the transportation, stone, clay, and glass,

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pipeline, lumber, and petroleum sectors, partially offset by decreased sales in the primary metals, chemicals, and paper sectors.

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 third quarter and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without this adjustment, third quarter 2015 weather-adjusted residential sales increased 0.1%, weather-adjusted commercial sales increased 1.2%, and industrial KWH sales decreased 0.6% as compared to the corresponding period in 2014. Also, without this adjustment, year-to-date 2015 weather-adjusted residential sales increased 0.4%, weather-adjusted commercial sales increased 0.7%, and industrial KWH sales increased 0.4% as compared to the corresponding period in 2014.

Fuel ~~Cost Recovery~~and other cost recovery revenues decreased $48 million and $576 million in the third quarter and year-to-date 2015, respectively, when compared to the corresponding periods in 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 ~~each~~may also have ~~established~~one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPAs.

Wholesale Revenues

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 ~~cost recovery rates approved~~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 ~~their respective state PSCs. Fuel cost recovery revenues~~fuel prices are ~~adjusted for differences~~accompanied by an increase or decrease in ~~actual recoverable~~ fuel costs and ~~amounts billed in current regulated rates. Accordingly, changes in the billing factor will~~do not have a significant ~~effect~~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's~~Company system's variable cost to produce the energy.

In the third quarter 2015, wholesale revenues ~~or net income, but will affect cash flow.~~were $520 million compared to $600 million for the corresponding period in 2014 related to a $52 million decrease in energy revenues and a $28 million decrease in capacity revenues. For year-to-date 2015, wholesale revenues were $1.4 billion compared to $1.7 billion for the corresponding period in 2014 related to a $214 million decrease in energy revenues and a $70 million decrease in capacity revenues. The decreases in energy revenues were primarily related to lower fuel costs, partially offset by increases in energy revenues from new solar PPAs at Southern Power. The decreases in capacity revenues were primarily due to the expiration of wholesale contracts in December 2014 at Georgia Power, unit retirements at Georgia Power, and PPA expirations at Southern Power.

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Fuel and Purchased Power Expenses



	Third Quarter 2015 vs. Third Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(136	)	(8.2)	$	(833	)	(17.5)
Purchased power	(1		)	(0.5)	(7		)	(1.4)
Total fuel and purchased power expenses	$	(137	)		$	(840	)

In the third quarter 2015, total fuel and purchased power expenses were $1.7 billion compared to $1.9 billion for the corresponding period in 2014. The decrease was primarily the result of a $139 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices and a $26 million decrease in the volume of KWHs generated, partially offset by a $28 million increase in the volume of KWHs purchased.

For year-to-date 2015, total fuel and purchased power expenses were $4.4 billion compared to $5.3 billion for the corresponding period in 2014. The decrease was primarily the result of a $918 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices and a $22 million decrease in the volume of KWHs generated, partially offset by a $100 million increase in the volume of KWHs purchased.

Fuel and purchased power energy transactions at the traditional operating companies ~~continuously monitor their~~are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under ~~or over recovered~~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:



	Third Quarter 2015	Third Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (billions of KWHs)	53	54	146	147
Total purchased power (billions of KWHs)	4	3	10	9
Sources of generation (percent) —
Coal	40	44	37	45
Nuclear	15	15	16	16
Gas	43	40	44	36
Hydro	1	1	2	3
Renewables	1	—	1	—
Cost of fuel, generated (cents per net KWH) —
Coal	3.86	3.63	3.65	3.87
Nuclear	0.84	0.84	0.78	0.87
Gas	2.71	3.42	2.72	3.77
Average cost of fuel, generated (cents per net KWH)	2.90	3.13	2.78	3.34
Average cost of purchased power (cents per net KWH)^(*)	5.95	6.77	6.13	7.60


(*)	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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Fuel

In the third quarter 2015, fuel expense was $1.5 billion compared to $1.7 billion for the corresponding period in 2014. The decrease was primarily due to a 20.8% decrease in the average cost ~~balances. At September 30, 2014, Georgia~~of natural gas per KWH generated and a 9.4% decrease in the volume of KWHs generated by coal, partially offset by a 7.8% increase in the volume of KWHs generated by natural gas and a 6.3% increase in the average cost of coal per KWH generated.

For year-to-date 2015, fuel expense was $3.9 billion compared to $4.8 billion for the corresponding period in 2014. The decrease was primarily due to a 27.9% decrease in the average cost of natural gas per KWH generated, a 17.0% decrease in the volume of KWHs generated by coal, and a 5.7% decrease in the average cost of coal per KWH generated, partially offset by a 22.5% increase in the volume of KWHs generated by natural gas.

Purchased Power ~~Gulf Power, and Mississippi Power had total under recovered fuel costs included~~

In the third quarter 2015, purchased power expense was $193 million compared to $194 million for the corresponding period in 2014. The decrease was primarily due to a 12.1% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by an 11.3% increase in the volume of KWHs purchased.

For year-to-date 2015, purchased power expense was $507 million compared to $514 million for the corresponding period in 2014. The decrease was primarily due to a 19.3% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by a 15.2% increase in the volume of KWHs purchased.

Energy purchases will vary depending on demand for energy within the Southern ~~Company's Condensed Balance Sheet herein~~Company system's service territory, the market prices 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 balance at Alabama Power included on Southern Company's Condensed Balance Sheet herein was approximately $44 million at September 30, 2014wholesale energy as compared to the ~~total over recovered fuel balance~~cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.

Other Operations and Maintenance Expenses

In the third quarter 2015, other operations and maintenance expenses were $1.1 billion compared to $1.0 billion for the corresponding period in 2014. The increase was primarily due to a $31 million increase in employee compensation and benefits including pension costs, a $26 million increase in generation expenses primarily related to non-outage operations and maintenance, $11 million related to AGL Resources acquisition costs, and a $5 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, partially offset by a $19 million decrease in transmission and distribution costs primarily related to overhead line maintenance and an $11 million decrease in scheduled outage and maintenance costs at generation facilities. In addition, in the third quarter 2014, Alabama Power ~~Georgia~~deferred approximately $16 million of certain non-nuclear outage expenditures under an accounting order.

For year-to-date 2015, other operations and maintenance expenses were $3.3 billion compared to $3.0 billion for the corresponding period in 2014. The increase was primarily due to an $88 million increase in employee compensation and benefits including pension costs, a $69 million increase in generation expenses primarily related to non-outage operations and maintenance, a $26 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, a $19 million increase in scheduled outage and maintenance costs at generation facilities, and $11 million related to AGL Resources acquisition costs, partially offset by a $16 million decrease in transmission and distribution costs primarily related to overhead line maintenance. In addition, in the first nine months of 2014, Alabama Power ~~and Mississippi Power at December 31, 2013~~deferred approximately $57 million of ~~approximately $115 million.~~certain non-nuclear outage expenditures under an accounting order.

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See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – ~~Retail Energy Cost Recovery" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery"~~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

In the third quarter 2015, depreciation and amortization was $528 million compared to $514 million for the corresponding period in 2014. The increase was primarily due to a $27 million increase related to additional plant in service at the traditional operating companies and Southern Power and a $9 million increase in amortization of regulatory assets associated with the Kemper IGCC at Mississippi Power primarily as a result of interim rates that became effective with the first billing cycle in September (on August 19). These increases were partially offset by a $23 million decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015.

For year-to-date 2015, depreciation and amortization was flat compared to the corresponding period in 2014

primarily due to a $74 million increase related to additional plant in service at the traditional operating companies and Southern Power and a $10 million increase in amortization of regulatory assets associated with the Kemper IGCC at Mississippi Power primarily as a result of interim rates that became effective with the first billing cycle in September (on August 19). These increases were offset by a $72 million decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015 and a $15 million reduction in depreciation at Gulf Power, as approved by the Florida PSC. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Gulf Power – 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.

Also see Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Estimated Loss on Kemper IGCC

In the third quarter 2015 and 2014, estimated probable losses on the Kemper IGCC of $150 million and $418 million, respectively, were recorded at Southern Company. For year-to-date 2015 and 2014, estimated probable losses on the Kemper IGCC of $182 million and $798 million, respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE 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 – 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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Allowance for Equity Funds Used During Construction

Interest Expense, Net of Amounts Capitalized

In the third quarter 2015, interest expense, net of amounts capitalized was $218 million compared to $207 million in the corresponding period in 2014. The increase was primarily due to an increase in outstanding long-term debt.

For year-to-date 2015, interest expense, net of amounts capitalized was $612 million compared to $623 million in the corresponding period in 2014. The decrease was primarily due to a $50 million decrease related to the termination of the asset purchase agreement (APA) between Mississippi Power and SMEPA which also 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. 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

N/M – Not meaningful

In the third quarter 2015, other income (expense), net was $(21) million compared to $(7) million for the corresponding period in 2014. The change was primarily due to a decrease in sales of non-utility property in 2015 at Alabama ~~Power~~Power.

~~Environmental Accounting Order~~For year-to-date 2015, other income (expense), net was $(41) million compared to $(20) million for the corresponding period in 2014. The change was primarily due to an increase in donations and a decrease in sales of non-utility property in 2015 at Alabama Power.

Income Taxes

In the third quarter 2015, income taxes were $500 million compared to $392 million for the corresponding period in 2014. The increase primarily reflects a reduction in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recorded in 2014 and higher pre-tax earnings.

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For year-to-date 2015, income taxes were $1.1 billion compared to $889 million for the corresponding period in 2014. The increase primarily reflects a reduction in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recorded in 2014 and beneficial changes that impacted 2014 state income taxes, partially offset by state income tax benefits realized in 2015 and increased federal income tax benefits related to ITCs on Southern Power solar projects 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 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 completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Other major factors include the profitability of the competitive wholesale business and successfully expanding investments in renewable and other energy projects. Future earnings for the electricity business in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale business also depends on numerous factors including regulatory matters, creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, including the impact of ITCs, and the successful remarketing of capacity as current contracts expire. Demand for electricity for the traditional operating companies and Southern Power is partially driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. 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

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Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

Environmental Statutes and ~~Regulations"~~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"~~Order," and – "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 for additional information on planned unit retirements and fuel conversions at Alabama Power, Georgia Power, and 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, the Cross State Air Pollution Rule (CSAPR), and the eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.

On June 12, 2015, the EPA published a final rule requiring affected states (includingAlabama, ~~Power's~~Florida, Georgia, Mississippi, North Carolina, and Texas) to revise or remove state implementation plan ~~for compliance with environmental statutes and regulations.~~

~~As part~~(SIP) provisions regarding excess emissions that occur during periods of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Alabama Power also plans to cease 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, 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 to be effectiveSSM 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 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 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.

On October 26, 2015, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. The ultimate impact of this matter will depend on any legal challenges and implementation of the final rule and cannot be determined at this time.

Water Quality

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Coal Combustion Residuals

On April ~~2016.~~

~~In accordance with an accounting order~~17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the ~~Alabama PSC, Alabama Power will transfer~~Federal Register, which became effective on October 19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ash ponds pursuant to the ~~unrecovered plant~~CCR Rule, during the second quarter 2015, Southern Company recorded incremental asset ~~balances~~retirement obligations (ARO) of approximately $700 million related to ~~a regulatory asset~~the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at ~~their respective retirement dates. The regulatory asset will be amortized over~~each site, and the ~~remaining useful lives, as established~~determination of timing, including the potential for closing ash ponds prior to the ~~decision~~end of their currently anticipated useful life, the traditional operating companies expect to continue to periodically update these estimates. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. See Note (A) to the Condensed Financial Statements herein for ~~retirement. As a result, these decisions will not have a significant impact on~~additional information regarding Southern Company's AROs as of September 30, 2015.

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 proposed regulation of CO₂ from fossil-fuel-fired electric generating units.

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 ~~statements.~~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 final rules on the Southern Company system 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, including legal challenges filed by the traditional operating companies; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different

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~~Nuclear Waste Fund Accounting Order~~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.

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters"~~FERC Matters

~~On August 5, 2014, the Alabama PSC~~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 ~~the continued recovery from customers of amounts associated~~rehearing on May 27, 2015 and on June 26, 2015 filed their response 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 customers subject to the approval of the Alabama PSC.FERC. 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 the financial statements of Southern Company under "RetailRetail 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 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.~~

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information on Georgia Power's NCCR tariff. On October 31, 2014, Georgia Power filed to increase the NCCR tariff by approximately $27 million effective January

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~~1, 2015 pending Georgia PSC approval. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters~~ – ~~Georgia Power~~ – ~~Nuclear Construction" herein for additional information.~~

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

~~Renewables Development~~

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

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

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

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

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

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

~~Integrated Resource Plan~~

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

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

~~Storm Damage Recovery~~

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

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage

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

~~Income Tax Matters~~

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

~~Bonus Depreciation~~

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

~~Investment Tax Credits~~

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

Key Performance Indicators

RESULTS OF OPERATIONS

Net Income

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IGCC, as well as an increase in retail base rates. The increases were partially offset by increases in non-fuel operations and maintenance expenses.

Retail Revenues

Details of the changes in retail revenues were as follows:



	Third Quarter 2015					Year-to-Date 2015
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	4,558				$	12,186
Estimated change resulting from –
Rates and pricing	130			2.9		237			1.9
Sales growth	11			0.2		52			0.4
Weather	50			1.1		59			0.5
Fuel and other cost recovery	(48		)	(1.1	)	(576		)	(4.7	)
Retail – current year	$	4,701		3.1	%	$	11,958		(1.9	)%

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pipeline, lumber, and petroleum sectors, partially offset by decreased sales in the primary metals, chemicals, and paper sectors.

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 third quarter and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without this adjustment, third quarter 2015 weather-adjusted residential sales increased 0.1%, weather-adjusted commercial sales increased 1.2%, and industrial KWH sales decreased 0.6% as compared to the corresponding period in 2014. Also, without this adjustment, year-to-date 2015 weather-adjusted residential sales increased 0.4%, weather-adjusted commercial sales increased 0.7%, and industrial KWH sales increased 0.4% as compared to the corresponding period in 2014.

Fuel and other cost recovery revenues decreased $48 million and $576 million in the third quarter and year-to-date 2015, respectively, when compared to the corresponding periods in 2014 primarily due to a decrease in fuel prices.

Wholesale Revenues

In the third quarter 2015, wholesale revenues were $520 million compared to $600 million for the corresponding period in 2014 related to a $52 million decrease in energy revenues and a $28 million decrease in capacity revenues. For year-to-date 2015, wholesale revenues were $1.4 billion compared to $1.7 billion for the corresponding period in 2014 related to a $214 million decrease in energy revenues and a $70 million decrease in capacity revenues. The decreases in energy revenues were primarily related to lower fuel costs, partially offset by increases in energy revenues from new solar PPAs at Southern Power. The decreases in capacity revenues were primarily due to the expiration of wholesale contracts in December 2014 at Georgia Power, unit retirements at Georgia Power, and PPA expirations at Southern Power.

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Fuel and Purchased Power Expenses



	Third Quarter 2015 vs. Third Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(136	)	(8.2)	$	(833	)	(17.5)
Purchased power	(1		)	(0.5)	(7		)	(1.4)
Total fuel and purchased power expenses	$	(137	)		$	(840	)

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

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



	Third Quarter 2015	Third Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (billions of KWHs)	53	54	146	147
Total purchased power (billions of KWHs)	4	3	10	9
Sources of generation (percent) —
Coal	40	44	37	45
Nuclear	15	15	16	16
Gas	43	40	44	36
Hydro	1	1	2	3
Renewables	1	—	1	—
Cost of fuel, generated (cents per net KWH) —
Coal	3.86	3.63	3.65	3.87
Nuclear	0.84	0.84	0.78	0.87
Gas	2.71	3.42	2.72	3.77
Average cost of fuel, generated (cents per net KWH)	2.90	3.13	2.78	3.34
Average cost of purchased power (cents per net KWH)^(*)	5.95	6.77	6.13	7.60


(*)	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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Fuel

In the third quarter 2015, fuel expense was $1.5 billion compared to $1.7 billion for the corresponding period in 2014. The decrease was primarily due to a 20.8% decrease in the average cost of natural gas per KWH generated and a 9.4% decrease in the volume of KWHs generated by coal, partially offset by a 7.8% increase in the volume of KWHs generated by natural gas and a 6.3% increase in the average cost of coal per KWH generated.

Purchased Power

Other Operations and Maintenance Expenses

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Depreciation and Amortization

For year-to-date 2015, depreciation and amortization was flat compared to the corresponding period in 2014

Also see Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Estimated Loss on Kemper IGCC

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Allowance for Equity Funds Used During Construction

Interest Expense, Net of Amounts Capitalized

Other Income (Expense), Net

N/M – Not meaningful

For year-to-date 2015, other income (expense), net was $(41) million compared to $(20) million for the corresponding period in 2014. The change was primarily due to an increase in donations and a decrease in sales of non-utility property in 2015 at Alabama Power.

Income Taxes

In the third quarter 2015, income taxes were $500 million compared to $392 million for the corresponding period in 2014. The increase primarily reflects a reduction in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recorded in 2014 and higher pre-tax earnings.

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

FUTURE EARNINGS POTENTIAL

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. 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

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Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

Environmental Statutes and Regulations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations," – "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order," and – "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" 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 for additional information on planned unit retirements and fuel conversions at Alabama Power, Georgia Power, and 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, the Cross State Air Pollution Rule (CSAPR), and the eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.

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

On October 26, 2015, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. The ultimate impact of this matter will depend on any legal challenges and implementation of the final rule and cannot be determined at this time.

Water Quality

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Coal Combustion Residuals

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 proposed regulation of CO₂ from fossil-fuel-fired electric generating units.

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 final rules on the Southern Company system 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, including legal challenges filed by the traditional operating companies; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different

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FERC Matters

The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC 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.

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. On September 18, 2015, Georgia Power filed a rate request with the Georgia PSC to lower total annual billings by approximately $268 million effective January 1, 2016. The Georgia PSC is scheduled to vote on this matter on December 15, 2015. The ultimate outcome of this matter cannot be determined at this time.

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

Alabama Power

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through its Rate RSE, Rate CNP, rate energy cost recovery, and natural disaster reserve rate. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Rate CNP

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.

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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 $50 million of non-environmental compliance costs during the first nine 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.

On August 14, 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-13, allowing 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. The new accounting guidance will have no impact on Southern Company's financial statements.

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. On August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the joint stipulation in the New Source Review (NSR) action. In accordance with the joint stipulation, Alabama Power retired Plant Barry Unit 3 (225 MWs) and it is no longer available for generation. See Note (B) to the Condensed Financial Statements 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, and recovered through Rate CNP. As a result, these decisions will not have a significant impact on Southern Company's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Alabama Power – Rate CNP" herein for additional information.

Renewable Energy

On September 1, 2015, the Alabama PSC approved Alabama Power's petition for a Renewable Generation Certificate. This will allow 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.

Georgia Power

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Construction Program – Nuclear Construction" and "Retail Regulatory Matters – Retail Fuel Cost Recovery" herein for additional information regarding Georgia Power's recent NCCR tariff filing and fuel rate request, respectively. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power" in Item 8 of the Form 10-K for additional information.

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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 request to build, own, and operate an up to 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia by the end of 2016.

Rate Plans

In accordance with the terms of the 2013 ARP, on October 2, 2015, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2016 pending its approval:

increase in traditional base tariffs by approximately $49 million;

increase in the environmental compliance cost recovery tariff by approximately $75 million;

increase in the demand-side management tariffs by approximately $7 million; and

increase in the municipal franchise fee tariff by approximately $13 million.

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

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. On October 13, 2015, Plant Kraft Units 1 through 4 (316 MWs) were retired.

Gulf Power

Renewables

On 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 recovery of Kemper IGCC-related costs with the Mississippi PSC. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates designed to collect approximately $159 million annually. 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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Renewables

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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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 30, ~~2014,~~2015, Southern Company ~~has~~ recorded pre-tax charges totaling ~~$1.98~~$2.23 billion ($~~1.22~~1.4 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 reversed the Mississippi PSC's March 2013 order that authorized Mississippi Power's collection of $156 million annually to be recorded as Mirror CWIP and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts collected. The Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Refunds of $342 million collected by Mississippi Power through July 2015 billings plus associated carrying costs will begin in November 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 $369 million of Mirror CWIP rate collections, including associated carrying costs through September 30, 2015, the termination of the Mirror CWIP rates, and the likely repayment to the IRS of approximately $235 million of unrecognized tax benefits associated with the ITCs that were allocated to the Kemper IGCC under Section 48A (Phase II) of the Internal Revenue Code if the in-service date of the Kemper IGCC extends beyond April 19, 2016 have adversely impacted Mississippi Power's financial condition.

As a result of the Mississippi Supreme Court's decision and these financial impacts, on July 10, 2015, Mississippi Power submitted a filing with the Mississippi PSC that included a request for interim rates, until such time as the Mississippi PSC renders a final decision on permanent 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 (In-Service Asset Proposal). These interim rates are designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of the interim rates that became effective with the first billing cycle in September (on August 19), subject to refund and certain other conditions. In addition, the Mississippi PSC reserved the right to modify or terminate the interim rates based upon a material change in circumstances. The Mississippi PSC is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal. The ultimate outcome of these matters cannot be determined at this time.

Nuclear Construction

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth Vogtle Construction Monitoring (VCM) report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as to include the estimated owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. 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.

On August 28, 2015, Georgia Power filed its thirteenth VCM report with the Georgia PSC covering the period from January 1 through June 30, 2015, which requested approval for an additional $148 million of construction capital costs incurred during that period and reflected estimated financing costs during the construction period to total approximately $2.4 billion.

On October 30, 2015, Georgia Power filed to increase the NCCR tariff by approximately $19 million, effective January 1, 2016, pending Georgia PSC approval.

On October 27, 2015, Westinghouse and Chicago Bridge & Iron Company, N.V. (CB&I) announced an agreement under which Westinghouse or one of its affiliates will acquire CB&I Stone & Webster, Inc. (S&W) (formerly known as Stone & Webster, Inc.) from CB&I, subject to satisfaction of certain conditions to closing. In addition, on October 27, 2015, Westinghouse and the Vogtle Owners entered into a term sheet (Term Sheet) setting forth the terms of a settlement agreement to resolve disputes between the Vogtle Owners and the Contractor under the engineering, procurement, and construction agreement between the Vogtle Owners and the Contractor (Vogtle 3 and 4 Agreement), including the litigation pending in the U.S. District Court for the Southern District of Georgia between the Contractor and the Vogtle Owners (Vogtle Construction Litigation).

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In accordance with the Term Sheet, the Vogtle Owners and the Contractor will enter into mutual releases of all open claims which have been asserted, including any potential extension of such open claims, as well as future claims based on events occurring prior to the effective date of the release that potentially could have been asserted under the original terms of the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation, which will be dismissed with prejudice. In addition, among other items, the Term Sheet provides that the guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement will be revised to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4 and Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. The settlement of the pending disputes between the Vogtle Owners and the Contractor, including the Vogtle Construction Litigation, is subject to consummation of Westinghouse's proposed acquisition of S&W. If this proposed acquisition is not completed, the Vogtle Construction Litigation will continue and the Contractor may from time to time continue to assert that it is entitled to additional payments with respect to its allegations, any of which could be substantial.

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.

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. These tax credits 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. Through September 30, 2015, Southern Company had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $235 million had been utilized. While the in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, but has not made a final determination to that effect. Due to this uncertainty, Southern Company has reflected these tax credits as unrecognized tax benefits and reclassified the Phase II credits to a current liability on its September 30, 2015 balance sheet, with no impact to net income. Repayment to the IRS would occur with the quarterly estimated tax payment following a final determination that the in-service date would occur subsequent to April 19, 2016. Any cash funding requirements necessary for Mississippi Power to make this repayment are expected to be provided by Southern Company. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits – Investment Tax Credits," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

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, 2014, and 2015. 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 $414 million as of September 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"

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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

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~~$150 million ($~~258.1~~93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, ~~$380.0~~$380 million ($~~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~~$2.23 billion ($~~1.22~~1.4 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 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,~~June 30, 2016. Any ~~further~~ extension of the in-service date beyond June 2016 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond June 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $12 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees, a portion of which are being deferred as regulatory assets and are estimated to total approximately $6 million per month.

Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Asset Retirement Obligations

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

The liability for AROs primarily relates to the decommissioning of the nuclear facilities - Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2 - 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.

As a result of the final CCR Rule discussed above, 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

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based on information 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 for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional operating companies expect to continue 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 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. Early adoption is permitted and Southern Company intends to adopt the ASU in the fourth quarter 2015. The ASU is required to be applied retrospectively to all periods presented beginning in the year of adoption. 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 30, ~~2014.~~2015. Through September 30, ~~2014,~~2015, Southern Company has incurred non-recoverable cash expenditures of ~~$1.18~~$1.8 billion and is expected to incur approximately ~~$0.8~~$0.4 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~~$5.1 billion for the first nine months of ~~2014,~~2015, an increase of ~~$276 million~~$0.4 billion 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~~$4.9 billion for the first nine 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 million~~$0.2 billion for the first nine months of ~~2014. This was~~2015 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.

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Significant balance sheet changes for the first nine months of ~~2014~~2015 include an increase of ~~$2.0~~$3.4 billion in total property, plant, and equipment ~~for~~to comply with environmental standards and construction of generation, transmission, and distribution ~~facilities~~facilities; a $0.4 billion increase in income taxes receivable, non-current and a $0.4 billion increase in accumulated deferred income taxes for deductions primarily related to R&E expenditures for the Kemper IGCC; an increase of ~~$755 million~~$0.4 billion in ~~cash and cash equivalents. Other significant changes include~~accounts receivable primarily related to increases in customer billings; a ~~$1.2~~$1.5 billion increase in short-term and long-term debt to fund the ~~Southern Company~~ subsidiaries' continuous construction programs and for other general corporate ~~purposes~~purposes; and ~~an $849 million~~a $0.8 billion increase in ~~total stockholders' equity.~~AROs primarily related to the CCR Rule. 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 quarter ~~2014,~~2015, the market price of Southern Company's common stock was ~~$43.65~~$44.70 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was ~~$22.07~~$22.73 per share, representing a market-to-book ratio of ~~198%~~197%, 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 quarter ~~2014~~2015 was ~~$0.5250~~$0.5425 per share compared to ~~$0.5075~~$0.5250 per share in the third 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~~$3.3 billion will be required through September 30, ~~2015~~2016 to fund maturities 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.~~information. Subsequent to September 30, 2015, Alabama Power repaid at maturity $400 million aggregate principal amount of its Series 2012B 0.550% Senior Notes due October 15, 2015.

The Southern Company system's construction program is currently estimated to be ~~$7.2 billion for 2014, $5.8~~$7.7 billion for 2015, ~~and $4.4~~$5.6 billion for 2016, and $4.3 billion for 2017, which includes expenditures related to construction and start-up of the Kemper IGCC of ~~$1.3 billion for 2014, $551~~$834 million for 2015 and ~~$75~~$281 million for 2016 and ~~expenditures related to~~approximately $2.2 billion for acquisitions and/or construction of new 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.Power generating facilities in 2015.

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 1 to the financial statements of Southern Company under "Acquisitions" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.

In addition to the Merger Consideration to be paid by Southern Company at the Effective Time, in connection with the Merger, Southern Company will also assume AGL Resources' outstanding indebtedness (approximately $4

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billion on June 30, 2015). See OVERVIEW herein for additional information regarding the Merger, including the Merger Consideration.

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.

~~Table of Contents~~

~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~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 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 September 30, 2015, Southern Company's current liabilities ~~frequently exceed~~exceeded current assets by $3.4 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~~including approximately $0.5 billion at Southern Company, ~~system.~~$0.6 billion at Alabama Power, $1.4 billion at Georgia Power, $0.4 billion at Mississippi Power, and $0.4 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 an additional source of long-term borrowed funds.

The financial condition of Mississippi Power and its ability to obtain funds needed for normal business operations and completion of the construction and start-up of the Kemper IGCC were adversely affected by ~~bank~~the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA, the required refund of Mirror CWIP rate collections beginning in early November 2015 of approximately $369 million, including associated carrying costs, the termination of the Mirror CWIP rate, and the likely repayment of unrecognized tax benefits associated with the Phase II tax credits of $235 million. On August

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13, 2015, the Mississippi PSC approved the implementation of interim rates, subject to refund and certain other conditions, and is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal. 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.

At September 30, ~~2014,~~2015, Southern Company and its subsidiaries had approximately ~~$1.4~~$1.1 billion of cash and cash equivalents. Committed credit arrangements with banks at September 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		2020		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(a)	$	—	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	1,000	$	1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	70		158		50		—		1,030		1,308		1,308		58		—		58		170		—		40		—		500		800		1,340		1,339		—		—		—		40
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—		—		—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	20		60		165		30		—		275		275		50		—		50		30		20		225		30		—		—		275		275		50		—		50		195
Mississippi Power(b)	15		120		165		—		—		300		300		25		40		65		70		15		220		—		—		—		235		210		30		30		60		175
Southern Power(c)	—		—		—		—		500		500		499		—		—		—		—		—		—		—		—		600		600		567		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		50		—		70		—		—		—		70		70		—		—		—		70
Total	$	105	$	408	$	530	$	30	$	4,130	$	5,203	$	5,188	$	153	$	40	$	193	$	320	$	35	$	555	$	30	$	1,500	$	4,400	$	6,520	$	6,443	$	80	$	30	$	110	$	480


(a)	Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.


(b)	Subsequent to September 30, 2015, a $15 million bank credit arrangement expired pursuant to its terms.

(c)

Excludes the Tranquillity Credit Agreement assumed with the acquisition of Tranquillity on August 28, 2015, which is non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to Tranquillity's solar facility currently under construction in California. See Note (I) to the Condensed Financial Statements herein for additional information regarding Tranquillity.

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.

As reflected in the table above, in August 2015, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended and restated their multi-year credit arrangements, which, among other things, extended the maturity dates from 2018 to 2020. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $1.25 billion from $1.0 billion and to $600 million from $500 million, respectively. Georgia Power increased its borrowing ability by $150 million under its facility maturing in 2020 and terminated its aggregate $150 million facilities maturing in 2016. In September 2015, Southern Company entered into an additional multi-year credit arrangement for $1.0 billion with a maturity date of 2018. Also in September 2015, Alabama Power entered into a new $500 million three-year credit arrangement which replaced a majority of Alabama Power's bi-lateral credit arrangements.

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 30, ~~2014~~2015 was approximately $1.8 billion. In addition, at September 30, ~~2014,~~2015, the traditional operating companies had ~~$423~~approximately $354 million of fixed rate pollution control revenue bonds outstanding that were required to be ~~remarketed~~reoffered within the next 12 ~~months.~~months, of which $120 million were remarketed subsequent to September 30, 2015.

~~Southern Company and its subsidiaries expect to renew their~~Most of these bank credit arrangements ~~as needed, prior~~contain covenants that limit debt levels and contain cross acceleration or cross default provisions to ~~expiration.~~other indebtedness (including guarantee obligations) that are restricted only to the

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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. Such cross acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. Southern Company, the traditional operating companies, and Southern Power 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.

The Bridge Agreement provides for total loan commitments in an aggregate amount of $8.1 billion to fund the payment of the cash consideration payable under the Merger Agreement and other cash payments required in connection with the consummation of the Merger, the Bridge Agreement and the borrowings thereunder, the other financing transactions related to the Merger, and the payment of fees and expenses incurred in connection with the foregoing. If funded, the loan under the Bridge Agreement will mature and be payable in full on the date that is 364 days after the funding of the commitments under the Bridge Agreement (Closing Date).

In connection with the Bridge Agreement, Southern Company will pay a ticking fee for the benefit of the lenders thereto, accruing from November 21, 2015, in an amount equal to 0.125% per annum of the aggregate commitments under the Bridge Agreement, which fee will accrue through the earlier of (i) the date of termination of the commitments and (ii) the Closing Date. If the loan is funded, Southern Company will pay (i) interest at a fluctuating rate per annum equal to, at its election, the base rate or euro-dollar rate plus, in each case, an applicable margin, calculated as provided in the Bridge Agreement and (ii) on each of the dates set forth below, a duration fee equal to the applicable percentage set forth below of the aggregate principal amount of the loan outstanding on such date:



Date	Duration Fee
90 days after the Closing Date	0.50%
180 days after the Closing Date	0.75%
270 days after the Closing Date	1.00%

Additionally, under the terms of the Bridge Agreement, Southern Company is required to pay certain customary fees to the lenders as set forth in related letters. As of September 30, 2015, Southern Company had no outstanding loans under the Bridge Agreement.

Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described ~~above.~~above, excluding the Bridge Agreement. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term 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 September 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 Amount 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	$	990	0.5	%	$	826	0.4	%	$	1,406
Short-term bank debt	—		—	150		0.8%	250		500		1.4	%	543		1.1	%	555
Total	$	361	0.3%	$	998	0.3%			$	1,490	0.8	%	$	1,369	0.8	%


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 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~~Baa2 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, 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 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
At BBB and/or Baa2			$	12
At BBB- and/or Baa3	454		504
Below BBB- and/or Baa3	2,289		2,348

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, ~~any~~a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, ~~particularly~~and would be likely to impact the ~~short-term~~cost at which they do so.

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.

On August 14, 2015, Moody's downgraded the senior unsecured debt ~~market~~rating of Mississippi Power to Baa2 from Baa1. Moody's maintained the negative ratings outlook for Mississippi Power.

On August 17, 2015, S&P downgraded the consolidated long-term issuer rating of Southern Company (including Alabama Power, Georgia Power, and Gulf Power) to A- from A. Also on August 17, 2015, S&P downgraded the issuer rating of Mississippi Power to BBB+ from A. S&P revised its credit rating outlook for Southern Company and the ~~variable rate pollution control revenue bond market.~~traditional operating companies to stable from negative. Separately, on August 24, 2015, S&P revised its credit rating outlook for Southern Company and the traditional operating companies from stable to negative following the announcement of the Merger.

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Also following the announcement of the Merger, on August 24, 2015, Moody's affirmed the rating of Southern Company and revised its credit rating outlook from stable to negative. On the same date, Fitch placed the ratings of Southern Company on ratings watch negative.

Financing Activities

During the first nine months of ~~2014,~~2015, Southern Company issued approximately ~~7.8~~3.7 million shares of common stock ~~for approximately $295.5 million~~primarily through the employee equity compensation plan and ~~director stock plans,~~received proceeds of ~~which 150,000 shares related to Southern Company's performance share plan.~~

~~Since August 2013, Southern Company has used shares held in treasury, to~~approximately $136 million. During the ~~extent available, to satisfy the requirements~~first nine months of 2015, all sales under the Southern Investment Plan and the employee savings plan were funded with shares acquired on the open market by independent plan administrators. In October 2015, Southern Company began issuing shares of common stock through the Southern Investment Plan and the employee savings plan.

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 were repurchased through September 30, 2015 at a total cost of approximately $115 million. There were no repurchases during the ~~first nine~~three 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~~ended September 30, 2015 and no further repurchases under the ~~requirements.~~program are anticipated.

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


Company	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^(a)		Revenue Bond Maturities and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(b)
	(in millions)														(in millions)
Southern Company	$	750	$	350	$	—	$	—	$	—		$	—		$	600	$	400	$	—	$	—	$	400	$	—
Alabama Power	400		—		—		—		—			—			975		250		80		134		—		—
Georgia Power	—		—		40		37		1,000			4			—		525		274		268		600		20
Gulf Power	200		—		42		29		—			—			—		60		13		13		—		—
Mississippi Power	—		—		—		—		493			222			—		—		—		—		—		352
Southern Power	—		—		—		—		10			1			650		525		—		—		400		3
Other	—		—		—		—		—			15			—		—		—		—		—		13
Elimination^(c)	—		—		—		—		(220		)	(220		)
Total	$	1,350	$	350	$	82	$	66	$	1,283		$	22		$	2,225	$	1,760	$	367	$	415	$	1,400	$	388


~~(a)~~	Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013 and remarketing by Georgia Power of $40 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2010.

(a) Includes a reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds purchased and held since April 2015; reofferings by Georgia Power of $104.6 million and $65 million aggregate principal amount of revenue bonds purchased and held since 2013 and April 2015, respectively; and a reoffering by Gulf Power of $13 million aggregate principal amount of revenue bonds purchased and held in July 2015. Also includes repurchases and reofferings by Georgia Power of $94.6 million and $10 million aggregate principal amount of revenue bonds in August 2015 in connection with optional tenders.


(b)	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 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.

In ~~addition to the amounts reflected in the table above, in June 2014,~~September 2015, Southern Company entered into a ~~90-day~~$400 million aggregate principal amount 18-month floating rate bank loan bearing interest based on one-month LIBOR. ~~This short-term loan was for $250 million aggregate principal amount and the~~The 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 refundablepurposes.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~deposits from SMEPA~~Also in September 2015, Southern Company repaid at maturity $400 million aggregate principal amount of its Series 2010A 2.375% Senior Notes due September 15, 2015.

Subsequent to ~~be applied~~September 30, 2015, Southern Company issued $1.0 billion aggregate principal amount of Series 2015A 6.25% Junior Subordinated Notes due October 15, 2075. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.

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

A portion of the proceeds of Alabama Power's senior note issuances were used in May 2015 to redeem 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 ~~sale~~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 ~~for the pending sale~~ of ~~an undivided interest in the Kemper IGCC. See Note 3~~$25 per share plus accrued and unpaid dividends to the ~~financial statements~~redemption date, and 6.0 million shares ($150 million aggregate stated capital) of ~~Southern Company in Item 8~~Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the ~~Form 10-K under "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" for additional information.~~redemption date.

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 a payment of approximately ~~$66~~$6 million, which will be amortized to interest expense over ~~the life~~10 years.

In 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 loan was repaid at maturity.

In April 2015, Mississippi Power entered into two short-term 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. A portion of the ~~borrowings under~~proceeds of these loans were used for the ~~FFB Credit Facility.~~

~~Under the Loan Guarantee Agreement, Georgia Power is subject to customary events~~repayment 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 floating rate bank~~term loans in an aggregate principal amount of ~~$400~~$275 million. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

In June 2015, Gulf Power entered into a $40 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The loan was repaid at maturity.

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 30, ~~2014, Gulf Power's $75~~2015, Alabama Power repaid at maturity $400 million aggregate principal amount of its Series ~~K 4.90%~~2012B 0.550% Senior Notes ~~was paid at maturity.~~due October 15, 2015.

~~Subsequent~~Also subsequent to September 30, ~~2014, Alabama~~2015, Gulf 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~~$80 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 amount~~

Table of ~~the swaps totaled $900 million.~~Contents

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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PART I

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

During the nine months ended September 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 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.

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ALABAMA POWER COMPANY

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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 September 30,						For the Nine Months Ended September 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		$	1,558		$	1,512		$	4,151		$	4,058
Wholesale revenues, non-affiliates	72			66			222			186			65			72			188			222
Wholesale revenues, affiliates	31			47			168			163			20			31			55			168
Other revenues	54			53			166			155			52			54			157			166
Total operating revenues	1,669			1,604			4,614			4,304			1,695			1,669			4,551			4,614
Operating Expenses:
Fuel	442			467			1,288			1,240			408			442			1,061			1,288
Purchased power, non-affiliates	57			36			153			84			56			57			142			153
Purchased power, affiliates	54			30			140			102			51			54			153			140
Other operations and maintenance	334			316			989			965			371			334			1,140			989
Depreciation and amortization	174			170			521			487			163			174			481			521
Taxes other than income taxes	88			85			265			262			91			88			275			265
Total operating expenses	1,149			1,104			3,356			3,140			1,140			1,149			3,252			3,356
Operating Income	520			500			1,258			1,164			555			520			1,299			1,258
Other Income and (Expense):
Allowance for equity funds used during construction	15			7			36			23			14			15			43			36
Interest expense, net of amounts capitalized	(63		)	(65		)	(188		)	(196		)	(71		)	(63		)	(205		)	(188		)
Other income (expense), net	3			—			(5		)	1			(7		)	3			(24		)	(5		)
Total other income and (expense)	(45		)	(58		)	(157		)	(172		)	(64		)	(45		)	(186		)	(157		)
Earnings Before Income Taxes	475			442			1,101			992			491			475			1,113			1,101
Income taxes	183			174			429			390			192			183			427			429
Net Income	292			268			672			602			299			292			686			672
Dividends on Preferred and Preference Stock	10			10			30			30			4			10			21			30
Net Income After Dividends on Preferred and Preference Stock	$	282		$	258		$	642		$	572		$	295		$	282		$	665		$	642

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,				For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2014		2013		2014		2013		2015			2014		2015			2014
	(in millions)				(in millions)				(in millions)					(in millions)
Net Income	$	292	$	268	$	672	$	602	$	299		$	292	$	686		$	672
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
Changes in fair value, net of tax of $(4), $-, $(4) and $-, respectively									(6		)	—		(6		)	—
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $1 and $1, respectively									—			—		1			1
Total other comprehensive income (loss)	—		—		1		1		(6		)	—		(5		)	1
Comprehensive Income	$	292	$	268	$	673	$	603	$	293		$	292	$	681		$	673

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

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2015			2014
	(in millions)						(in millions)
Operating Activities:
Net income	$	672		$	602		$	686		$	672
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	631			616			585			631
Deferred income taxes	68			200			85			68
Allowance for equity funds used during construction	(36		)	(23		)	(43		)	(36		)
Regulatory deferrals	(62		)	(14		)
Other, net	29			15			23			(33		)
Changes in certain current assets and liabilities —
-Receivables	(139		)	(98		)	(160		)	(139		)
-Fossil fuel stock	106			173			69			106
-Materials and supplies	(8		)	16			18			(8		)
-Other current assets	(32		)	(18		)	(28		)	(32		)
-Accounts payable	(64		)	(109		)	(106		)	(64		)
-Accrued taxes	210			105			371			210
-Accrued compensation	18			(36		)	(32		)	18
-Retail fuel cost over recovery	2			42			81			2
-Other current liabilities	3			(2		)	30			3
Net cash provided from operating activities	1,398			1,469			1,579			1,398
Investing Activities:
Property additions	(966		)	(779		)	(938		)	(966		)
Nuclear decommissioning trust fund purchases	(178		)	(162		)	(349		)	(178		)
Nuclear decommissioning trust fund sales	178			162			349			178
Cost of removal, net of salvage	(50		)	(29		)	(41		)	(50		)
Change in construction payables	39			12			(48		)	39
Other investing activities	(26		)	35			(22		)	(26		)
Net cash used for investing activities	(1,003		)	(761		)	(1,049		)	(1,003		)
Financing Activities:
Proceeds —
Senior note issuances	400			—
Senior notes issuances							975			400
Capital contributions from parent company	20			18			13			20
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	(30		)	(30		)	(27		)	(30		)
Payment of common stock dividends	(412		)	(397		)	(428		)	(412		)
Other financing activities	(6		)	—			(11		)	(6		)
Net cash used for financing activities	(28		)	(409		)	(194		)	(28		)
Net Change in Cash and Cash Equivalents	367			299			336			367
Cash and Cash Equivalents at Beginning of Period	295			137			273			295
Cash and Cash Equivalents at End of Period	$	662		$	436		$	609		$	662
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $13 and $8 capitalized for 2014 and 2013, respectively)	$	174		$	182
Interest (net of $15 and $13 capitalized for 2015 and 2014, respectively)							$	192		$	174
Income taxes, net	227			154			47			227
Noncash transactions — accrued property additions at end of period	57			43
Noncash transactions — Accrued property additions at end of period							88			57

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

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ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Assets	At September 30, 2014			At December 31, 2013			At September 30, 2015			At December 31, 2014
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	662		$	295		$	609		$	273
Receivables —
Customer accounts receivable	442			341			460			345
Unbilled revenues	133			142			134			138
Under recovered regulatory clause revenues	34			—			67			74
Other accounts and notes receivable	38			30			34			23
Affiliated companies	36			54			43			37
Accumulated provision for uncollectible accounts	(9		)	(8		)	(9		)	(9		)
Fossil fuel stock, at average cost	223			329			199			268
Materials and supplies, at average cost	397			375			398			406
Vacation pay	63			63			65			65
Prepaid expenses	83			57			79			244
Other regulatory assets, current	8			7			118			84
Other current assets	9			6			9			5
Total current assets	2,119			1,691			2,206			1,953
Property, Plant, and Equipment:
In service	22,688			22,092			23,922			23,080
Less accumulated provision for depreciation	8,430			8,114			8,623			8,522
Plant in service, net of depreciation	14,258			13,978			15,299			14,558
Nuclear fuel, at amortized cost	324			332			325			348
Construction work in progress	995			748			1,117			1,006
Total property, plant, and equipment	15,577			15,058			16,741			15,912
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	67			54			69			66
Nuclear decommissioning trusts, at fair value	738			714			712			756
Miscellaneous property and investments	83			80			91			84
Total other property and investments	888			848			872			906
Deferred Charges and Other Assets:
Deferred charges related to income taxes	528			519			530			525
Prepaid pension costs	290			276
Deferred under recovered regulatory clause revenues	46			25			66			31
Other regulatory assets, deferred	703			692			1,055			1,063
Other deferred charges and assets	142			142			163			162
Total deferred charges and other assets	1,709			1,654			1,814			1,781
Total Assets	$	20,293		$	19,251		$	21,633		$	20,552

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

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ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholder's Equity	At September 30, 2014			At December 31, 2013			At September 30, 2015			At December 31, 2014
	(in millions)						(in millions)
Current Liabilities:
Securities due within one year	$	54		$	—		$	600		$	454
Accounts payable —
Affiliated	245			198			272			248
Other	273			339			272			443
Customer deposits	86			85			88			87
Accrued taxes —
Accrued income taxes	146			11			105			2
Other accrued taxes	114			33			117			37
Accrued interest	62			61			67			66
Accrued vacation pay	53			53			54			54
Accrued compensation	98			74			103			131
Other regulatory liabilities, current	49			37
Other current liabilities	44			41			118			82
Total current liabilities	1,224			932			1,796			1,604
Long-term Debt	6,577			6,233			6,699			6,176
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,670			3,603			3,965			3,874
Deferred credits related to income taxes	72			75			70			72
Accumulated deferred investment tax credits	127			133			120			125
Employee benefit obligations	203			195			319			326
Asset retirement obligations	813			730			1,288			829
Other cost of removal obligations	864			828			742			744
Other regulatory liabilities, deferred	242			259			152			239
Deferred over recovered regulatory clause revenues	—			15			128			47
Other deferred credits and liabilities	54			61			73			79
Total deferred credits and other liabilities	6,045			5,899			6,857			6,335
Total Liabilities	13,846			13,064			15,352			14,115
Redeemable Preferred Stock	342			342			85			342
Preference Stock	343			343			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			1,222			1,222
Paid-in capital	2,292			2,262			2,328			2,304
Retained earnings	2,273			2,044			2,483			2,255
Accumulated other comprehensive loss	(25		)	(26		)	(33		)	(29		)
Total common stockholder's equity	5,762			5,502			6,000			5,752
Total Liabilities and Stockholder's Equity	$	20,293		$	19,251		$	21,633		$	20,552

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER ~~2014~~2015 vs. THIRD 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 quarter ~~2014~~2015 was ~~$282~~$295 million compared to ~~$258~~$282 million for the corresponding period in ~~2013.~~2014. The increase ~~in net income~~ was primarily related to an increase in ~~revenue primarily due to warmer weather~~rates under rate stabilization and equalization (Rate RSE) effective January 1, 2015 and a decrease in ~~the third quarter 2014 as compared to the corresponding period in 2013 and an increase in AFUDC equity,~~depreciation, partially offset by increases in other operating expenses.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date ~~2014~~2015 was ~~$642~~$665 million compared to ~~$572~~$642 million for the corresponding period in ~~2013.~~2014. The increase ~~in net income~~ was primarily related to an increase under Rate RSE, a decrease in ~~revenue primarily due to colder weather~~depreciation, and a decrease in ~~the first quarter 2014~~dividends on preferred and ~~warmer weather in the second and third quarters of 2014 as compared to the corresponding periods in 2013 and~~preference stock, partially offset by an increase in ~~AFUDC equity, partially offset by increases in operating expenses.~~non-fuel operations and maintenance expenses and interest expense.

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 quarter ~~2014,~~2015, retail revenues were ~~$1.51~~$1.56 billion compared to ~~$1.44~~$1.51 billion for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, retail revenues were ~~$4.06~~$4.15 billion compared to ~~$3.80~~$4.06 billion for the corresponding period in ~~2013.~~2014.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:


	Third Quarter 2014				Year-to-Date 2014				Third 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			$	1,512				$	4,058
Estimated change resulting from –
Rates and pricing	8		0.5		45		1.2		69			4.5		172			4.2
Sales growth	6		0.4		2		0.1
Sales growth (decline)									(2		)	(0.1	)	8			0.2
Weather	32		2.2		91		2.4		2			0.1		—			—
Fuel and other cost recovery	28		2.0		120		3.1		(23		)	(1.5	)	(87		)	(2.1	)
Retail – current year	$	1,512	5.1	%	$	4,058	6.8	%	$	1,558		3.0	%	$	4,151		2.3	%

Revenues associated with changes in rates and pricing increased in the third 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~~growth remained relatively flat in the third quarter 2015 and increased slightly year-to-date ~~2014~~2015 when compared to the corresponding periods in ~~2013.~~2014. Weather-adjusted residential and commercial KWH energy sales both increased 0.2% for year-to-date 2015 when compared to the corresponding period in 2014. Industrial KWH energy sales ~~increased 6.5% in the third quarter and 4.3%~~decreased 0.3% for year-to-date ~~2014~~2015 as a result of ~~an increase~~a decrease in demand resulting from changes in production levels primarily in the primary metals ~~chemicals, forest products, automotive~~sector. A strong dollar, low oil prices, and ~~plastics,~~weak global growth conditions have constrained growth in the industrial sector.

Fuel and ~~stone, clay, and glass sectors. Weather-adjusted residential KWH energy sales~~other cost recovery revenues decreased ~~1.7%~~ in the third quarter 2015 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% 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.

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

Revenues resulting from changes in weather increased year-to-date 2014 primarily due to colder weather experienced in Alabama Power's service territory in the first quarter 2014 and warmer weather in the second and third quarters 20142015 when 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.~~

~~Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2014 when compared to the corresponding periods in 2013~~ primarily due to ~~an increase~~a decrease in ~~fuel costs associated with an increase in KWH generation and~~ 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

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 quarter ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$72~~$65 million compared to ~~$66~~$72 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to ~~an 11.2% increase~~a 5.7% decrease in KWH sales ~~primarily due to the availability of Alabama Power's lower cost generation partially offset by~~and a ~~2.3%~~4.3% decrease in the price of ~~energy primarily due to the lower cost of coal.~~

energy. For year-to-date ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$222~~$188 million compared to ~~$186~~$222 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to ~~a 16.4% increase~~an 8.7% decrease in KWH sales ~~primarily due to the availability of Alabama Power's lower cost generation~~ and ~~an increase of 2.2%~~a 7.3% 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 resulted in lower sales of Alabama Power's generation to non-affiliates.

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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 quarter ~~2014,~~2015, wholesale revenues from sales to affiliates were ~~$31~~$20 million compared to ~~$47~~$31 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to a ~~38.8%~~22.9% decrease in KWH sales primarily due to decreased availability of hydro generation due to less rainfall in the third quarter 2014 as compared 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

and a 13.8% decrease in KWH sales. For year-to-date ~~2014, other~~2015, wholesale revenues from sales to affiliates were ~~$166~~$55 million compared to ~~$155~~$168 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to ~~increases~~a 52.8% decrease in ~~co-generation steam revenues, open access transmission tariff revenues,~~KWH sales and ~~transmission service agreement revenues.~~a 30.6% 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 resulted in lower sales of Alabama Power's generation to affiliates.

Fuel and Purchased Power Expenses


	Third Quarter 2014 vs. Third Quarter 2013				Year-to-Date 2014 vs. Year-to-Date 2013			Third Quarter 2015 vs. Third 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	$	(34	)	(7.7)	$	(227	)	(17.6	)
Purchased power – non-affiliates	21			58.3	69		82.1	(1		)	(1.8)	(11		)	(7.2	)
Purchased power – affiliates	24			80.0	38		37.3	(3		)	(5.6)	13			9.3
Total fuel and purchased power expenses	$	20			$	155		$	(38	)		$	(225	)

In the third quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$553~~$515 million compared to ~~$533~~$553 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~$42~~$36 million decrease in the average cost of fuel and a $9 million decrease related to the volume of KWHs purchased, partially offset by a $5 million increase in the average cost of purchased power and a $2 million increase related to the volume of KWHs generated.

~~Table~~For year-to-date 2015, fuel and purchased power expenses were $1.36 billion compared to $1.58 billion for the corresponding period in 2014. The decrease was primarily due to a $159 million decrease in the average cost of ~~Contents~~

~~ALABAMA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~purchased,~~fuel, a $6$68 million ~~increase~~decrease related to the volume of KWHs generated, and a $3$41 million ~~increase~~decrease 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~~$43 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.~~purchased.

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.

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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	Third Quarter 2015	Third Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (billions of KWHs)	17	18	50	49	17	17	46	50
Total purchased power (billions of KWHs)	2	1	5	3	2	2	5	5
Sources of generation (percent) —
Coal	59	57	55	53	61	59	56	55
Nuclear	23	21	23	22	23	23	23	23
Gas	16	16	16	16	14	16	16	16
Hydro	2	6	6	9	2	2	5	6
Cost of fuel, generated (cents per net KWH) —
Coal	3.04	3.41	3.24	3.37	2.79	3.04	2.85	3.24
Nuclear	0.81	0.84	0.84	0.83	0.81	0.81	0.81	0.84
Gas	3.54	3.27	3.83	3.38	3.11	3.54	3.08	3.83
Average cost of fuel, generated (cents per net KWH)^(a)	2.61	2.80	2.75	2.76	2.39	2.61	2.40	2.75
Average cost of purchased power (cents per net KWH)^(b)	6.56	6.44	6.32	5.44	6.90	6.56	5.56	6.32


(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 quarter ~~2014,~~2015, fuel expense was ~~$442~~$408 million compared to ~~$467~~$442 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to a ~~10.8%~~12.1% 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~~8.1% decrease in the volume of KWHs generated by ~~coal.~~

~~Table~~natural gas, and an 8.1% decrease in the average cost of ~~Contents~~coal per KWH generated.

~~ALABAMA POWER COMPANY~~For year-to-date 2015, fuel expense was $1.06 billion compared to $1.29 billion for the corresponding period in 2014. The decrease was primarily due to a 19.7% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, an 11.8% decrease in the average cost of coal per KWH generated, and a 6.7% decrease in the volume of KWHs generated. The decrease was partially offset by a 20.0% decrease in the volume of KWHs generated by hydro facilities.

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Purchased Power – Non-Affiliates

~~In the third quarter 2014,~~For year-to-date 2015, purchased power expense from non-affiliates was ~~$57~~$142 million compared to ~~$36~~$153 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was related to a ~~48.3% increase~~19.5% decrease in the average cost per KWH purchased ~~and~~as a ~~3.4%~~result of lower natural gas prices partially offset by a 15.3% 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 quarter 2014,~~For year-to-date 2015, purchased power expense from affiliates was ~~$54~~$153 million compared to ~~$30~~$140 million for the corresponding period in ~~2013.~~2014. The increase was related to a ~~130.0%~~13.9% increase in the amount of energy purchased primarily due to the ~~decreased~~ availability of Southern Company's lower cost generation sources and the decreased availability

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of hydro generation due to 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. Thisgeneration. The increase was partially offset by a ~~23.6%~~3.6% decrease in the average cost per KWH purchased due to ~~availability of~~ lower ~~cost Southern Company system generation at the time of purchase.~~

For year-to-date 2014, purchased power expense from affiliates was $140 million compared to $102 million for the corresponding period in 2013. The increase was related to a 63.1% 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 partially offset by a 16.5% 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 quarter ~~2014,~~2015, other operations and maintenance expenses were ~~$334~~$371 million compared to ~~$316~~$334 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~~an increase of $18 million in ~~labor and contract labor~~employee benefit costs including pension costs. ~~These increases were partially offset by~~In addition, the implementation of an accounting order in 2014 ~~allowing~~allowed the deferral of non-nuclear outage costs. Alabama Power deferred approximately $16 million of non-nuclear outage expenditures in the third quarter 2014. Nuclear generation costs increased $9 million primarily due to outage amortization costs and labor costs.

For year-to-date 2015, other operations and maintenance expenses were $1.14 billion compared to $989 million for the corresponding period in 2014. Alabama Power deferred approximately $57 million of non-nuclear outage expenditures in the ~~third quarter~~first nine months of 2014. In addition, employee benefit costs including pension costs increased $49 million and ~~year-to-date 2014, respectively.~~ steam generation costs increased $27 million primarily due to labor costs, maintenance costs, and other general operating expenses.

See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC~~Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Non-Nuclear Outage Accounting Order" and "– Cost of ~~Alabama Power~~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.

Depreciation and Amortization

In the third quarter 2015, depreciation and amortization was $163 million compared to $174 million for the corresponding period in 2014. For year-to-date 2015, depreciation and amortization was $481 million compared to $521 million for the corresponding period in 2014. These decreases were primarily due to a decrease in depreciation rates related to environmental, steam generation, transmission, and distribution assets effective January 1, 2015, as authorized by the FERC, partially offset by increases in plant in service.

Interest Expense, Net of Amounts Capitalized

In the third quarter 2015, interest expense, net of amounts capitalized was $71 million compared to $63 million for the corresponding period in 2014. For year-to-date 2015, interest expense, net of amounts capitalized was $205 million compared to $188 million for the corresponding period in 2014. These increases were primarily due to new debt issuances, a portion of which were used to redeem long-term debt, preferred stock, and preference stock.

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~~Depreciation and Amortization~~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 2.4 $34 7.0

~~For year-to-date 2014, depreciation and amortization~~N/M – Not meaningful

In the third quarter 2015, other income (expense), net was ~~$521~~$(7) million compared to ~~$487~~$3 million for the corresponding period in ~~2013.~~2014. The ~~increase~~change was primarily due to a decrease in sales of non-utility property in 2015.

For year-to-date 2015, other income (expense), net was $(24) million compared to $(5) million for the corresponding period in 2014. The change was primarily due to an increase in ~~depreciation rates related to environmental assets~~donations and ~~the deferral~~a decrease in ~~2013~~sales of certain costs under an accounting order. Depreciation related to environmental assets is offset by revenues associated with Rate CNP Environmental. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate CNP" of Alabama Powernon-utility property 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 Power in Item 7 of the Form 10-K for additional information regarding Alabama Power's deferral of costs under this accounting order.

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

~~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 5.2 $39 10.0

In the third quarter 2014, income taxes were $183 million compared to $174 million for the corresponding period in 2013. For year-to-date 2014, income taxes were $429 million compared to $390 million for the corresponding period in 2013. The increases were primarily due to higher pre-tax earnings.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~~Demand for electricity for Alabama Power is partially driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, ~~may impact sales for Alabama Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and~~which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Environmental Matters

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

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.

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use only natural gas at certain other 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.

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.

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, the Cross State Air Pollution Rule (CSAPR), and the ~~EPA's proposed rules~~eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.

On June 12, 2015, the 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 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 ~~is dependent on~~remands the ~~outcome of further legal proceedings, the manner in which~~rule to the EPA ~~and~~for further action consistent with 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.~~court's decision. 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~~court rejected all other pending challenges to the ~~rule, including Alabama, to revise their SSM provisions within 18 months after issuance of the final~~ 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.

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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.

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 became effective August 28, 2015, but on October 9, 2015, the ~~rule as proposed could have significant impacts on economic development projects which could affect customer demand growth.~~U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact

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~~impact~~ of the ~~proposed~~final rule will depend on the ~~specific requirements~~outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the ~~final~~ rule ~~and the outcome of any legal challenges~~ 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 Alabama 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,~~(CCR Rule) in the Federal Register, which became effective on October ~~14, 2014. The ultimate outcome~~19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ~~this final rule will depend on~~ash ponds pursuant to the ~~results~~CCR Rule, during the second quarter 2015, Alabama Power recorded incremental asset retirement obligations (ARO) of ~~additional studies and implementation~~approximately $401 million related to the CCR Rule. As further analysis is performed, including evaluation of the ~~rule by state regulators, but could result in additional capital~~expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and ~~operational costs associated with changes~~the determination of timing, including the potential for closing ash ponds prior to ~~existing intake structures and cooling systems and increased costs associated with~~ the ~~construction~~end of ~~new generating units.~~their currently anticipated useful life, Alabama Power expects to continue to periodically update these estimates. 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 Alabama Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's AROs as of September 30, 2015.

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,~~October 23, 2015, two final actions by the EPA that would limit CO₂ emissions from fossil fuel-fired electric generating units were published in the ~~proposed Clean Power Plan, setting forth~~Federal Register. One of the final actions contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final action 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, a proposed federal plan and proposed model rule were published 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, including legal challenges filed by Alabama Power; 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

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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 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 Note 1 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and Note 3 under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Rate CNP

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

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~~FERC Matters~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of~~On August 14, 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-13, allowing the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power ~~in Item 7 of the Form 10-K~~currently accounts for ~~additional information~~its two wind PPAs. The new accounting guidance will have no impact 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 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 for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.financial statements.

Environmental Accounting Order

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

AsIn 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~~On August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the joint stipulation in the New Source Review (NSR) action. In accordance with the joint stipulation, Alabama Power retired Plant Barry Unit 3 (225 MWs) and it is no longer available for generation. See Note (B) to ~~be effective no later than April 2016.~~the Condensed Financial Statements herein for additional information regarding the NSR 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.~~retirement, and recovered through Rate CNP. As a result, these decisions will not have a significant impact on Alabama Power's financial statements.

~~Nuclear Waste Fund Accounting Order~~

See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters"~~Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 78 of the Form 10-K and ~~"Other Matters"~~"Retail Regulatory Matters – Rate CNP" herein for additional ~~information regarding the court order for the DOE to set the spent fuel depositary fees at zero.~~information.

Renewable Energy

On ~~August 5, 2014,~~September 1, 2015, the Alabama PSC ~~issued an order to provide~~approved Alabama Power's petition 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, 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 accountRenewable Generation Certificate. This 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. 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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~~ALABAMA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~On November 3, 2014, the Alabama PSC issued an accounting order authorizing~~allow 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~~build its own renewable projects each less than 80 MWs or purchase power from other renewable-generated sources 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.500 MWs.

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

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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.

As a result of the final CCR Rule discussed above, Alabama Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information 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 for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Alabama Power expects to continue 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. Early adoption is permitted and Alabama Power intends to adopt the ASU in the fourth quarter 2015. The ASU is required to be applied retrospectively to all periods presented beginning in the year of adoption. Alabama Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption,

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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 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~~$1.6 billion for the first nine months of ~~2014, a decrease~~2015, an increase of ~~$71~~$181 million as compared to the first nine months of ~~2013.~~2014. The ~~decrease~~increase in net cash provided from operating activities was primarily due to ~~an increase in~~the timing of income tax payments and ~~changes in~~refunds associated with bonus depreciation and collection of fuel cost recovery revenues, partially offset by the timing of ~~fossil fuel stock purchases as compared to the first nine months~~payments of ~~2013.~~accounts payable. Net cash used for investing activities totaled $1.0 billion for the first nine 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~~$194 million for the first nine months of ~~2014~~2015 primarily due to the ~~payment~~redemptions and repurchases of ~~common~~long-term debt and ~~preferred~~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 months of ~~2014~~2015 include ~~an increase~~increases of ~~$519~~$829 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, and steam generation, ~~$367~~$336 million in cash and cash equivalents, ~~$344~~$523 million in long-term debt primarily due to the issuance of additional senior notes, and ~~$135~~$459 million in ~~accrued income taxes.~~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 redeemable preferred and preference stock due to redemptions in 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 Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately ~~$54~~$600 million will be required through September 30, ~~2015~~2016 to fund maturities of long-term debt.

~~Table~~ Subsequent to September 30, 2015, Alabama Power repaid at maturity $400 million aggregate principal amount of ~~Contents~~its Series 2012B 0.550% Senior Notes due October 15, 2015.

~~ALABAMA POWER COMPANY~~

~~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.

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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~~meet its future capital needs through operating cash flows, short-term debt, term loans, external security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.

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 30, ~~2014,~~2015, Alabama Power had approximately ~~$662~~$609 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, ~~2014~~2015 were as follows:


Expires^(a)	Expires^(a)											Executable Term Loans				Due Within One Year				Expires^(a)											Due Within One Year
2014		2015		2016		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
2016																				2016	2018		2020		Total		Unused		Term Out		No Term Out
(in millions)	(in millions)							(in millions)				(in millions)				(in millions)				(in millions)					(in millions)				(in millions)
$	70	$	158	$	50	$	1,030	$	1,308	$	1,308	$	58	$	—	$	58	$	170	40	$	500	$	800	$	1,340	$	1,339	$	—	$	40


~~(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.

Most of these arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross default provisions to other indebtedness would trigger an event of default ifAs reflected in the table above, in August 2015, Alabama Power ~~defaulted on indebtedness or guarantee obligations over a specified threshold. Alabama Power is currently in compliance with all such covenants. None of~~amended and restated its multi-year credit arrangement, which, among other things, extended the ~~arrangements contain material adverse change clauses at the time of borrowings. Alabama Power expects~~maturity date from 2018 to ~~renew its credit arrangements, as needed, prior to expiration.~~

2020. In addition, Alabama Power ~~has substantial cash flow from operating activities and access to capital markets, including~~entered into a ~~commercial paper program, to meet liquidity needs.~~ new $500 million three-year credit arrangement which replaced a majority of Alabama Power's bi-lateral credit arrangements.

A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's variable rate pollution control revenue bonds and commercial paper borrowings. AsThe amount of ~~September 30, 2014, Alabama Power had $784 million of outstanding~~ variable rate pollution control revenue bonds outstanding requiring liquidity ~~support.~~support as of September 30, 2015 was approximately $810 million. In addition, at September 30, ~~2014,~~2015, Alabama Power

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had ~~$280~~$200 million of fixed rate pollution control revenue bonds outstanding that ~~will be~~were required to be ~~remarketed~~reoffered within the next 12 ~~months.~~months, of which $120 million were remarketed subsequent to September 30, 2015.

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. Alabama Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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

In addition, Alabama Power has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama

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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~~Alabama Power had no commercial paper or short-term ~~borrowings were as follows:~~debt outstanding during the three-month period ended September 30, 2015.

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


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

~~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-~~BBB and/or ~~Baa3.~~Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, ~~and~~ energy price risk ~~management. At September 30, 2014, the~~management, and transmission. The maximum potential collateral requirements under these contracts at ~~a rating below BBB- and/or Baa3~~September 30, 2015 were ~~approximately $343 million.~~ as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	1
At BBB- and/or Baa3	2
Below BBB- and/or Baa3	372

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 the ability of Alabama ~~Power's ability~~Power to access capital markets, ~~particularly~~and would be likely to impact the ~~short-term debt market and~~cost at which it does so.

On August 17, 2015, S&P downgraded the ~~variable rate pollution control revenue bond market.~~consolidated long-term issuer rating of Southern Company (including Alabama Power) to A- from A. S&P revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its credit rating outlook from stable to negative following the announcement of the Merger.

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.

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.

Table of Contents

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

In June 2015, $18.7 million aggregate principal amount of the 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.

Subsequent to September 30, ~~2014,~~2015, Alabama Power ~~entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional~~repaid at maturity $400 million aggregate principal amount of ~~the swaps totaled $100 million.~~its Series 2012B 0.550% Senior Notes due October 15, 2015.

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

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GEORGIA POWER COMPANY

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended September 30,						For the Nine Months Ended September 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		$	2,537		$	2,452		$	6,223		$	6,502
Wholesale revenues, non-affiliates	80			77			269			212			55			80			173			269
Wholesale revenues, affiliates	7			3			38			14			5			7			18			38
Other revenues	92			90			277			260			94			92			271			277
Total operating revenues	2,631			2,484			7,086			6,408			2,691			2,631			6,685			7,086
Operating Expenses:
Fuel	684			691			2,055			1,767			706			684			1,735			2,055
Purchased power, non-affiliates	77			64			219			175			90			77			227			219
Purchased power, affiliates	172			152			522			503			148			172			411			522
Other operations and maintenance	456			402			1,334			1,230			462			456			1,405			1,334
Depreciation and amortization	211			201			628			605			214			211			633			628
Taxes other than income taxes	111			102			320			292			107			111			302			320
Total operating expenses	1,711			1,612			5,078			4,572			1,727			1,711			4,713			5,078
Operating Income	920			872			2,008			1,836			964			920			1,972			2,008
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		)	(90		)	(88		)	(272		)	(262		)
Other income (expense), net	1			(1		)	—			(2		)	18			14			34			29
Total other income and (expense)	(74		)	(82		)	(233		)	(257		)	(72		)	(74		)	(238		)	(233		)
Earnings Before Income Taxes	846			790			1,775			1,579			892			846			1,734			1,775
Income taxes	317			299			660			600			337			317			657			660
Net Income	529			491			1,115			979			555			529			1,077			1,115
Dividends on Preferred and Preference Stock	4			4			13			13			4			4			13			13
Net Income After Dividends on Preferred and Preference Stock	$	525		$	487		$	1,102		$	966		$	551		$	525		$	1,064		$	1,102

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,				For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2014		2013		2014		2013		2015			2014		2015			2014
	(in millions)				(in millions)				(in millions)					(in millions)
Net Income	$	529	$	491	$	1,115	$	979	$	555		$	529	$	1,077		$	1,115
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
Changes in fair value, net of tax of $(7), $-, $(7) and $-, respectively									(11		)	—		(10		)	—
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $1 and $1, respectively									1			—		2			1
Total other comprehensive income (loss)	—		1		1		2		(10		)	—		(8		)	1
Comprehensive Income	$	529	$	492	$	1,116	$	981	$	545		$	529	$	1,069		$	1,116

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2015			2014
	(in millions)						(in millions)
Operating Activities:
Net income	$	1,115		$	979		$	1,077		$	1,115
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	757			734			766			757
Deferred income taxes	121			354			12			121
Allowance for equity funds used during construction	(29		)	(24		)	(24		)	(29		)
Retail fuel cost over recovery — long-term	(44		)	(123		)	—			(44		)
Deferred expenses	(35		)	(34		)	(45		)	(35		)
Pension, postretirement, and other employee benefits	28			58			40			28
Other, net	23			28			30			24
Changes in certain current assets and liabilities —
-Receivables	(377		)	(191		)	37			(377		)
-Fossil fuel stock	337			213			141			337
-Prepaid income taxes	19			11			244			19
-Other current assets	(24		)	38			(17		)	(24		)
-Accounts payable							(118		)	(7		)
-Accrued taxes	148			131			54			148
-Accrued compensation							(34		)	20
-Retail fuel cost over recovery — short-term							—			(14		)
-Other current liabilities	29			(46		)	(3		)	29
Net cash provided from operating activities	2,068			2,128			2,160			2,068
Investing Activities:
Property additions	(1,364		)	(1,165		)	(1,321		)	(1,364		)
Investment of restricted cash	—			(89		)
Distribution of restricted cash	—			89
Nuclear decommissioning trust fund purchases	(457		)	(582		)	(815		)	(457		)
Nuclear decommissioning trust fund sales	455			580			810			455
Cost of removal, net of salvage	(39		)	(42		)	(57		)	(39		)
Change in construction payables, net of joint owner portion	16			(28		)	44			16
Prepaid long-term service agreements	(66		)	(14		)	(60		)	(66		)
Other investing activities	(3		)	—			11			(3		)
Net cash used for investing activities	(1,458		)	(1,251		)	(1,388		)	(1,458		)
Financing Activities:
Increase (decrease) in notes payable, net	(836		)	211
Decrease in notes payable, net							(26		)	(836		)
Proceeds —
Capital contributions from parent company	39			30			41			39
Pollution control revenue bonds issuances	40			89
Senior notes issuances	—			850
Pollution control revenue bonds							274			40
FFB loan	1,000			—			600			1,000
Redemptions —
Short-term borrowings							250			—
Redemptions and repurchases —
Pollution control revenue bonds	(37		)	(89		)	(268		)	(37		)
Senior notes	—			(1,250		)	(525		)	—
Short-term borrowings							(250		)	—
Payment of preferred and preference stock dividends	(13		)	(13		)	(13		)	(13		)
Payment of common stock dividends	(715		)	(680		)	(776		)	(715		)
FFB loan issuance costs	(49		)	(2		)	—			(49		)
Other financing activities	(6		)	(15		)	(18		)	(6		)
Net cash used for financing activities	(577		)	(869		)	(711		)	(577		)
Net Change in Cash and Cash Equivalents	33			8			61			33
Cash and Cash Equivalents at Beginning of Period	30			45			24			30
Cash and Cash Equivalents at End of Period	$	63		$	53		$	85		$	63
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $13 and $10 capitalized for 2014 and 2013, respectively)	$	235		$	247
Interest (net of $10 and $13 capitalized for 2015 and 2014, respectively)							$	251		$	235
Income taxes, net	309			109			311			309
Noncash transactions — accrued property additions at end of period	220			230
Noncash transactions — Accrued property additions at end of period							192			220

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

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Assets	At September 30, 2014			At December 31, 2013			At September 30, 2015			At December 31, 2014
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	63		$	30		$	85		$	24
Receivables —
Customer accounts receivable	738			512			758			553
Unbilled revenues	241			209			243			201
Joint owner accounts receivable	75			67			52			121
Other accounts and notes receivable	54			117			47			61
Affiliated companies	21			21			22			18
Accumulated provision for uncollectible accounts	(8		)	(5		)	(7		)	(6		)
Fossil fuel stock, at average cost	405			742			298			439
Materials and supplies, at average cost	431			409			439			438
Vacation pay	88			88			90			91
Prepaid income taxes	57			97			24			278
Other regulatory assets, current	62			66			124			136
Other current assets	118			54			94			74
Total current assets	2,345			2,407			2,269			2,428
Property, Plant, and Equipment:
In service	30,818			30,132			31,546			31,083
Less accumulated provision for depreciation	11,192			10,970			11,046			11,222
Plant in service, net of depreciation	19,626			19,162			20,500			19,861
Other utility plant, net	218			240			10			211
Nuclear fuel, at amortized cost	516			523			544			563
Construction work in progress	3,884			3,500			4,390			4,031
Total property, plant, and equipment	24,244			23,425			25,444			24,666
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	58			46			62			58
Nuclear decommissioning trusts, at fair value	772			751			761			789
Miscellaneous property and investments	37			44			38			38
Total other property and investments	867			841			861			885
Deferred Charges and Other Assets:
Deferred charges related to income taxes	701			718			678			698
Prepaid pension costs	133			118
Deferred under recovered regulatory clause revenues	175			—			—			197
Other regulatory assets, deferred	1,156			1,152			2,075			1,753
Other deferred charges and assets	294			246			399			403
Total deferred charges and other assets	2,459			2,234			3,152			3,051
Total Assets	$	29,915		$	28,907		$	31,726		$	31,030

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

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholder's Equity	At September 30, 2014			At December 31, 2013			At September 30, 2015			At December 31, 2014
	(in millions)						(in millions)
Current Liabilities:
Securities due within one year	$	503		$	5		$	1,362		$	1,154
Notes payable	211			1,047			130			156
Accounts payable —
Affiliated	503			417			444			451
Other	476			472			515			555
Customer deposits	250			246			260			253
Accrued taxes —
Accrued income taxes	155			—			75			1
Other accrued taxes	313			321			311			332
Accrued interest	99			91			99			96
Accrued vacation pay	60			61			62			63
Accrued compensation	111			80			120			153
Other current liabilities	177			166			345			256
Total current liabilities	2,858			2,906			3,723			3,470
Long-term Debt	9,135			8,633			8,709			8,683
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,295			5,200			5,493			5,507
Deferred credits related to income taxes	107			112			101			106
Accumulated deferred investment tax credits	196			203			188			196
Employee benefit obligations	580			542			893			903
Asset retirement obligations	1,215			1,210			1,332			1,223
Other cost of removal obligations	58			43
Other deferred credits and liabilities	178			201			266			255
Total deferred credits and other liabilities	7,629			7,511			8,273			8,190
Total Liabilities	19,622			19,050			20,705			20,343
Preferred Stock	45			45			45			45
Preference Stock	221			221			221			221
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares	398			398			398			398
Paid-in capital	5,683			5,633			6,251			6,196
Retained earnings	3,950			3,565			4,123			3,835
Accumulated other comprehensive loss	(4		)	(5		)	(17		)	(8		)
Total common stockholder's equity	10,027			9,591			10,755			10,421
Total Liabilities and Stockholder's Equity	$	29,915		$	28,907		$	31,726		$	31,030

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER ~~2014~~2015 vs. THIRD 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 quarter ~~2014~~2015 was ~~$525~~$551 million compared to ~~$487~~$525 million for the corresponding period in ~~2013.~~2014. For year-to-date 2015, net income after dividends on preferred and preference stock was $1.06 billion compared to $1.10 billion for the corresponding period in 2014. The increase in the third quarter 2015 was primarily due to an increase in retail base revenues effective January 1, ~~2014~~2015, as authorized ~~under~~by the ~~2013 ARP and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013,~~Georgia PSC, partially offset by higher non-fuel ~~operations and maintenance~~operating expenses.

~~Georgia Power's net income after dividends on preferred and preference stock for~~ The decrease in year-to-date ~~2014 was $1.10 billion compared to $966 million for the corresponding period in 2013. The increase~~2015 was primarily due to ~~colder weather in~~higher non-fuel operating expenses and the ~~first quarter 2014~~correction of an error affecting billings since 2013 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 under a rate plan allowing for variable demand-driven pricing, 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.

~~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

InSee Note (A) to the ~~third quarter 2014, retail revenues were $2.45 billion compared to $2.31 billion~~Condensed Financial Statements herein for ~~the corresponding period in 2013. For year-to-date 2014, retail revenues were $6.50 billion compared to $5.92 billion for the corresponding period in 2013.~~additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

In the third quarter 2015, retail revenues were $2.54 billion compared to $2.45 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $6.22 billion compared to $6.50 billion for the corresponding period in 2014.

Details of the changes in retail revenues were as follows:


	Third Quarter 2014				Year-to-Date 2014				Third 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			$	2,452				$	6,502
Estimated change resulting from –
Rates and pricing	67		2.9		147		2.5		29			1.2		32			0.5
Sales growth	1		0.1		23		0.4		13			0.5		49			0.7
Weather	51		2.2		131		2.2		44			1.8		50			0.8
Fuel cost recovery	19		0.8		279		4.7		(1		)	—		(410		)	(6.3	)
Retail – current year	$	2,452	6.0	%	$	6,502	9.8	%	$	2,537		3.5	%	$	6,223		(4.3	)%

Revenues associated with changes in rates and pricing increased in the third quarter ~~and year-to-date 2014~~2015 when compared to the corresponding ~~periods~~period in ~~2013~~2014 primarily due 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, which were both effective January 1, 2015 as well as higher contributions from ~~market-driven rates~~variable demand-driven pricing from commercial and industrial customers. Revenues associated with changes in rates and pricing increased for 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 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. 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 quarter andyear-to-date ~~2014~~2015 when compared to the corresponding periods in ~~2013.~~2014. Weather-adjusted residential KWH sales ~~decreased~~increased 0.1%, weather-adjusted commercial KWH sales increased 1.8%, and weather-adjusted industrial KWH sales decreased 0.3% in the third quarter 2015 when compared to the corresponding period in 2014. For year-to-date 2015, weather-adjusted residential KWH sales increased 1.1%, weather-adjusted commercial KWH sales increased 1.3%, and weather-adjusted industrial KWH sales increased ~~2.4% in the third quarter 2014~~1.2% when compared to the corresponding period in ~~2013. For year-to-date~~2014. An increase of approximately 26,000 residential customers since September 30, 2014 contributed to the increase in weather-adjusted residential KWH ~~sales increased 0.8%,~~sales. Increased customer usage and an increase of approximately 3,000 commercial customers since September 30, 2014 contributed to the increase in weather-adjusted commercial ~~KWH sales decreased 0.2%, and weather-adjusted industrial KWH sales increased 1.7% when compared to the corresponding period in 2013.~~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 year-to-date 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 chemicals and primary ~~drivers of residential customer usage, has been flat~~metals sectors. A strong dollar, low oil prices, and weak global growth conditions have constrained growth in ~~2014.~~the industrial sector.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues ~~increased $19~~decreased $1 million and ~~$279~~$410 million in the third 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 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.~~costs. Electric rates include provisions to adjust

Table of Contents

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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

~~Table of Contents~~

~~GEORGIA POWER COMPANY~~

~~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 ofto produce the energy.

~~For year-to-date 2014,~~In the third quarter 2015, wholesale revenues from sales to non-affiliates were ~~$269~~$55 million compared to ~~$212~~$80 million for the corresponding period in ~~2013~~2014 related to an $8 million decrease in energy revenues and a $17 million decrease in capacity revenues. For year-to-date 2015, wholesale revenues from sales to non-affiliates were $173 million compared to $269 million for the corresponding period in 2014 related to a $57 million decrease in energy revenues and a $39 million decrease in capacity revenues. The decreases in energy revenues were primarily due to ~~increased demand resulting from colder weather~~lower natural gas prices. The decreases in capacity revenues reflect the ~~first quarter~~expiration of wholesale contracts in December 2014 and ~~warmer weather in~~ the ~~second~~retirements of Plant Branch Units 1, 3, and ~~third quarters 2014 as compared to the corresponding periods in 2013~~4, Plant Yates Units 1 through 5, and ~~the lower cost of Georgia Power-owned generation compared to the market cost of available energy.~~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 third quarter 2015, wholesale revenues from sales to affiliates were ~~$38~~$5 million compared to ~~$14~~$7 million for the corresponding period in ~~2013.~~2014. For year-to-date 2015, wholesale revenues from sales to affiliates were $18 million compared to $38 million for the corresponding period in 2014. The ~~increase was~~decreases were due to ~~higher demand resulting from colder weather~~lower natural gas prices and a 41.7% and 52.9% decrease in KWH sales in the ~~first~~third quarter ~~2014~~2015 and ~~warmer weather in~~year-to-date 2015, respectively, primarily due to the ~~second and third quarters 2014~~higher cost of Georgia Power-owned generation as compared to the ~~corresponding periods in 2013 and the lower~~market 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

For year-to-date 2014, other operating revenues were $277 million compared to $260 million in the corresponding period in 2013. The increase was primarily due to an increase of $13 million in open access transmission tariff revenues and $6 million of solar application fee revenue for year-to-date 2014 as compared to the corresponding period in 2013.

~~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 $ (7 ) (1.0 ) $ 288
16.3
Purchased power – non-affiliates 13
20.3
44
25.1
Purchased power – affiliates 20
13.2
19
3.8
Total fuel and purchased power expenses $ 26
$ 351

In the third quarter 2014, total fuel and purchased power expenses were $933 million compared to $907 million in the corresponding period in 2013. The increase in the third quarter 2014 was primarily due to an $82 million increase in the volume of KWHs generated and purchased as a result of warmer weather in the third quarter 2014 asavailable energy.

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Fuel and Purchased Power Expenses



	Third Quarter 2015 vs. Third Quarter 2014					Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	22		3.2		$	(320	)	(15.6	)
Purchased power – non-affiliates	13			16.9		8			3.7
Purchased power – affiliates	(24		)	(14.0	)	(111		)	(21.3	)
Total fuel and purchased power expenses	$	11				$	(423	)

In the third quarter 2015, total fuel and purchased power expenses were $944 million compared to $933 million in the corresponding period in ~~2013 driving~~2014. The increase in the third quarter 2015 was primarily due to an increase of $44 million in the volume of KWHs purchased due to lower natural gas prices and a $37 million increase in the average cost of fuel related to higher ~~customer demand,~~coal prices, partially offset by a ~~$56~~$35 million decrease in the average cost of ~~fuel primarily~~purchased power due to lower natural gas prices and a $35 million decrease in the volume of KWHs generated due to higher coal prices.

For year-to-date ~~2014,~~2015, total fuel and purchased power expenses were ~~$2.80~~$2.37 billion co~~mpared~~compared to ~~$2.45~~$2.80 billion in the corresponding period in ~~2013.~~2014. The ~~increase~~decrease in year-to-date ~~2014 wa~~s2015 was primarily due to a ~~$66~~$394 million ~~increase~~decrease in the average cost of fuel and purchased power ~~primarily due~~related to ~~higher~~lower natural gas prices and a ~~$285~~$135 million decrease in the volume of KWHs generated due to higher coal prices, partially offset by a $106 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	Third Quarter 2015	Third Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (billions of KWHs)	19	19	55	50	19	19	53	55
Total purchased power (billions of KWHs)	6	5	16	17	7	6	18	16
Sources of generation (percent) —
Coal	45	42	45	35	41	45	38	45
Nuclear	20	22	21	23	22	20	23	21
Gas	34	34	32	39	36	34	37	32
Hydro	1	2	2	3	1	1	2	2
Cost of fuel, generated (cents per net KWH) —
Coal	4.19	4.89	4.49	4.99	5.42	4.19	4.65	4.49
Nuclear	0.86	0.91	0.90	0.91	0.86	0.86	0.76	0.90
Gas	3.41	3.34	3.84	3.34	2.57	3.41	2.62	3.84
Average cost of fuel, generated (cents per net KWH)	3.25	3.47	3.51	3.37	3.37	3.25	2.98	3.51
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)^(*)					4.54	5.03	4.50	5.42


~~(a)~~(*)	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 quarter 2014, fuel expense was $684 million compared to $691 million in the corresponding period in 2013. The decrease was primarily due to a 14.3% 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 primarily due to higher natural gas prices.

~~Purchased Power – Non-Affiliates~~

In the third quarter 2014, purchased power expense from non-affiliates was $77 million compared to $64 million in the corresponding period in 2013. The increase was due to a 4.1% increase in the average cost per KWH purchased

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Fuel

In the third quarter 2015, fuel expense was $706 million compared to $684 million in the corresponding period in 2014. The increase was primarily ~~resulting from higher~~due to a 29.4% increase in the average cost of coal per KWH generated, partially offset by a 24.6% decrease in the average cost of natural gas ~~prices~~per KWH generated and an 11.5% decrease in the volume of KWHs generated by coal.

For year-to-date 2015, fuel expense was $1.74 billion compared to $2.06 billion in the corresponding period in 2014. The decrease was primarily due to a ~~19.0%~~15.1% decrease in the average cost of fuel per KWH generated and an 18.5% decrease in the volume of KWHs generated by coal, partially offset by a 9.5% increase in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the third quarter 2015, purchased power expense from non-affiliates was $90 million compared to $77 million in the corresponding period in 2014. The increase was primarily due to a 42.9% 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.~~

~~For year-to-date 2014, purchased power expense from non-affiliates was $219 million compared to $175 million in the corresponding period in 2013.~~ ~~The increase was due to an increase of 17.5%~~partially offset by a 15.0% decrease in the average cost per KWH purchased primarily resulting from ~~higher~~lower natural gas ~~prices and~~prices.

For year-to-date 2015, purchased power expense from non-affiliates was $227 million compared to $219 million in the corresponding period in 2014. The increase was primarily due to a ~~7.3%~~46.0% increase in the volume of KWHs purchased to meet ~~higher~~ customer demand, partially offset by a 26.4% decrease in the average cost per KWH purchased primarily 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.~~lower natural gas prices.

Purchased Power – Affiliates

In the third quarter ~~2014,~~2015, purchased power expense from affiliates was ~~$172~~$148 million compared to ~~$152~~$172 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~~$411 million compared to ~~$503~~$522 million in the corresponding period in ~~2013.~~2014. The ~~increase was primarily~~decreases were due to ~~a 10.1% increase~~decreases of 11.0% and 17.2% in the average cost per KWH purchased ~~reflecting higher~~in the third quarter 2015 and year-to-date 2015, respectively, 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 quarter ~~2014,~~2015, other operations and maintenance expenses were ~~$456~~$462 million compared to ~~$402~~$456 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 and $5 million primarily related to ~~meet higher demand~~customer incentive and ~~for scheduled outage maintenance and $22~~demand-side management costs due to additional customer participation, partially offset by a decrease of $10 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~~$1.41 billion co~~mpared to $1.23 billion in the corresponding p~~eriod in 2013. The increase was due to increases of $44 million in generation expenses to meet higher demand, $37 million in transmission and distribution overhead line maintenance, and $16 million in customer assistance expenses related to customer incentive and demand-side management programs.

~~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 quarter 2014, depreciation and amortization was $211 million~~ compared to ~~$201 million~~$1.33 billion in the corresponding period in ~~2013.~~2014. The increase was primarily due to ~~decreases~~increases of ~~$9 million and $4~~$39 million in ~~amortization of~~employee compensation and benefits including pension costs, $13 million in scheduled outage-related costs, and $17 million

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~~regulatory liabilities~~primarily related to ~~state income tax credits that was completed in December 2013~~customer incentive and ~~other cost of removal obligations as authorized in the 2013 ARP, respectively, partially offset by a decrease of $6 million in~~demand-side management costs due to additional customer participation.

Depreciation and Amortization

For year-to-date 2015, depreciation and amortization ~~also as authorized in the 2013 ARP.~~

~~For year-to-date 2014, depreciation and amortization~~was ~~$628~~$633 million compared to ~~$605~~$628 million in the corresponding period in ~~2013.~~2014. The increase was primarily due to ~~decreases of $27~~a $16 million ~~and $12 million in amortization of regulatory liabilities~~increase related to ~~state income tax credits that was completed~~additional plant in ~~December 2013 and~~service, partially offset by a $9 million decrease related to other cost of removal ~~obligations as authorized~~and a $3 million decrease due to a change in ~~the 2013 ARP, respectively, partially offset by a decrease of $14 million in depreciation and amortization also as authorized in the 2013 ARP.~~useful lives.

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 quarter ~~2014,~~2015, taxes other than income taxes were ~~$111~~$107 million compared to ~~$102~~$111 million in the corresponding period in ~~2013.~~ 2014. For the year-to-date ~~2014,~~2015, taxes other than income taxes were ~~$320~~$302 million c~~ompared~~compared to ~~$292~~$320 million in the corresponding period in ~~2013.~~2014. The ~~increases were~~decrease in year-to-date 2015 was primarily due to ~~increases~~decreases of ~~$5 million and $21~~$9 million in municipal franchise fees related to ~~higher~~lower retail revenues and ~~$3 million and $6~~$7 million in ~~payroll taxes in the third quarter 2014 and year-to-date 2014, respectively.~~property 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)
$(4) (4.3) $(17) (6.1)

In the third quarter ~~2014,~~2015, interest expense, net of amounts capitalized was ~~$88~~$90 million compared to ~~$92~~$88 million in the corresponding period in ~~2013.~~2014. For year-to-date 2015, interest expense, net of amounts capitalized was $272 million compared to $262 million in the corresponding period in 2014. The ~~decrease was~~increases were primarily 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~~increased outstanding long-term debt borrowings from the FFB.

~~For year-to-date 2014, interest expense, net of amounts capitalized was $262~~Income Taxes

In the third quarter 2015, income taxes were $337 million compared to ~~$279~~$317 million in the corresponding period in 2013. The decrease was due 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.~~

~~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,~~2014. For year-to-date 2015, income taxes were ~~$317~~$657 million compared to ~~$299 million for the corresponding period in 2013. For year-to-date 2014, income taxes were~~ $660 ~~million compared to $600~~ million in the corresponding period in ~~2013.~~2014. The ~~increases~~increase in ~~income taxes were~~the third quarter 2015 was primarily due to higher pre-tax earnings.

~~Table~~ The decrease in year-to-date 2015 was due to lower pre-tax earnings, partially offset by the recognition in 2014 of ~~Contents~~tax benefits related to emission allowances and state apportionment and lower non-taxable AFUDC equity.

~~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

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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~~Demand for electricity for Georgia Power is partially driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, ~~may impact sales for Georgia Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and~~which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to 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, the Cross State Air Pollution Rule (CSAPR), and the ~~EPA's proposed rules~~eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.

On June 12, 2015, the EPA published a final rule requiring affected states (including Georgia, Alabama, and 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.

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

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Georgia, Alabama, and ~~Florida)~~Florida. 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.

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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.

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 became effective August 28, 2015, but on October 9, 2015, the ~~rule as proposed could have significant impacts on economic development projects which could affect customer demand growth.~~U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the ~~proposed~~final rule will depend on the ~~specific requirements~~outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the ~~final~~ rule ~~and the outcome of any legal challenges~~ 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,~~(CCR Rule) in the Federal Register, which became effective on October ~~14, 2014. The ultimate outcome~~19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ~~this final rule will depend on~~ash ponds pursuant to the ~~results~~CCR Rule, during the second quarter 2015, Georgia Power recorded incremental asset retirement obligations (ARO) of ~~additional studies and implementation~~approximately $82 million related to the CCR Rule. As further analysis is performed, including evaluation of the ~~rule by state regulators, but could result in additional capital~~expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and ~~operational costs associated with changes~~the determination of timing, including the potential for closing ash ponds prior to ~~existing intake structures and cooling systems and increased costs associated with~~ the ~~construction~~end of ~~new generating units.~~their currently anticipated useful life, Georgia Power expects to continue to periodically update these estimates. The ultimate impact of ~~this rule will depend on~~ the ~~outcome of any legal challenges and~~CCR Rule cannot be determined at this ~~time.~~

~~Global Climate Issues~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of~~timeand will depend on Georgia ~~Power in Item 7~~Power's ongoing review of the ~~Form 10-K~~CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. See Note (A) to the Condensed Financial Statements herein for additional information regarding ~~the EPA's current and proposed regulation~~Georgia Power's AROs as 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 CO~~₂ ~~emissions from existing 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. 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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~~a preliminary estimated cost~~Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of ~~complying with the proposed guidelines utilizing one~~Georgia 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.

These guidelines and standards could result in operational restrictions and material compliance ~~scenarios. These~~ costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Georgia Power's results of operations, cash flows, and financial condition could be ~~significant to the utility industry and the Southern Company system.~~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~~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, including legal challenges filed by Georgia Power; 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 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

Georgia Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Georgia Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On ~~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 Georgia 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 Georgia 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 Georgia 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.

~~PSC~~Retail Regulatory Matters

~~Rate Plans~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate Plans"~~Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power ~~in Item 7~~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 the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory ~~Matters – Rate Plans" in Item 8 of the Form 10-K for additional information on Georgia Power's 2013 ARP.~~

~~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"Matters" 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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~~On October 8, 2014, Georgia Power executed PPAs to purchase energy from 515 MWs of solar capacity as~~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~~an up to 46-MW solar generation ~~facilities~~facility at ~~three~~a U.S. ~~Army bases~~Marine Corps base in Albany, Georgia by the end of 2016.

Rate Plans

In ~~addition,~~accordance with the terms of the 2013 ARP, on October 2, 2015, Georgia Power ~~has entered into a memorandum of understanding~~filed the following tariff adjustments with the ~~U.S. Navy to pursue a similar solar project pending~~ Georgia PSC ~~review.~~to become effective January 1, 2016 pending its approval:

increase in traditional base tariffs by approximately $49 million;

increase in the environmental compliance cost recovery tariff by approximately $75 million;

increase in the demand-side management tariffs by approximately $7 million; and

increase in the municipal franchise fee tariff by approximately $13 million.

The ultimate outcome of ~~these matters~~this matter 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. On October 13, 2015, Plant Kraft Units 1 through 4 (316 MWs) were retired.

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. On September 18, 2015, 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's next fuel case is expected to be filed a rate request with the Georgia PSC to lower total annual billings by ~~February 27,~~approximately $268 million effective January 1, 2016. The Georgia PSC is scheduled to vote on this matter on December 15, 2015. The ultimate outcome of this matter cannot be 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~~Nuclear Construction

See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Storm Damage Recovery" of Georgia Power in Item 7 and~~ Note 13 to the financial statements of Georgia Power under ~~"Storm Damage Recovery"~~"Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional ~~information.~~information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, and pending litigation.

In 2008, Georgia Power, ~~defers~~acting for itself and ~~recovers certain costs related~~as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to ~~damages from major storms as mandated by~~which the ~~Georgia PSC. As of September 30, 2014 and December 31, 2013, the balance in the regulatory asset related~~Contractor agreed 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.design, engineer, procure,

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~~Nuclear Construction~~construct, and test Plant Vogtle Units 3 and 4. Current anticipated in-service dates for Plant Vogtle Units 3 and 4 are the second quarter 2019 and the second quarter 2020, respectively.

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Nuclear Construction"~~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, 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 ~~in Item 7 and Note 3~~(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 ~~financial statements~~Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.

Certain payment obligations of ~~Georgia Power~~Westinghouse and CB&I Stone & Webster, Inc. (S&W) (formerly known as Stone & Webster, Inc.) under ~~"Retail Regulatory Matters – Nuclear Construction" in Item 8~~the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation (Toshiba) and The Shaw Group Inc. (Shaw Group) (a subsidiary of Chicago Bridge & Iron Company, N.V. (CB&I)), 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 ~~Form 10-K~~Vogtle 3 and ~~Note (B)~~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 ~~Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding the~~ construction and licensing of Plant Vogtle Units 3 and 4, ~~Vogtle Construction Monitoring (VCM) reports,~~at the federal and ~~pending litigation.~~

~~In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3~~state level, 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~~additional challenges may arise as 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 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 the Georgia PSC. Accordingly, Georgia Power's eighth VCM report filed in February 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the construction period are estimated to total approximately $2.0 billion.

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

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 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~~extensions of the guaranteed substantial completion dates of 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. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the decision of the U.S. District Court for the District of Columbia, which had dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The case is pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). 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 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

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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).

On October 27, 2015, Westinghouse and CB&I announced an agreement under which Westinghouse or one of its affiliates will acquire S&W from CB&I, subject to satisfaction of certain conditions to closing. In addition, on October 27, 2015, Westinghouse and the Vogtle Owners entered into a term sheet (Term Sheet) setting forth the terms of a settlement agreement to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation.

In accordance with the Term Sheet: (i) the Vogtle Owners and the Contractor will enter into mutual releases of all open claims which have been asserted, including any potential extension of such open claims, as well as future claims based on events occurring prior to the effective date of the release that potentially could have been asserted under the original terms of the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation, which will be dismissed with prejudice; (ii) the Vogtle 3 and 4 Agreement will be amended to restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (iii) enhanced dispute resolution procedures will be implemented; (iv) the guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement will be revised to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4 (as discussed below); (v) delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (vi) Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. In addition, the Vogtle Owners and the Contractor resolved other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the proposed settlement and in connection with Westinghouse's proposed acquisition of S&W: (i) the Vogtle Owners will terminate the parent guarantee of Shaw Group with respect to certain obligations of S&W, subject to obtaining the consent of the DOE under loan guarantee agreements relating to Plant Vogtle Units 3 and 4, while the parent guarantee of Toshiba with respect to certain obligations of Westinghouse will remain in place; (ii) Westinghouse will make provisions to engage Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (iii) the Vogtle Owners, CB&I, and Shaw Group also will enter into mutual releases of any and all claims against each other arising out of the construction of Plant Vogtle Units 3 and 4.

The settlement of the pending disputes between the Vogtle Owners and the Contractor, including the Vogtle Construction Litigation, is subject to consummation of Westinghouse's proposed acquisition of S&W. If this proposed acquisition is not completed, the Vogtle Construction Litigation will continue and the Contractor may from time to time continue to assert that it is entitled to additional payments with respect to ~~these new~~its allegations, any of which could be substantial.

Georgia Power ~~does not agree~~will submit the ultimate settlement agreement terms and the related amendments to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review.

Georgia Power is required to file semi-annual VCM reports with ~~either~~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. 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.

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Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated owner-related costs, which include approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost ~~or schedule adjustments or~~of Plant Vogtle Units 3 and 4 to $5.0 billion. 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 ~~Vogtle Owners have~~certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any ~~responsibility for~~ costs ~~related to these issues. Litigation is ongoing and~~incurred by Georgia Power ~~intends to vigorously defend the positions~~in excess of the ~~Vogtle Owners.~~certified amount will be included in rate base, provided Georgia Power ~~also expects negotiations~~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.

The Georgia PSC has approved twelve VCM reports covering the periods through December 31, 2014, including construction capital costs incurred, which through that date totaled $3.0 billion. On August 28, 2015, Georgia Power filed its thirteenth VCM report with the ~~Contractor~~Georgia PSC covering the period from January 1 through June 30, 2015, which requested approval for an additional $148 million of construction capital costs incurred during that period and reflected estimated financing costs during the construction period to total approximately $2.4 billion. Georgia Power will continue ~~with respect~~ to ~~cost~~incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and ~~schedule during which negotiations~~4 are placed in service.

On October 30, 2015, Georgia Power filed to increase the ~~parties may reach a mutually acceptable compromise of their positions.~~NCCR tariff by approximately $19 million, effective January 1, 2016, pending Georgia PSC approval.

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~~may 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~~Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) ~~are also likely to~~could 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

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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 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.

Georgia Power previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule discussed above. The cost estimates are based on information 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 for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

for closing ash ponds prior to the end of their currently anticipated useful life, Georgia Power expects to continue 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.

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. Early adoption is permitted and Georgia Power intends to adopt the ASU in the fourth quarter 2015. The ASU is required to be applied retrospectively to all periods presented beginning in the year of adoption. 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 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~~$2.16 billion for the first nine months of ~~2014~~2015 compared to ~~$2.13~~$2.07 billion for the corresponding period in ~~2013.~~2014. The ~~decrease~~increase was primarily due to increased fuel cost recovery, ~~and storm restoration costs,~~ partially offset by ~~higher retail operating revenues and~~ lower ~~fuel inventory additions.~~deferred taxes. Net cash used for investing activities totaled ~~$1.46~~$1.39 billion for the first nine months of ~~2014~~2015 compared to ~~$1.25~~$1.46 billion 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 financing activities totaled ~~$577~~$711 million for the first nine months of ~~2014~~2015 compared to ~~$869~~$577 million ~~used for financing activities~~ in the corresponding period in ~~2013.~~2014. The ~~decrease~~increase in cash used for financing activities is primarily due to an increase in common stock dividends, lower borrowings from the FFB for the construction of Plant Vogtle ~~Units~~ 3 and 4, ~~partially offset by FFB loan issuance costs~~ and a ~~reduction~~redemption and a maturity of senior notes in ~~short-term debt.~~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 nine months of ~~2014~~2015 include increases of ~~$819~~$778 million in property, plant, and equipment ~~$502~~to comply with environmental standards and construction of generation, transmission, and distribution facilities and an increase in other regulatory assets, deferred of $322 million ~~in long-term debt~~ primarily ~~due~~related to ~~borrowings from the FFB,~~AROs and ~~$175 million in~~ deferred ~~under recovered regulatory clause revenues and decreases~~plant retirement costs.

Table of ~~$836 million in short-term debt and $337 million in fossil fuel stock.~~Contents

GEORGIA 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 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~~$1.4 billion will be required through September 30, ~~2015~~2016 to fund maturities 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.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "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 September 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~~As of 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.

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 $1.45 billion primarily due to ~~meet scheduled maturities~~approximately $1.49 billion of long-term debt due within one year and notes payable. Georgia Power intends to utilize operating cash flows, as well as ~~cash needs, which can fluctuate significantly due~~FFB borrowings, 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.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, ~~2014,~~2015, Georgia Power had approximately ~~$63~~$85 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, ~~2014~~2015 were as follows:


Expires^(a)	Expires^(a)								Expires^(a)								Due Within One Year
	2016		2018		Total		Unused
2020									2020	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
$									1,750	$	1,750	$	1,732	$	—	$	—


~~(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.

As reflected in the table above, in August 2015, Georgia Power amended and restated its multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. Georgia Power increased its borrowing ability by $150 million under its facility maturing in 2020 and terminated its aggregate $150 million facilities maturing in 2016.

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 30, ~~2014~~2015 was approximately ~~$865~~$872 million. In addition, at September 30, ~~2014,~~2015, Georgia Power had ~~$65~~$121 million of fixed rate pollution control revenue bonds outstanding that were required to be ~~remarketed~~reoffered within the next 12 months.

~~Georgia Power's~~This bank credit ~~arrangements contain covenants~~arrangement contains a covenant that ~~limit~~limits debt levels and ~~contain~~contains a cross ~~default provisions~~acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such a cross ~~default provisions~~acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, ~~or guarantee obligations over a specified threshold.~~the payment of which was then accelerated. 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~~

~~arrangements~~this covenant. This bank credit arrangement does not contain a material adverse change ~~clauses~~clause at the time of ~~borrowings.~~borrowing.

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

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

Details of short-term borrowings were as follows:



	Short-term Debt at September 30, 2015				Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	130	0.5	%	$	193	0.4	%	$	325


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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

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

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

The maximum potential collateral requirements under these contracts at September 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		1,287

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 the ability of Georgia ~~Power's ability~~Power to access capital markets, ~~particularly~~and would be likely to impact the ~~short-term debt market and~~cost at which it does so.

On August 17, 2015, S&P downgraded the ~~variable rate pollution control revenue bond market.~~consolidated long-term issuer rating of Southern Company (including Georgia Power) to A- from A. S&P revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its credit rating outlook from stable to negative following the announcement of the Merger.

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 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. Georgia Power settled $350 million of interest rate swaps related to this borrowing for a payment of approximately $6 million, which will be amortized to interest expense over 10 years.

In ~~connection with its entry into~~July 2015, $97.925 million aggregate principal amount of the 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~agreements with the DOE and the FFB,~~In August 2015, Georgia ~~Power incurred issuance costs of approximately $66~~Power's $400 million ~~which will be amortized over the life of the borrowings under the FFB Credit Facility.~~

Under the Loan Guarantee Agreement, 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 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.~~Series 2012C 0.75% Senior Notes matured.

~~In June 2014,~~Also in August 2015, in connection with optional tenders, Georgia Power ~~redeemed $17~~repurchased and reoffered to the public $94.6 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), ~~Second~~First Series ~~1998~~2009 and ~~$19.5~~$10 million aggregate principal amount of Development Authority of ~~Appling~~Burke 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 SchererVogtle Project), First Series ~~2009, which had been previously purchased 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.2013.

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

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GULF POWER COMPANY

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended September 30,						For the Nine Months Ended September 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		$	363		$	366		$	983		$	979
Wholesale revenues, non-affiliates	33,689			29,431			103,616			82,533			30			34			82			104
Wholesale revenues, affiliates	20,591			16,701			96,996			65,206			17			21			52			97
Other revenues	18,083			17,313			48,950			47,726			19			17			53			49
Total operating revenues	438,334			399,361			1,228,997			1,096,808			429			438			1,170			1,229
Operating Expenses:
Fuel	164,497			136,216			478,163			397,409			143			164			375			478
Purchased power, non-affiliates	26,813			17,180			56,605			41,369			26			27			76			57
Purchased power, affiliates	3,611			15,829			19,299			30,075			4			4			22			19
Other operations and maintenance	85,097			76,964			250,425			232,472			90			85			274			251
Depreciation and amortization	38,487			37,345			109,354			111,479			40			38			100			109
Taxes other than income taxes	31,229			28,051			83,786			75,437			35			31			91			84
Total operating expenses	349,734			311,585			997,632			888,241			338			349			938			998
Operating Income	88,600			87,776			231,365			208,567			91			89			232			231
Other Income and (Expense):
Allowance for equity funds used during construction	3,195			1,663			8,276			4,318			3			3			11			8
Interest expense, net of amounts capitalized	(12,859		)	(13,988		)	(39,417		)	(42,650		)	(12		)	(13		)	(38		)	(39		)
Other income (expense), net	(627		)	(337		)	(1,857		)	(2,704		)	(1		)	(1		)	(3		)	(2		)
Total other income and (expense)	(10,291		)	(12,662		)	(32,998		)	(41,036		)	(10		)	(11		)	(30		)	(33		)
Earnings Before Income Taxes	78,309			75,114			198,367			167,531			81			78			202			198
Income taxes	29,511			28,109			74,228			62,950			31			29			75			74
Net Income	48,798			47,005			124,139			104,581			50			49			127			124
Dividends on Preference Stock	2,251			2,251			6,752			5,453			2			2			7			7
Net Income After Dividends on Preference Stock	$	46,547		$	44,754		$	117,387		$	99,128		$	48		$	47		$	120		$	117

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



	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income	$	50	$	49	$	127	$	124
Other comprehensive income (loss)	—		—		—		—
Comprehensive Income	$	50	$	49	$	127	$	124

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,						For the Nine Months Ended September 30,
	2014			2013			2015			2014
	(in thousands)						(in millions)
Operating Activities:
Net income	$	124,139		$	104,581		$	127		$	124
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	115,093			116,626			105			115
Deferred income taxes	29,359			55,911			58			29
Allowance for equity funds used during construction	(8,276		)	(4,318		)	(11		)	(8		)
Pension, postretirement, and other employee benefits	5,693			9,279
Stock based compensation expense	1,520			1,389
Other, net	(2,667		)	2,509			16			5
Changes in certain current assets and liabilities —
-Receivables	(45,777		)	(49,690		)	18			(46		)
-Prepayments	2,894			2,568
-Fossil fuel stock	44,300			24,475			18			44
-Materials and supplies	1,007			(2,683		)
-Prepaid income taxes	8,627			23,515			31			9
-Other current assets	(1,022		)	—			1			3
-Accounts payable	10,097			(9,132		)	(13		)	10
-Accrued taxes	21,858			20,648			46			22
-Accrued compensation	5,131			(5,974		)	(3		)	5
-Over recovered regulatory clause revenues	6,834			(17,092		)	10			7
-Other current liabilities	4,939			5,258			8			5
Net cash provided from operating activities	323,749			277,870			411			324
Investing Activities:
Property additions	(254,256		)	(205,161		)	(189		)	(254		)
Cost of removal, net of salvage	(9,309		)	(12,563		)	(9		)	(9		)
Change in construction payables	1,688			6,752			(29		)	2
Payments pursuant to long-term service agreements	(6,097		)	(3,843		)
Other investing activities	89			306			(6		)	(7		)
Net cash used for investing activities	(267,885		)	(214,509		)	(233		)	(268		)
Financing Activities:
Decrease in notes payable, net	(44,395		)	(65,077		)	(34		)	(44		)
Proceeds —
Common stock issued to parent	50,000			40,000			20			50
Capital contributions from parent company	2,873			1,936
Preference stock	—			50,000
Pollution control revenue bonds	42,075			63,000			13			42
Senior notes	200,000			90,000			—			200
Redemptions —
Redemptions and repurchases —
Pollution control revenue bonds	(29,075		)	(63,000		)	(13		)	(29		)
Senior notes	—			(90,000		)	(60		)	—
Payment of preference stock dividends	(6,752		)	(4,753		)	(7		)	(7		)
Payment of common stock dividends	(92,400		)	(86,550		)	(98		)	(92		)
Other financing activities	(2,951		)	(3,209		)	3			(1		)
Net cash provided from (used for) financing activities	119,375			(67,653		)	(176		)	119
Net Change in Cash and Cash Equivalents	175,239			(4,292		)	2			175
Cash and Cash Equivalents at Beginning of Period	21,753			32,167			39			22
Cash and Cash Equivalents at End of Period	$	196,992		$	27,875		$	41		$	197
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
Interest (net of $5 and $4 capitalized for 2015 and 2014, respectively)							$	27		$	29
Income taxes, net	35,940			(17,064		)	(37		)	36
Noncash transactions — accrued property additions at end of period	34,876			30,846
Noncash transactions — Accrued property additions at end of period							17			35

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

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CONDENSED BALANCE SHEETS (UNAUDITED)


Assets	At September 30, 2014			At December 31, 2013			At September 30, 2015			At December 31, 2014
	(in thousands)						(in millions)
Current Assets:
Cash and cash equivalents	$	196,992		$	21,753		$	41		$	39
Receivables —
Customer accounts receivable	98,357			64,884			100			73
Unbilled revenues	63,950			57,282			68			58
Under recovered regulatory clause revenues	52,531			48,282			17			57
Other accounts and notes receivable	10,131			8,620			9			8
Affiliated companies	7,405			8,259			4			10
Accumulated provision for uncollectible accounts	(1,695		)	(1,131		)	(2		)	(2		)
Fossil fuel stock, at average cost	90,750			135,050			84			101
Materials and supplies, at average cost	53,928			54,935			57			56
Other regulatory assets, current	42,683			18,536			81			74
Prepaid expenses	8,374			33,186			13			40
Other current assets	3,805			6,120			1			2
Total current assets	627,211			455,776			473			516
Property, Plant, and Equipment:
In service	4,444,015			4,363,664			4,640			4,495
Less accumulated provision for depreciation	1,277,290			1,211,336			1,273			1,296
Plant in service, net of depreciation	3,166,725			3,152,328			3,367			3,199
Other utility plant, net							64			—
Construction work in progress	433,299			280,626			407			465
Total property, plant, and equipment	3,600,024			3,432,954			3,838			3,664
Other Property and Investments	15,212			15,314			15			15
Deferred Charges and Other Assets:
Deferred charges related to income taxes	54,856			50,597			61			56
Prepaid pension costs	11,639			11,533
Other regulatory assets, deferred	322,370			340,415			430			416
Other deferred charges and assets	38,394			30,982			44			41
Total deferred charges and other assets	427,259			433,527			535			513
Total Assets	$	4,669,706		$	4,337,571		$	4,861		$	4,708

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholder's Equity	At September 30, 2014			At December 31, 2013			At September 30, 2015		At December 31, 2014
	(in thousands)						(in millions)
Current Liabilities:
Securities due within one year	$	75,000		$	75,000
Notes payable	91,483			135,878			$	76	$	110
Accounts payable —
Affiliated	82,258			76,897			65		87
Other	55,713			47,038			40		56
Customer deposits	35,188			34,433			36		35
Accrued taxes —
Accrued income taxes	16,124			45			22		—
Other accrued taxes	29,777			7,486			33		9
Accrued interest	17,808			10,272			20		11
Accrued compensation	16,839			11,657			20		23
Other regulatory liabilities, current	9,136			13,408
Deferred capacity expense, current							22		22
Liabilities from risk management activities	7,337			6,470			41		37
Other current liabilities	41,716			22,972			44		23
Total current liabilities	478,379			441,556			419		413
Long-term Debt	1,369,447			1,158,163			1,310		1,370
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	746,866			734,355			870		800
Accumulated deferred investment tax credits	3,101			4,055
Employee benefit obligations	78,004			76,338			120		121
Other cost of removal obligations	233,926			228,148			226		235
Other regulatory liabilities, deferred	50,859			56,051			49		49
Deferred capacity expense	168,574			180,149			147		163
Other deferred credits and liabilities	78,671			77,126			216		101
Total deferred credits and other liabilities	1,360,001			1,356,222			1,628		1,469
Total Liabilities	3,207,827			2,955,941			3,357		3,252
Preference Stock	146,504			146,504			147		147
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
Outstanding — September 30, 2015: 5,642,717 shares
— December 31, 2014: 5,442,717 shares							503		483
Paid-in capital	557,664			552,681			564		560
Retained earnings	275,481			250,494			290		267
Accumulated other comprehensive loss	(830		)	(1,109		)	—		(1		)
Total common stockholder's equity	1,315,375			1,235,126			1,357		1,309
Total Liabilities and Stockholder's Equity	$	4,669,706		$	4,337,571		$	4,861	$	4,708

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

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER ~~2014~~2015 vs. THIRD 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 quarter ~~2014~~2015 was ~~$46.5~~$48 million compared to ~~$44.7~~$47 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~~$120 million compared to ~~$99.1~~$117 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to higher retail revenues related to a base rate increase and ~~colder weather~~a reduction in depreciation, as authorized by the ~~first quarter 2014,~~Florida PSC, 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 quarter ~~2014,~~2015, retail revenues were ~~$366.0~~$363 million compared to ~~$335.9~~$366 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, retail revenues were ~~$979.4~~$983 million c~~ompared~~compared to ~~$901.3~~$979 million for the corresponding period in ~~2013.~~2014.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:


	Third Quarter 2014					Year-to-Date 2014				Third 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			$	366				$	979
Estimated change resulting from –
Rates and pricing	11.0			3.3		33.6		3.7		8			2.1		18			1.8
Sales growth	6.1			1.8		7.7		0.9
Sales decline										(1		)	(0.3	)	(1		)	(0.1	)
Weather	(0.9		)	(0.3	)	10.0		1.1		4			1.1		8			0.8
Fuel and other cost recovery	13.9			4.1		26.8		3.0		(14		)	(3.7	)	(21		)	(2.1	)
Retail – current year	$	366.0		8.9	%	$	979.4	8.7	%	$	363		(0.8	)%	$	983		0.4	%

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 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, as authorized in a settlement agreement for Gulf Power's 2013 base rate ~~increase effective January 2014 and higher revenues associated with~~case, as well as an increase in the environmental and energy conservation cost recovery clause ~~rate~~rates, both effective in January ~~2014.~~2015.

Revenues attributable to changes in sales ~~increased~~decreased slightly in the third quarter ~~2014~~and year-to-date 2015 when compared to the corresponding ~~period~~periods in ~~2013. Weather-adjusted~~2014. For the third quarter and year-to-date 2015, weather-adjusted KWH energy sales decreased 2.0% and 1.4%, respectively, to residential customers, and decreased 0.6% and 0.3%, respectively, to commercial customers, ~~increased 5.8% and 2.6%, respectively,~~ due to ~~higher weather-adjusted use per~~lower customer ~~and~~usage, partially offset by customer growth. KWH energy sales to industrial customers ~~increased 6.4%~~decreased 2.9% and 2.8% for the third quarter and year-to-date 2015, respectively, primarily due to increased customer co-generation.

Fuel and other cost recovery revenues decreased ~~customer co-generation~~in the third quarter and ~~changes~~year-to-date 2015 when compared to the corresponding periods in ~~customers' operations.~~

~~Revenues attributable~~2014 primarily due to ~~changes in sales increased~~lower revenues associated with fuel costs as the result of decreased generation and lower purchased power energy costs. For year-to-date ~~2014~~2015, the decrease was partially offset by higher revenues associated with purchased power capacity costs 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.

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

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.

~~Table of Contents~~

~~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

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 quarter ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$33.7~~$30 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~~20.2% 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 lower natural gas prices that led to increased generation from customer-owned units.

For y~~ear-to-date 2014,~~year-to-date 2015, wholesale revenues from sales to non-affiliates were ~~$103.6~~$82 million compared to ~~$82.5~~$104 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to a ~~59.9% increase~~41.4% 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 generation from customer-owned units.

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 quarter ~~2014,~~2015, wholesale revenues from sales to affiliates were ~~$20.6~~$17 million compared to ~~$16.7~~$21 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to ~~an 11.7% increase~~a 17.7% 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 $52 million compared to $97 million for the corresponding period in 2014. The decrease was primarily due to a ~~10.3% increase~~29.1% 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~~resources through the ~~corresponding period in 2013. The increase was primarily due to~~second quarter 2015 and a ~~29.6% increase~~24.4% decrease in the price of energy sold to affiliates due to ~~higher marginal generation costs~~lower power pool interchange rates resulting from lower natural gas prices.

Fuel and Purchased Power Expenses



	Third Quarter 2015 vs. Third Quarter 2014					Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(21	)	(12.8	)	$	(103	)	(21.5	)
Purchased power – non-affiliates	(1		)	(3.7	)	19			33.3
Purchased power – affiliates	—			—		3			15.8
Total fuel and purchased power expenses	$	(22	)			$	(81	)

In the third quarter 2015, total fuel and purchased power expenses were $173 million compared to $195 million for the corresponding period in 2014. The decrease was primarily the result of a $20 million decrease due to the lower average cost of fuel and purchased power and a ~~14.8%~~$10 million decrease related to the volume of KWHs generated, partially offset by an $8 million increase in ~~KWH sales that resulted from more Gulf Power generation dispatched~~the volume of KWHs purchased.

For year-to-date 2015, total fuel and purchased power expenses were $473 million compared to ~~serve affiliated companies' higher weather-related energy demand~~$554 million for the corresponding period in 2014. The decrease was primarily the result of a $52 million decrease related to the volume

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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
(change in millions) (% change) (change in millions) (% change)
Fuel $ 28.3
20.8
$ 80.8
20.3
Purchased power – non-affiliates 9.6
56.1
15.2
36.8
Purchased power – affiliates (12.2 ) (77.2 ) (10.8 ) (35.8 )
Total fuel and purchased power expenses $ 25.7
$ 85.2

In the third quarter 2014, total fuel and purchased power expenses were $194.9 million compared to $169.2 million for the corresponding period in 2013. Total fuel and purchased power expenses for the third quarter 2013 included the effect of a 2013 payment received pursuant to 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 Gulf Power generation dispatched to serve affiliated companies' higher weather-related demand. This increase was offset by a ~~$7.3~~$31 million decrease due to athe lower average cost of fuel and purchased ~~power.~~

~~For year-to-date 2014, total fuel and purchased~~ power, ~~expenses were $554.1~~partially offset by a $2 million ~~compared to $468.9 million for the corresponding period in 2013. Total fuel and purchased power expenses for the first nine months of 2013 included the effect of a 2013 payment received pursuant~~increase related to 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 Gulf Power generation dispatched to serve affiliated companies' higher demand as a result of colder weather in the first quarter 2014 and warmer weather in the third quarter 2014 compared to the corresponding periods in 2013. The increased expenses also included a $2.4 million increase due to a higher average cost of fuel and purchased power.purchased.

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	Third Quarter 2015	Third Quarter 2014	Year-to-Date 2015	Year-to-Date 2014
Total generation (millions of KWHs)	3,085	2,692	8,717	6,978	2,839	3,085	7,435	8,717
Total purchased power (millions of KWHs)	1,479	1,593	4,190	4,602	1,637	1,479	4,231	4,190
Sources of generation (percent) –
Coal	66	64	69	62	64	66	61	69
Gas	34	36	31	38	36	34	39	31
Cost of fuel, generated (cents per net KWH) –
Coal^(a)	3.83	3.33	4.08	4.09	3.67	3.83	3.88	4.08
Gas	4.16	4.17	3.95	4.05	4.32	4.16	4.22	3.95
Average cost of fuel, generated (cents per net KWH)^(a)	3.94	3.64	4.04	4.07	3.90	3.94	4.01	4.04
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)^(*)					3.83	4.96	4.12	4.83


~~(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.

~~Table of Contents~~

~~GULF POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Fuel

In the third quarter ~~2014,~~2015, fuel expense was ~~$164.5~~$143 million compared to ~~$136.2~~$164 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was primarily due to an 8.0% decrease in the volume of KWHs generated by Gulf Power's generation resources and a 1.0% decrease in the average cost of fuel due to lower coal prices per KWH generated.

For year-to-date 2015, fuel expense was $375 million compared to $478 million for the corresponding period in 2014. The decrease was primarily due to a ~~14.6% higher~~14.7% decrease in the volume of KWHs generated due to ~~more~~planned outages for Gulf ~~Power~~Power's generation ~~dispatched to serve affiliated companies' higher demand resulting from warmer weather~~and a resource contracted under a PPA and a 1.0% decrease 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~~lower 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.prices per KWH generated.

Purchased Power – Non-Affiliates

In the third quarter ~~2014,~~2015, purchased power expense from non-affiliates was ~~$26.8~~$26 million compared to ~~$17.2~~$27 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to a 22.2% decrease in the average cost per KWH purchased due to lower natural gas prices, partially offset by a 7.7% increase in the volume of KWHs purchased.

For year-to-date 2015, purchased power expense from non-affiliates was $76 million compared to $57 million for the corresponding period in 2014. The increase was primarily due to a ~~30.4% increase in the average cost per KWH purchased, which included a $9.7~~$26 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%~~an 8.2% 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, purchased power expense from non-affiliates was $56.6 million compared to $41.4 million for the corresponding period in 2013. The increase was primarily due to a 34.9% increase in the average cost per KWH purchased, which included a $12.8 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA. This increase was partially offset by an 11.7% 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.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Affiliates

In the third 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.~~$4 million. The ~~decrease was primarily~~volume of KWHs purchased increased 37.9% due to decreased generation from Gulf Power resources. The increase was offset by a ~~67.0%~~13.0% 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~~$22 million compared to ~~$30.1~~$19 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%60.5% 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, offset by a 31.5% 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.

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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,~~2015, other operations and maintenance expenses were ~~$85.1~~$90 million compared to ~~$76.9~~$85 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to increases of ~~$7.0~~$3 million in ~~routine~~employee compensation and ~~planned maintenance expense at generation facilities, partially offset by a decrease of $1.8~~benefits including pension costs, $1 million in customer service expenses, and $1 million in marketing programs.

For year-to-date ~~2014,~~2015, other operations and maintenance expenses were ~~$250.4~~$274 million compared to ~~$232.5~~$251 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to ~~a $20.0~~increases of $9 million ~~increase~~ in routine and planned maintenance expenses at generation ~~transmission, and distribution~~ facilities, ~~a $2.3~~$5 million ~~net increase~~ in employee compensation and benefits including pension costs, ~~a $2.1~~$2 million ~~increase~~ in customer ~~uncollectibles and collection~~service expenses, ~~and a $2.0~~$2 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~~$2 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 expenseExpenses from marketing programs did not have a significant impact on ~~net income~~earnings since ~~the expense was~~they were offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause. ~~The decreased expense~~Expenses 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 quarter 2014,~~For year-to-date 2015, depreciation and amortization was ~~$38.5~~$100 million compared to ~~$37.3~~$109 million for the corresponding period in ~~2013. The increase in depreciation and amortization was primarily attributable to property additions at transmission and distribution facilities.~~

~~For year-to-date 2014, depreciation and amortization was $109.4 million compared to $111.5 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~~$20.5 million reduction in depreciation ~~expense~~in the first nine months 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~~$6 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 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 quarter ~~2014,~~2015, taxes other than income taxes were ~~$31.2~~$35 million compared to ~~$28.0~~$31 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, taxes other than income taxes were ~~$83.8~~$91 million compared to ~~$75.4~~$84 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~~$11 million compared to ~~$1.7~~$8 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 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~~Demand for electricity for Gulf Power is partially driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, ~~may impact sales for Gulf Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and~~which 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 wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's co-ownership of that unit through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively 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. 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.

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wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's ownership of that unit through 2015 and 57% through 2018. The second type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from other Gulf Power resources.

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, the Cross State Air Pollution Rule (CSAPR), and the ~~EPA's proposed rules~~eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.

On June 12, 2015, the EPA published a final rule requiring affected states (including Florida, Georgia, and 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 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 ~~is dependent on~~Georgia. The court's decision leaves the ~~outcome of further legal proceedings,~~emissions trading program in place and remands the ~~manner in which~~rule to the EPA ~~and~~for further action consistent with 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.~~court's decision. 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~~court rejected all other pending challenges to the ~~rule (including Florida, Georgia, and Mississippi) to revise their SSM provisions within 18 months after issuance of the final~~ 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.

~~Water Quality~~

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the

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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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.

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 rule became effective August 28, 2015, but on October 9, 2015, the ~~rule as proposed could have significant impacts on economic development projects which could affect customer demand growth.~~U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the ~~proposed~~final rule will depend on the ~~specific requirements~~outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the ~~final~~ rule ~~and the outcome of any legal challenges~~ 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,~~(CCR Rule) in the Federal Register, which became effective on October ~~14, 2014. The ultimate outcome~~19, 2015. Based on initial cost estimates for closure in place and groundwater monitoring of ~~this final rule will depend on~~ash ponds pursuant to the ~~results~~CCR Rule, during the second quarter 2015, Gulf Power recorded incremental asset retirement obligations (ARO) of ~~additional studies and implementation~~approximately $75 million related to the CCR Rule. As further analysis is performed, including evaluation of the ~~rule by state regulators, but could result in additional capital~~expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and ~~operational costs associated with changes~~the determination of timing, including the potential for closing ash ponds prior to ~~existing intake structures and cooling systems and increased costs associated with~~ the ~~construction~~end of ~~new generating units.~~their currently anticipated useful life, Gulf Power expects to continue to periodically update these estimates. 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. See Note (A) to the Condensed Financial Statements herein for additional information regarding Gulf Power's AROs as of September 30, 2015.

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.

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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, including legal challenges filed by Gulf Power; 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 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 ~~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 Gulf 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, to

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~~tailor~~ the ~~statutory permitting thresholds.~~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 26, 2015 filed their response with the 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

Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.

Retail Base Rate Case

~~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 retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. ~~Gulf Power recognized a $5.4 million reduction in depreciation expense in~~For 2014 and the first nine months of ~~2014.~~2015, Gulf Power recognized reductions in depreciation expense of $8.4 million and $20.5 million, respectively.

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

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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.

On ~~October 22, 2014,~~November 2, 2015, 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.~~2016. The net effect of the approved changes is a ~~$41.2~~$49 million ~~increase~~decrease in annual revenue for ~~2015.~~2016. The ~~increased~~decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses.

~~Retail Fuel Cost Recovery~~Renewables

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery"~~On 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 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.

Asset Retirement Obligations

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a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.

The liability for AROs primarily relates to Gulf Power's facilities that are subject to the CCR Rule and to the closure of an ash pond at Plant Scholz. In addition, Gulf Power has retirement obligations related to various landfill sites, a barge unloading dock, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and combustion turbines at its Pea Ridge facility. 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.

As a result of the final CCR Rule discussed above, Gulf Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information 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 for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Gulf Power expects to continue 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. Early adoption is permitted and Gulf Power intends to adopt the ASU in the fourth quarter 2015. The ASU is required to be applied retrospectively to all periods presented beginning in the year of adoption. 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 30, ~~2014.~~2015. Gulf 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. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled ~~$323.7~~$411 million for the first nine months of ~~2014~~2015 compared to ~~$277.9~~$324 million for the corresponding period in ~~2013.~~2014. The ~~$45.8~~$87 million increase in net cash was primarily due to ~~changes in cash flows~~increased revenue collection related to ~~clause~~cost recovery ~~a decrease in~~clauses and the timing of income tax payments and refunds associated with bonus depreciation, partially offset by the timing of payments for accounts payable and fossil fuel stock ~~and an increase in accounts payable, offset by a decrease in deferred income taxes.~~purchases. Net cash used for investing activities totaled ~~$267.9~~$233 million in the first nine months of ~~2014~~2015 primarily due to property additions to utility plant. Net cash ~~provided from~~used for financing activities totaled ~~$119.4~~$176 million for the first nine months of ~~2014~~2015 primarily due to ~~the issuance~~payments for common stock dividends and redemptions of long-term debt and ~~common stock,~~notes payable, partially offset by cash received for the ~~payment~~issuance of common stock ~~dividends, notes payable, and the redemption of long-term debt.~~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 months of ~~2014~~2015 include increases of ~~$211.3 million in long-term debt, $175.2 million in cash and cash equivalents, $167.1~~$174 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~~

$115 million in ~~common stock due~~other deferred credits and liabilities primarily related to ~~the issuance~~AROs, and $70 million in accumulated deferred income tax liabilities primarily related to bonus depreciation. Other significant changes include decreases of ~~common stock to Southern Company. Decreases included $44.4~~$60 million in long-term debt, $40 million in under recovered regulatory clause revenues, and $34 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 million was required~~There are no scheduled maturities of long-term debt through September 30, ~~2015 to fund maturities of long-term debt. Subsequent to September 30, 2014, Gulf Power repaid at maturity the $75 million of securities due within one year.~~2016. 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 30, ~~2014,~~2015, Gulf Power had approximately ~~$197.0~~$41 million of cash and cash equivalents. Committed credit arrangements with banks at September 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 are 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 September 30, 2015 was approximately $82 million. In addition, at September 30, 2015, Gulf Power had approximately $33 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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~~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 September 30, 2015				Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	76	0.4	%	$	91	0.4	%	$	125
Short-term bank debt	—		—	%	30		0.7	%	40
Total	$	76	0.4	%	$	121	0.4	%


~~(a)~~(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

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

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

The maximum potential collateral requirements under these contracts at September 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		485

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 the ability of Gulf ~~Power's ability~~Power to access capital markets, ~~particularly~~and would be likely to impact the ~~short-term debt market~~cost at which it does so.

On August 17, 2015, S&P downgraded the consolidated long-term issuer rating of Southern Company (including Gulf Power) to A- from A and revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its credit rating outlook from stable to negative following the ~~variable rate pollution control revenue bond market.~~announcement of the Merger.

Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the third 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 ~~loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075~~$40 million aggregate principal amount ~~of Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 for the benefit of Gulf Power.~~three-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used ~~to redeem $29.075 million aggregate principal amount~~for credit support, working capital, and other general corporate purposes. The loan was repaid at maturity.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In ~~June 2014,~~July 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.

In September ~~2014,~~2015, Gulf Power ~~issued $200~~redeemed $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~~2035.

Subsequent to September 30, ~~2014, for repayment at maturity $75 million aggregate principal~~2015, Gulf 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 ~~Gulf Power's Series K 4.90% Senior Notes due October 1, 2014.~~the swaps totaled $80 million.

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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CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended September 30,						For the Nine Months Ended September 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		$	244		$	228		$	601		$	647
Wholesale revenues, non-affiliates	82,952			82,937			254,642			219,984			76			83			216			255
Wholesale revenues, affiliates	38,639			6,999			81,593			31,242			18			39			63			82
Other revenues	4,701			4,560			13,829			13,075			3			5			13			13
Total operating revenues	354,623			325,206			996,759			877,575			341			355			893			997
Operating Expenses:
Fuel	168,708			138,148			458,976			384,905			130			169			359			459
Purchased power, non-affiliates	3,475			2,077			16,163			5,222			1			3			5			16
Purchased power, affiliates	1,966			14,691			16,630			28,302			1			2			6			17
Other operations and maintenance	65,758			56,907			191,923			166,175			63			67			206			192
Depreciation and amortization	23,382			22,202			70,318			67,644			38			23			95			70
Taxes other than income taxes	22,344			21,071			63,198			60,760			24			22			71			63
Estimated loss on Kemper IGCC	418,000			150,000			798,000			1,062,000			150			418			182			798
Total operating expenses	703,633			405,096			1,615,208			1,775,008			407			704			924			1,615
Operating Income (Loss)	(349,010		)	(79,890		)	(618,449		)	(897,433		)	(66		)	(349		)	(31		)	(618		)
Other Income and (Expense):
Allowance for equity funds used during construction	32,223			32,624			107,685			87,740			29			32			82			108
Interest expense, net of amounts capitalized	(9,416		)	(8,728		)	(34,071		)	(29,526		)	(13		)	(9		)	6			(34		)
Other income (expense), net	(7,764		)	(375		)	(11,496		)	(4,184		)	(2		)	(8		)	(5		)	(12		)
Total other income and (expense)	15,043			23,521			62,118			54,030			14			15			83			62
Earnings (Loss) Before Income Taxes	(333,967		)	(56,369		)	(556,331		)	(843,403		)	(52		)	(334		)	52			(556		)
Income taxes (benefit)	(139,330		)	(32,687		)	(253,007		)	(355,156		)	(31		)	(139		)	(11		)	(253		)
Net Income (Loss)	(194,637		)	(23,682		)	(303,324		)	(488,247		)	(21		)	(195		)	63			(303		)
Dividends on Preferred Stock	433			433			1,299			1,299			—			—			1			2
Net Income (Loss) After Dividends on Preferred Stock	$	(195,070	)	$	(24,115	)	$	(304,623	)	$	(489,546	)	$	(21	)	$	(195	)	$	62		$	(305	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013			2015			2014			2015		2014
	(in thousands)						(in thousands)						(in millions)						(in millions)
Net Income (Loss)	$	(194,637	)	$	(23,682	)	$	(303,324	)	$	(488,247	)	$	(21	)	$	(195	)	$	63	$	(303	)
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
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $- and $-, respectively													—			—			1		—
Total other comprehensive income (loss)	212			212			637			637			—			—			1		—
Comprehensive Income (Loss)	$	(194,425	)	$	(23,470	)	$	(302,687	)	$	(487,610	)	$	(21	)	$	(195	)	$	64	$	(303	)

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

For the 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 Nine Months Ended September 30,
	2015			2014
	(in millions)
Operating Activities:
Net income (loss)	$	63		$	(303	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	94			78
Deferred income taxes	518			159
Investment tax credits	25			(108		)
Allowance for equity funds used during construction	(82		)	(108		)
Regulatory assets associated with Kemper IGCC	(56		)	(52		)
Estimated loss on Kemper IGCC	182			798
Income taxes receivable, non-current	(544		)	—
Other, net	7			10
Changes in certain current assets and liabilities —
-Receivables	7			(48		)
-Fossil fuel stock	5			36
-Prepaid income taxes	(1		)	(90		)
-Other current assets	(8		)	(4		)
-Accounts payable	(32		)	28
-Accrued taxes	24			(17		)
-Accrued interest	(6		)	24
-Accrued compensation	(8		)	8
-Over recovered regulatory clause revenues	59			(18		)
-Mirror CWIP	99			112
-Other current liabilities	3			—
Net cash provided from operating activities	349			505
Investing Activities:
Property additions	(626		)	(986		)
Construction payables	(31		)	(40		)
Investment in restricted cash	—			(11		)
Distribution of restricted cash	—			9
Other investing activities	(29		)	(22		)
Net cash used for investing activities	(686		)	(1,050		)
Financing Activities:
Increase in notes payable, net	475			—
Proceeds —
Capital contributions from parent company	153			311
Bonds — Other	—			23
Interest-bearing refundable deposit	—			75
Long-term debt issuance to parent company	—			220
Other long-term debt issuances	—			250
Short-term borrowings	30			—
Redemptions —
Long-term debt to parent company	—			(220		)
Other long-term debt	(350		)	—
Payment of preferred stock dividends	(1		)	(1		)
Return of capital	—			(165		)
Other financing activities	(7		)	(3		)
Net cash provided from financing activities	300			490
Net Change in Cash and Cash Equivalents	(37		)	(55		)
Cash and Cash Equivalents at Beginning of Period	133			145
Cash and Cash Equivalents at End of Period	$	96		$	90
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $58 and $55, net of $52 and $50 capitalized for 2015 and 2014, respectively)	$	6		$	5
Income taxes, net	(55		)	(210		)
Noncash transactions —
Accrued property additions at end of period	83			124
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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CONDENSED BALANCE SHEETS (UNAUDITED)


Assets	At September 30, 2014			At December 31, 2013			At September 30, 2015			At December 31, 2014
	(in thousands)						(in millions)
Current Assets:
Cash and cash equivalents	$	89,946		$	145,165		$	96		$	133
Receivables —
Customer accounts receivable	53,593			40,978			51			43
Unbilled revenues	38,575			38,895			42			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			31			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			72			62
Other regulatory assets, current	53,854			52,496			119			73
Prepaid income taxes	162,790			34,751			183			191
Other current assets	4,676			9,357			10			6
Total current assets	609,510			516,776			709			704
Property, Plant, and Equipment:
In service	4,323,501			3,458,770			4,475			4,378
Less accumulated provision for depreciation	1,149,432			1,095,352			1,215			1,173
Plant in service, net of depreciation	3,174,069			2,363,418			3,260			3,205
Construction work in progress	1,987,789			2,586,031			2,596			2,161
Total property, plant, and equipment	5,161,858			4,949,449			5,856			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			278			226
Other regulatory assets, deferred	255,430			200,620			460			385
Accumulated deferred income taxes	25,255			—
Income taxes receivable, non-current							544			—
Other deferred charges and assets	54,929			36,673			60			71
Total deferred charges and other assets	532,892			377,127			1,342			682
Total Assets	$	6,311,123		$	5,848,209		$	7,913		$	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 September 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							500			—
Interest-bearing refundable deposits							—			275
Accounts payable —
Affiliated	90,488			70,299			91			86
Other	177,212			210,191			109			178
Customer deposits	14,946			14,379
Accrued taxes —
Accrued income taxes	92,018			5,590			288			142
Other accrued taxes	65,375			77,958			67			84
Accrued interest	70,956			47,144			15			76
Accrued compensation	17,317			9,324			18			26
Other regulatory liabilities, current	10,138			24,981
Over recovered regulatory clause liabilities	—			18,358			60			1
Mirror CWIP							369			271
Other current liabilities	21,634			21,413			87			61
Total current liabilities	1,596,835			663,426			2,033			1,978
Long-term Debt	1,633,394			2,167,067
Long-term Debt:
Long-term debt, affiliated							301			—
Long-term debt, non-affiliated							1,621			1,630
Total Long-term Debt							1,922			1,630
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	159,061			72,808			674			285
Deferred credits related to income taxes	6,639			9,145
Accumulated deferred investment tax credits	283,382			284,248			5			283
Employee benefit obligations	94,539			94,430			147			148
Asset retirement obligations	42,624			41,197			150			48
Unrecognized tax benefits							361			2
Other cost of removal obligations	162,274			151,340			171			166
Other regulatory liabilities, deferred	263,531			140,880			66			64
Other deferred credits and liabilities	15,037			14,337			48			36
Total deferred credits and other liabilities	1,027,087			808,385			1,622			1,032
Total Liabilities	4,257,316			3,638,878			5,577			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			2,767			2,612
Accumulated deficit	(534,493		)	(229,871		)	(496		)	(559		)
Accumulated other comprehensive loss	(7,227		)	(7,864		)	(6		)	(7		)
Total common stockholder's equity	2,021,027			2,176,551			2,303			2,084
Total Liabilities and Stockholder's Equity	$	6,311,123		$	5,848,209		$	7,913		$	6,757

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

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER ~~2014~~2015 vs. THIRD 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 $6.43 billion, which includes approximately $5.11 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~~cost estimate above the ~~Kemper IGCC~~cost cap of ~~$418.0~~$150 million ($~~258.1~~93 million after tax) in the third quarter ~~2014 resulting in an estimated probable loss~~2015 and a total of ~~$798.0~~$182 million ($~~492.8~~112 million after tax) for the ~~first~~ nine months ~~of 2014. In~~ended September 30, 2015. Since 2012, in the aggregate, Mississippi Power has incurred charges of ~~$1.98~~$2.23 billion ($~~1.22~~1.4 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 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~~While the expected in-service date for the remainder of the Kemper IGCC is ~~currently expected to occur~~ in the first half of ~~2016.~~2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, which would result in Mississippi Power being required to recapture the investment tax credits that were allocated to the Kemper IGCC under Section 48A (Phase II) of the Internal Revenue Code. The ~~revised~~current cost estimate ~~above~~ includes costs through ~~March 31,~~June 30, 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) reversed the Mississippi PSC's March 2013 order that authorized collection of $156 million annually (2013 MPSC Rate Order) to be recorded as Mirror CWIP and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

collected. Following the Court's rejection of both Mississippi Power's and the Mississippi PSC's motions for rehearing, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Refunds of the $342 million collected by Mississippi Power through July 2015 billings, plus carrying costs, will begin in early November 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, Mississippi Power filed a rate case on May 15, 2015 (2015 Rate Case) that 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).

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. In connection with the termination of the APA, on June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million ($275 million in deposits plus interest) to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

The return of approximately $301 million to SMEPA in June 2015 in connection with the termination of the APA, the required refund of the approximately $369 million of Mirror CWIP rate collections, including associated carrying costs through September 30, 2015, the termination of the Mirror CWIP rates, and the likely repayment of approximately $235 million of unrecognized tax benefits associated with the Phase II tax credits to the IRS if the in-service date of the Kemper IGCC extends beyond April 19, 2016 have adversely impacted Mississippi Power's financial condition.

As a result of the Court's decision and these financial impacts, on July 10, 2015, Mississippi Power submitted a supplemental filing with the Mississippi PSC that included 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 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, and is designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September (on August 19), subject to refund and certain other conditions. In addition, the Mississippi PSC reserved the right to modify or terminate the interim rates based upon a material change in circumstances. The Mississippi PSC is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.

As of September 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $1.3 billion primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, the required refund of approximately $369 million in Mirror CWIP, which includes associated carrying costs through September 30, 2015, and the likely repayment of the Phase II tax credits of $235 million as of September 30, 2015. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" and Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits – Investment Tax Credits" herein for additional information. Mississippi Power is primarily dependent upon Southern Company to meet its financing needs. 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power's current liabilities exceeded current assets by approximately $1 billion at September 30, 2014, primarily because of securities due within a year. Management intends to utilize 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 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 meaningful

Mississippi Power's net loss after dividends on preferred stock for the third quarter ~~2014~~2015 was ~~$195.1~~$21 million compared to ~~$24.1~~$195 million for the corresponding period in ~~2013.~~2014. The change was primarily related to ~~a $418.0~~lower pre-tax charges of $150 million ~~pre-tax charge~~ ($~~258.1~~93 million after tax) in the third quarter 2015 compared to $418 million ($258 million after tax) in the third quarter 2014 ~~compared to a $150.0 million pre-tax charge ($92.6 million after tax) in the third quarter 2013~~ 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~~increase in net income was also related to an increase in retail revenue due to the implementation of interim rates that became effective with the first billing cycle in September (on August 19), partially offset by ~~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~~associated with the Kemper IGCC cost recovery ~~that became effective on March 19, 2013.~~recognized in 2014, prior to the 2015 Mississippi Supreme Court decision. The change in net income was also related to a decrease in non-fuel operations and maintenance expenses, decrease in other income and deductions, a decrease in AFUDC, an increase in depreciation and amortization, and an increase in interest expense.

For year-to-date ~~2014, the~~2015, net ~~loss~~income after dividends on preferred stock was ~~$304.6~~$62 million compared to ~~$489.5~~a net loss of $305 million for the corresponding period in ~~2013.~~2014. The ~~change~~increase was primarily related to ~~a $798.0~~$182 million in pre-tax ~~charge~~charges ($~~492.8~~112 million after tax) in ~~2014~~2015 compared to ~~$1.06 billion~~$798 million in pre-tax charges ($~~655.8~~493 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 in ~~AFUDC equity primarily related~~retail revenue due to the ~~construction~~implementation of interim rates that became effective with the ~~Kemper IGCC~~first billing cycle in September (on August 19) and ~~an increase~~a decrease in ~~revenues~~interest expense primarily due to ~~retail and wholesale base rate increases and~~ the ~~recognition as revenue of~~SMEPA termination, partially offset by a ~~portion~~decrease in Kemper revenues primarily resulting from the termination of the ~~retail~~Mirror CWIP rate, ~~increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013. The change was partially offset by~~a decrease in AFUDC equity, increases in non-fuel operations and maintenance ~~expenses.~~expenses, and an increase in depreciation and amortization.

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. Also see "Interest Expense, Net of Amounts Capitalized" herein for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 quarter ~~2014,~~2015, retail revenues were ~~$228.3~~$244 million compared to ~~$230.7~~$228 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, retail revenues were ~~$646.7~~$601 million compared to ~~$613.3~~$647 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					Third 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				$	228				$	647
Estimated change resulting from –
Rates and pricing	2.8			1.2		16.4			2.7		24			10.5		15			2.3
Sales decline	(3.3		)	(1.4	)	(3.6		)	(0.6	)
Sales growth (decline)											1			0.4		(4		)	(0.6	)
Weather	4.8			2.1		6.3			1.0		—			—		1			0.2
Fuel and other cost recovery	(6.7		)	(2.9	)	14.3			2.3		(9		)	(3.9	)	(58		)	(9.0	)
Retail – current year	$	228.3		(1.0	)%	$	646.7		5.4	%	$	244		7.0	%	$	601		(7.1	)%

Revenues associated with changes in rates and pricing increased in the third quarter ~~2014~~2015 when compared to the corresponding period in ~~2013~~2014, primarily due to $28 million for the ~~collection~~implementation of interim rates associated with the Kemper IGCC that became effective with the first billing cycle in September (on August 19), partially offset by $5 million associated with the Kemper IGCC cost recovery ~~revenues,~~recognized in the ~~majority of which were deferred to a regulatory liability. The collected revenue for~~ third quarter 2014, ~~was $47.6 million compared~~prior to ~~$37.0 million for~~ the ~~corresponding period in 2013, with deferrals of $41.8 million in 2014 and $34.0 million in 2013.~~2015 Mississippi Supreme Court decision.

Revenues associated with changes in rates and pricing increased year-to-date ~~2014~~2015 when compared to the corresponding period in ~~2013~~2014, primarily due to $28 million for the ~~collection~~implementation of interim rates associated with the Kemper IGCC that became effective with the first billing cycle in September (on August 19) and $3 million of net revenues associated with the new energy efficiency cost recovery rate, which began in the fourth quarter 2014. These increases were partially offset by $16 million associated with the Kemper IGCC cost recovery revenues, 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 millionrecognized in 2014, ~~and $60.1 million in 2013. Also contributing~~prior to the ~~increase was a $4.7 million refund in 2013 related to the annual PEP lookback filing.~~2015 Mississippi Supreme Court decision.

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~~increased in the third quarter ~~and year-to-date 2014~~2015 when compared to the corresponding ~~periods~~period in ~~2013.~~2014. Weather-adjusted KWH sales to residential customers increased 0.4% in the third quarter 2015 due to an increase in customers and customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.6% in the third quarter 2015 due to lower customer usage slightly offset by an increase in customers. KWH sales to industrial customers increased 0.8% in the third quarter 2015 due to increased usage by larger customers related to increased production.

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~~0.6% 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~~0.3% 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~~1.1% primarily due to increased usage by larger customers.

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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 third quarter and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without these adjustments, third quarter 2015 weather-adjusted residential KWH sales decreased 0.3%, weather-adjusted commercial KWH sales increased 3.8%, and industrial KWH sales increased 0.9% as compared to the corresponding period in 2014. Also, without these adjustments, year-to-date 2015 weather-adjusted residential KWH sales decreased 2.1%, weather-adjusted commercial KWH sales decreased 1.8%, and industrial KWH sales increased 0.3% as compared to the corresponding period in 2014.

Fuel and other cost recovery revenues decreased in the third 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 and – FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.

In the third quarter ~~2014,~~2015, wholesale revenues from sales to non-affiliates were ~~$83.0~~$76 million compared to ~~$82.9~~$83 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~~$216 million compared to ~~$220.0~~$255 million for the corresponding period in ~~2013.~~2014. The ~~increase was~~decreases were primarily due to a ~~$17.2 million increase~~decrease in ~~base~~energy revenues primarily resulting from ~~wholesale base rate increases effective April 1, 2013 and May 1, 2014 and a $17.4 million increase in energy revenues, of which $5.1 million was primarily associated with higher~~lower fuel 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.prices.

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 quarter 2014, wholesale revenues from sales to affiliates were $38.6 million compared to $7.0 million for the corresponding period in 2013. The increase was due to a $33.7 million increase in energy revenues

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~~primarily due to placing~~In the Kemper IGCC combined cycle 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, partially offset by a $2.1 million decrease in capacity revenues.

~~For year-to-date 2014,~~third quarter 2015, wholesale revenues from sales to affiliates were ~~$81.6~~$18 million compared to ~~$31.2~~$39 million for the corresponding period in ~~2013.~~2014. The ~~increased revenues were driven by $48.0~~decrease was due to a $16 million ~~associated with an increase~~decrease in KWH sales ~~primarily~~resulting from a decrease in sales from coal generation and a $5 million decrease associated with lower natural gas prices.

For year-to-date 2015, wholesale revenues from sales to affiliates were $63 million compared to $82 million for the corresponding period in 2014. The decrease was due to ~~higher~~a $20 million decrease associated with 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~~$1 million ~~decrease~~increase in ~~capacity revenues.~~KWH sales due to an increase in generation partially as a result of the Kemper IGCC combined cycle being in service since August 2014.

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~~



	Third Quarter 2015 vs. Third Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(39	)	(23.1)	$	(100	)	(21.8	)
Purchased power – non-affiliates	(2		)	(66.7)	(11		)	(68.8	)
Purchased power – affiliates	(1		)	(50.0)	(11		)	(64.7	)
Total fuel and purchased power expenses	$	(42	)		$	(122	)

In the third quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$174.1~~$132 million compared to ~~$154.9~~$174 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was due to a ~~$39.4~~$22 million ~~increase~~decrease in the ~~total~~ volume of KWHs generated ~~partially offset by~~and purchased and a ~~$20.2~~$20 million decrease in the average cost of ~~fuel and purchased power.~~fuel.

For year-to-date ~~2014,~~2015, total fuel and purchased power expenses were ~~$491.8~~$370 million compared to ~~$418.4~~$492 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~~$89 million decrease in the average cost of fuel and purchased ~~power.~~power and a $33 million decrease in the volume of KWHs generated and purchased.

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	Third Quarter 2015	Third 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)^(*)					4,681	5,022	13,136	12,996
Total purchased power (millions of KWHs)	125	469	591	1,070	121	125	427	591
Sources of generation (percent)^(a) –
Sources of generation (percent)^(*) –
Coal	43	43	45	38	19	43	20	45
Gas	57	57	55	62	81	57	80	55
Cost of fuel, generated (cents per net KWH) –
Coal	3.97	5.12	4.12	5.01	3.81	3.97	3.70	4.12
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^(*)					2.72	3.20	2.70	3.45
Average cost of fuel, generated (cents per net KWH)^(*)					2.93	3.55	2.91	3.77
Average cost of purchased power (cents per net KWH)^(*)					2.21	4.36	2.42	5.55


~~(a)~~(*)	Includes energy produced during the test period for the Kemper IGCC which is accounted for in accordance with FERC guidance.

Fuel

In the third quarter 2015, fuel expense was $130 million compared to $169 million for the corresponding period in 2014. The decrease was due to a 17.4% decrease in the average cost of fuel per KWH generated primarily due to

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~~Fuel~~higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower natural gas prices and a 6.4% decrease in the volume of KWHs generated. The 6.4% decrease in volume included a decrease in coal-fired generation of 59.1%, partially offset by an increase in gas-fired generation of 36.6%.

~~In the third quarter 2014,~~For year-to-date 2015, total fuel expense was ~~$168.7~~$359 million compared to ~~$138.2~~$459 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%22.8% 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%~~1.2% 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 1.2% increase in ~~the first quarter 2014 as compared to the corresponding period~~volume included an increase in ~~2013,~~gas-fired generation of 53.4%, partially 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 55.7%.

Purchased Power - Non-Affiliates

In the third quarter ~~2014,~~2015, purchased power expense from non-affiliates was ~~$3.5~~$1 million compared to ~~$2.1~~$3 million for the corresponding period in ~~2013.~~2014. For year-to-date 2015, purchased power expense from non-affiliates was $5 million compared to $16 million for the corresponding period in 2014. The ~~increase was~~decreases were primarily the result of a ~~145.8% increase~~decrease in the average cost per KWH purchased ~~partially offset by~~as a ~~32.0% decrease in the volume~~result of ~~KWHs purchased.~~

For year-to-date 2014, purchased power expense from non-affiliates was $16.2 million compared to $5.2 million for the corresponding period in 2013. The increase was primarily due to a 283.8% increase in the average cost per KWH purchased, partially offset by a 19.4% decrease in the volume of KWHs purchased.lower natural gas prices.

Purchased Power - Affiliates

~~In the third quarter 2014,~~For year-to-date 2015, purchased power expense from affiliates was ~~$2.0~~$6 million compared to ~~$14.7~~$17 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to ~~an 83.4%~~a 45.2% 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%~~38.4% decrease in the average cost per KWH ~~purchased.~~

~~For year-to-date 2014,~~ purchased ~~power expense from affiliates was $16.6 million compared to $28.3 million for the corresponding period in 2013. The decrease was primarily due to~~as a ~~52.8% decrease in the volume~~result of ~~KWHs purchased, partially offset by a 24.5% increase in the average cost per KWH purchased.~~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 quarter ~~2014,~~2015, other operations and maintenance expenses were ~~$65.8~~$63 million compared to ~~$56.9~~$67 million for the corresponding period in ~~2013.~~2014. The decrease was primarily due to a $2 million decrease in transmission and distribution expenses mainly related to overhead line maintenance and vegetation management and a $2 million decrease primarily related to uncollectible expenses and customer incentives.

For year-to-date 2015, other operations and maintenance expenses were $206 million compared to $192 million for the corresponding period in 2014. The increase was primarily due to a ~~$4.0~~$7 million increase in generation maintenance expenses including scheduled outages, a $5 million increase in employee compensation and benefits including pension, and ~~labor,~~ a ~~$2.3~~$4 million increase ~~in customer accounting services and sales expenses primarily due~~related to uncollectible expenses and customer incentives, partially offset by a ~~$1.9~~$2 million ~~increase in administrative and general expenses primarily due to an increase in charges from affiliates and a $1.5 million increase~~decrease in transmission and distribution expenses mainly ~~for~~related to overhead line maintenance and vegetation management. ~~These increases were partially offset by a $0.7 million decrease in generation maintenance expenses primarily~~

See Note (F) to the Condensed Financial Statements herein for additional information related to ~~scheduled outages.~~pension costs.

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~~For year-to-date 2014, other operations~~Depreciation and ~~maintenance expenses were $191.9~~Amortization

In the third quarter 2015, depreciation and amortization was $38 million compared to ~~$166.2~~$23 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to ~~an $11.8~~a $9 million increase in ~~employee compensation and benefits and labor,~~amortization of regulatory assets associated with the Kemper IGCC primarily as a ~~$10.5 million increase~~result of interim rates that became effective with the first billing cycle in ~~generation maintenance expenses primarily related to scheduled outages,~~September (on August 19), and a ~~$2.7 million increase in transmission and distribution maintenance expenses primarily for overhead line maintenance, vegetation management and equipment maintenance.~~

~~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 quarter 2014, depreciation and amortization was $23.4 million compared to $22.2 million for the corresponding period in 2013. The $1.2 million increase was primarily due to a $0.6~~$6 million increase in depreciation related to increases in generation, transmission and ~~transmission~~distribution plant in ~~service and a $0.3 million increase in amortization primarily resulting from the 2013 regulatory deferral associated with the capital lease related to the Kemper IGCC air separation unit.~~service.

For year-to-date ~~2014,~~2015, depreciation and amortization was ~~$70.3~~$95 million compared to ~~$67.6~~$70 million for the corresponding period in ~~2013.~~2014. The ~~$2.7 million~~ increase was primarily due to a ~~$1.6~~$10 million increase in depreciation related to increases in generation, transmission and ~~transmission~~distribution plant in service, ~~and~~ a ~~$1.9~~$10 million increase in ~~the~~amortization of regulatory ~~deferral~~assets associated with the ~~purchase~~Kemper IGCC as a result of interim rates that became effective with the first billing cycle in September (on August 19), and a $2 million increase related to regulatory deferrals associated with 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 the Kemper IGCC.~~

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~~Also, 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 quarter ~~2014,~~2015, taxes other than income taxes were ~~$22.3~~$24 million compared to ~~$21.1~~$22 million for the corresponding period in 2013. The increase was primarily due to a $1.4 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 million decrease primarily in corporate franchise taxes.

2014. For year-to-date ~~2014,~~2015, taxes other than income taxes were ~~$63.2~~$71 million compared to ~~$60.8~~$63 million for the corresponding period in ~~2013.~~2014. The ~~increase was~~increases were primarily due to ~~a $1.4 million increase~~increases in ad valorem 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 meaningful~~

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In the third ~~quarter~~quarters of 2015 and 2014, ~~and the third quarter 2013,~~ estimated probable losses on the Kemper IGCC of ~~$418.0~~$150 million and ~~$150.0~~$418 million, respectively, were recorded at Mississippi Power. For year-to-date ~~2014~~2015 and year-to-date ~~2013,~~2014, estimated probable losses on the Kemper IGCC of ~~$798.0~~$182 million and ~~$1.06 billion,~~$798 million, 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.

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See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K ~~and 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 third quarter 2015, AFUDC equity was ~~$107.7~~$29 million compared to ~~$87.7~~$32 million for the corresponding period in ~~2013.~~2014. For year-to-date 2015, AFUDC equity was $82 million compared to $108 million for the corresponding period in 2014. The ~~increase was primarily due to $16.8 million related to~~decreases were 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 ~~and $3.2 million related to the Plant Daniel scrubber project.~~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 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.

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)
$0.7 7.9 $4.5 15.4

N/M – Not meaningful

In the third quarter ~~2014,~~2015, interest expense, net of amounts capitalized was ~~$9.4~~$13 million compared to ~~$8.7~~$9 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to a ~~$2.5~~decrease of $6 million ~~increase~~in capitalized interest primarily 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~~placing the Kemper IGCC combined cycle in service in August 2014, a ~~$1.9~~$3 million increase due to the issuances of new debt, and a $2 million increase related to the Mirror CWIP 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~~$7 million decrease related to the 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.

For year-to-date 2015, interest expense, net of amounts capitalized was $(6) million compared to $34 million for the corresponding period in 2014. The decrease was primarily due to a $50 million decrease related to the termination of the APA between Mississippi Power and SMEPA which also required the return of SMEPA's deposits at a lower rate of interest than accrued. Also contributing to the decrease was a $2 million increase in capitalized interest primarily resulting from ~~AFUDC debt and~~ carrying costs related to the Kemper IGCC, ~~and a $0.9~~partially offset by increases of $7 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 Mirror CWIP regulatory liability ~~for Kemper IGCC rate recovery,~~ and ~~a $3.7~~$5 million ~~increase associated with~~due to the 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,~~2015, other income (expense), net was ~~$(7.8)~~$(2) million compared to ~~$(0.4)~~$(8) million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, other income (expense), net was ~~$(11.5)~~$(5) million compared to ~~$(4.2)~~$(12) million for the corresponding period in ~~2013.~~2014. These changes in expense were primarily due to a settlement

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with the Sierra Club in 2014. See ~~"Other Matters~~MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Sierra Club Settlement Agreement" ~~and Note (B) to~~of Mississippi Power in Item 8 of the ~~Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein~~Form 10-K 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,~~2015, income tax benefits were ~~$139.3~~$31 million compared to ~~$32.7~~$139 million for the corresponding period in ~~2013.~~2014. For year-to-date ~~2014,~~2015, income tax benefits were ~~$253.0~~$11 million compared to ~~$355.2~~$253 million for the corresponding period in ~~2013. These~~2014. The changes ~~were~~ primarily reflect a reduction in tax benefits related to the estimated probable losses ~~recorded~~ on ~~the~~ construction of the Kemper ~~IGCC.~~IGCC and a decrease in non-taxable AFUDC equity related to placing the Kemper IGCC combined cycle in service in August 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~~Demand for electricity for Mississippi Power is partially driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, ~~may impact sales for Mississippi Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and~~which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely ~~basis.~~basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could

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negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million, excluding the reserve for cost of removal, and has been reclassified to other regulatory assets, deferred, 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters –

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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.

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.

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, the Cross State Air Pollution Rule (CSAPR), and the ~~EPA's proposed rules~~eight-hour National Ambient Air Quality Standard (NAAQS) for ozone.

On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama and 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 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 ~~is dependent on~~remands the ~~outcome of further legal proceedings, the manner in which~~rule to the EPA ~~and~~for further action consistent with 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.~~court's decision. 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~~court rejected all other pending challenges to the ~~rule (including Alabama and Mississippi) to revise their SSM provisions within 18 months after issuance of the final~~ 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.

~~See "PSC Matters~~ – ~~Environmental Compliance Overview Plan"~~On October 26, 2015, the EPA published a more stringent eight-hour NAAQS for ozone. This new standard could potentially require additional emission controls, improvements in control efficiency, and ~~"Other Matters~~ – ~~Sierra Club Settlement Agreement"~~operational fuel changes and ~~Note (B) to~~could affect the ~~Condensed Financial Statements under "PSC Matters~~ – ~~Environmental Compliance Overview Plan" and "Other Matters~~ – ~~Sierra Club Settlement Agreement" herein for additional information regarding~~siting of new generating ~~unit retirement, repowering, and/or conversion.~~

facilities. The ultimate ~~outcome~~impact of ~~these matters~~this matter will depend on any legal challenges and implementation of the final rule and cannot be determined at this time.

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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' rule revising the definition of waters of the U.S. under the Clean Water Act (CWA) and the EPA's revisions to effluent guidelines.

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 became effective August 28, 2015, but on October 9, 2015, the ~~rule as proposed could have significant impacts on economic development projects which could affect customer demand growth.~~U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the ~~proposed~~final rule will depend on the ~~specific requirements~~outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the ~~final~~ rule ~~and the outcome of any legal challenges~~ 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 Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's ~~rulemaking~~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, which became effective on October 19, 2015. Based on initial cost estimates for ~~cooling water intake structures.~~closure in place and groundwater monitoring of ash ponds pursuant to the CCR Rule, during the second quarter 2015, Mississippi Power recorded incremental asset retirement obligations (ARO) of approximately $95 million related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Mississippi Power expects to continue to periodically update these estimates. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Mississippi Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. See Note (A) to the Condensed Financial Statements herein for additional information regarding Mississippi Power's AROs as of September 30, 2015.

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 proposed regulation of CO₂ from fossil-fuel-fired electric generating units.

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~~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.

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, including legal challenges filed by Mississippi Power; 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 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.

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 ~~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.

Under a 2014 settlement agreement, an adjustment to Mississippi Power's wholesale revenue requirement was allowed in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore, Mississippi Power has recorded a regulatory asset as a result of a portion of the Kemper IGCC being placed in service prior to the projected date and is amortizing this regulatory asset over the nine months ending December 31, 2015.

On May 13, 2015, the FERC accepted a settlement agreement between Mississippi Power and its wholesale customers to forgo a Municipal and Rural Associations (MRA) cost-based electric tariff increase by, among other things, increasing the accrual of AFUDC and lowering the portion of CWIP in rate base, effective April 1, 2015. The additional resulting AFUDC is estimated to be approximately $13 million annually, of which $10 million relates to the Kemper IGCC.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor and a wholesale MRA emissions cost recovery factor. At September 30, 2015, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $14 million compared to $0.2 million at December 31, 2014. 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 additional information.

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

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continued reliance on the energy auction as tailored mitigation. On ~~March 31, 2014,~~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 ~~reached~~to show why market-based rate authority should not be revoked in these areas or to provide a ~~settlement agreement with its wholesale customers~~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~~FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Mississippi Power's rates and charges for ~~an increase in~~service to retail customers are subject to the ~~Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, approved by~~regulatory oversight of the ~~FERC on May 20, 2014, provides that~~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 fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the ~~MRA cost-based electric tariff will increase approximately $10.1 million annually,~~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 cannot be determined at~~ this ~~time.~~

~~Environmental Compliance Overview Plan~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Compliance Overview Plan" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information regarding the CPCN to construct a scrubber on Plant Daniel Units 1 and 2.

On August 1, 2014, Mississippi Power entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On August 28, 2014, the Chancery Court dismissed the appeal.

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from

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environmental regulations. As of September 30, 2014, $5.5 million of Plant Greene County CWIP had been reclassified as a regulatory asset. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Greene County and Watson. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Mississippi Power in Item 7 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,~~2015, the amount of ~~under~~over recovered retail fuel costs included on ~~Mississippi Power's Condensed Balance Sheet herein~~its balance sheet was ~~$13.1~~$44 million compared to ~~over~~under recovered retail fuel costs of ~~$14.5~~$2 million at December 31, ~~2013.~~2014.

Ad Valorem Tax Adjustment

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Ad Valorem Tax Adjustment" of Mississippi Power in Item 7 of the Form 10-K for additional information.~~

On ~~May 6, 2014,~~September 1, 2015, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing ~~for 2014,~~effective September 18, 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.

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

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from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO₂ pipeline infrastructure for the planned transport of captured CO₂ for use in enhanced oil recovery.

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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 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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Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court's decision), and actual costs incurred as of September 30, ~~2014~~2015, as adjusted for the ~~Kemper IGCC~~Court's decision, are as follows:


Cost Category	2010 Project Estimate^(f)		Current Estimate		Actual Costs at September 30, 2014		2010 Project Estimate^(f)		Current Estimate^(a)		Actual Costs
	(in billions)						(in billions)
Plant Subject to Cost Cap^(a)(g)	$	2.40	$	4.86	$	4.06	$	2.40	$	5.11	$	4.66
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
AFUDC^(c)							0.17		0.66		0.55
Combined Cycle and Related Assets Placed in Service – Incremental^(d)(g)	—		—		—		—		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^(e)(g)							—		0.20		0.17
Total Kemper IGCC^(c)	$	2.97	$	6.10	$	4.97	$	2.97	$	6.43	$	5.80


(a)	Amounts in the Current Estimate reflect estimated costs through June 30, 2016.

(b)

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 reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.


~~(b)~~ (c)	Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs."


~~(c)~~	~~Amounts in~~ The current estimate reflects the ~~Current Estimate reflect costs through March 31, 2016.~~impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.


(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.


(g)	Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with placed in service and other non-construction work in progress accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the current cost estimate and actual costs at September 30, 2015.

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Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, ~~2014, $2.88~~2015, $3.45 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of ~~$1.98~~$2.23 billion), ~~$104.3~~$2 million in other property and investments, $62 million in fossil fuel stock, $43 million in materials and supplies, $50 million in other regulatory assets, current, $158 million in other regulatory assets, deferred, and ~~$3.9~~$15 million in other deferred charges and assets in ~~Mississippi Power's Condensed Balance Sheet herein, and $1.1 million was previously expensed.~~the balance sheet.

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 above the cost cap of ~~$418.0~~$150 million ($~~258.1~~93 million after tax) in the third quarter ~~2014~~2015, and ~~$380.0~~a total of $182 million ($~~234.7~~112 million after tax) infor the ~~first quarter 2014.~~nine months ended September 30, 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 2015 primarily ~~reflected~~reflect costs for increased efforts related to ~~decreases~~equipment rework, scope modifications, and the related additional labor costs in ~~construction labor productivity at the Kemper IGCC due in large part to adverse weather, unexpected excessive craft labor turn-over,~~support of start-up and ~~unanticipated installation inefficiencies,~~operational readiness activities, as well as additional ~~risk related to the expected in-service date. The third quarter 2014 revised cost estimate primarily reflects~~schedule costs related to the extension of the project schedule for the remainder of the Kemper IGCC (including the gasifier and the gas clean-up facilities) as a result 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.through June 30, 2016. The current estimate includes costs through ~~March 31,~~June 30, 2016. Any ~~further~~ extension of the in-service date beyond June 30, 2016 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond June 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $12 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees. Beginning in the third quarter 2015, in connection with the implementation of interim rate recovery, certain of these ongoing project costs are being expensed, with the remainder being deferred as regulatory assets and are estimated to total approximately $6 million per month. For additional information, see "2015 Rate Case" herein.

~~Any further~~Mississippi Power’s analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. Further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and

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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

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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 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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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS) to implement the requirements of the 2013 Settlement Agreement.~~additional information.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in ~~January 2013, Mississippi Power filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013.~~

In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively ~~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 2013, a legal challenge to~~August 2014, Mississippi Power provided an analysis of the ~~2013 MPSC Rate Order was filed by Thomas A. Blanton~~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 ~~Mississippi Supreme Court, which remains pending against~~operation of the combined cycle. In addition, Mississippi Power ~~and~~requested confirmation of Mississippi Power's accounting treatment by the Mississippi ~~PSC. On April 22, 2014,~~PSC of the ~~Mississippi Supreme Court requested further briefing in this proceeding on a number~~continued accrual of ~~substantive issues relating to~~AFUDC through the ~~2013 MPSC Rate Order. An adverse outcome could affect~~in-service date of the ~~rates that went into effect on March 19, 2013 and January 1, 2014 and~~remainder of the ~~related amounts deferred as a regulatory liability.~~

Kemper IGCC. 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~~ Any action by the Mississippi PSC ~~for~~that is inconsistent with the ~~Kemper IGCC for cost recovery through 2020 (Seven-Year Rate Plan), which is still under review~~treatment requested by ~~the Mississippi PSC. In the Seven-Year Rate Plan,~~ Mississippi Power ~~proposed recovery~~could have a material impact on the results of ~~an annual revenue requirement~~operations, financial condition, and liquidity 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 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 ActPower.

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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 ~~2012 (ATRA), which currently requires that assets be placed in service in 2014. While~~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. Mississippi Power ~~placed~~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. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Through July 2015 billings, Mississippi Power had collected $342 million through rates under the 2013 MPSC Rate Order and had accrued $27 million in associated carrying costs through September 30, 2015. Refunds will begin in early November 2015.

2015 Rate Case

As a result of the 2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On 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). In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.

Furthermore, 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 presented 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 requested 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 requested that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal.

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~~On August 13, 2015, the Mississippi PSC ~~does not approve~~approved the implementation of interim rates that became effective with the first billing cycle in September (on August 19), subject to refund and certain other conditions. In addition, the Mississippi PSC reserved the right to modify or terminate the interim rates based upon a material change in circumstances. Through September 30, 2015, Mississippi Power ~~withdraws~~had recognized $28 million under the ~~Seven-Year Rate Plan, as ultimately revised,~~ interim rates. The Mississippi PSC is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal.

Mississippi Power ~~would~~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 30, ~~2014~~2015 of ~~$6.10~~$6.43 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.

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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. 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. Beginning in the third quarter 2015, in connection with the implementation of interim rates, Mississippi Power began expensing certain ongoing project costs and certain debt carrying costs (associated with placed in service and other non-construction work in progress accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees over a 24-month period. As of September 30, ~~2014,~~2015, the ~~regulatory asset~~ balance associated with ~~the Kemper IGCC~~these regulatory assets was ~~$104.3 million. The projected balance at March 31, 2016 is estimated to total approximately $180~~$117 million. The amortization period ~~of 40 years proposed by Mississippi Power~~ for ~~any such costs approved for recovery remains~~these regulatory assets is subject to ~~approval by~~ the Mississippi ~~PSC.~~

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In March 2013, the Mississippi PSC issued the 2013 MPSC Rate Order approving retail rate increases of 15% effective March 19, 2013, and 3% effective January 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 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~~totaled $91 million as of September 30, 2015. The amortization period for these assets is ~~deferring the collections under the approved rates through the in-service date in a regulatory liability~~expected 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 disposition of the regulatory liability will be determined by the Mississippi PSC in future ~~cost recovery mechanism proceedings.~~rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.

Also see "2015 Mississippi Supreme Court Decision" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.

See Note 1 to the financial statements of Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.

Lignite Mine and CO₂ Pipeline Facilities

In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

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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.

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,~~On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and ~~SMEPA signed an amendment to the APA whereby~~SMEPA. Mississippi Power ~~and~~previously received a total of $275 million of deposits from SMEPA ~~agreed to amend the power supply agreement entered into by the parties in April 2011 to reduce the capacity amounts~~that were required to be ~~received by~~returned to SMEPA ~~by half (approximately 75 MWs) at~~with interest in connection with the ~~sale and transfer~~termination of the ~~undivided interest~~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 ~~Kemper IGCC~~aggregate principal amount of approximately $301 million to ~~SMEPA. Capacity revenues under the April 2011 power supply agreement were $17.5 million in 2013. In December 2013,~~Southern Company.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power ~~and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014.~~in Item 7 of the Form 10-K for additional information.

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In 2012 and on January 2, 2014, Mississippi Power received $150 million and $75 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposits have been presented as a current liability in 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 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 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.~~

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

~~Income Tax Matters~~

~~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~~These tax ~~benefits~~

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~~totaling $276.4 million for the Phase II~~ credits ~~of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and~~ are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. ~~A portion of~~Through September 30, 2015, Mississippi Power had recorded tax benefits totaling $276 million for the Phase II ~~tax~~ credits, ~~will be subject to recapture upon completion~~ of ~~SMEPA's purchase~~which approximately $235 million had been utilized. While the in-service date for the remainder of ~~an undivided interest in~~ the Kemper IGCC is currently expected to occur in the first half of 2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, but has not made a final determination to that effect. Due to this uncertainty, Mississippi Power has reflected these tax credits as ~~described above.~~unrecognized tax benefits and reclassified the Phase II credits to a current liability on its September 30, 2015 balance sheet, with no impact to net income. Repayment to the IRS would occur with the quarterly estimated tax payment following a final determination that the in-service date would occur subsequent to April 19, 2016. Any cash funding requirements necessary for Mississippi Power to make this repayment are expected to be provided by Southern Company. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits – Investment Tax Credits," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

Section 174 Research and Experimental Deduction

~~For the 2013 tax year,~~ Southern Company, ~~included in its consolidated federal income tax return a deduction~~on behalf of Mississippi Power, reflected deductions for ~~R&E~~research and experimental (R&E) expenditures related to the Kemper ~~IGCC.~~IGCC in its federal income tax calculations for 2013, 2014, and 2015. 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 ~~recorded an~~had unrecognized tax ~~benefit of~~benefits associated with these R&E deductions totaling approximately ~~$100~~$414 million as of September 30, ~~2014.~~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"~~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 ~~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~~$150 million ($~~258.1~~93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, ~~$380.0~~$380 million ($~~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~~$2.23 billion ($~~1.22~~1.4 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 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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portion of which are being deferred as regulatory assets and are estimated to total approximately $6 million per month.

Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

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, 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.

As a result of the final CCR Rule discussed above, Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information 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 for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, Mississippi Power expects to continue to periodically update these estimates.

Given the significant judgment involved in estimating AROs, Mississippi Power considers the liabilities for AROs to be critical accounting estimates.

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

Recently Issued Accounting Standards

The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Mississippi Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle"~~required to be applied retrospectively to all periods presented beginning in the year of adoption. Mississippi 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 Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

~~Recently Issued Accounting Standards~~

~~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. Mississippi Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.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 and its ability to obtain financing needed for normal business operations and completion of construction and start-up of the Kemper IGCC were 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, the required refund of Mirror CWIP rate collections beginning in early November 2015 of approximately $369 million, including associated carrying costs, the termination of the Mirror CWIP rate and the likely repayment of the Phase II tax credits of $235 million as of September 30, 2015. Earnings for the nine months ended September 30, ~~2014~~2015 were negatively affected by revisions to the cost estimate for the Kemper ~~IGCC; however,~~IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. 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 ~~Power's financial condition remained stable at September 30, 2014 as a result of capital contributions to Mississippi Power by Southern Company.~~Supreme Court Decision," "– 2015 Rate Case," and – "Income Tax Matters – Investment Tax Credits" herein for additional information.

Through September 30, ~~2014,~~2015, Mississippi Power has incurred non-recoverable cash expenditures of ~~$1.18~~$1.8 billion and is expected to incur approximately ~~$0.8~~$0.4 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC.

~~During~~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, $25 million of short-term debt, and the ~~first nine months~~required refund of ~~2014,~~approximately $369 million in Mirror CWIP, which includes associated carrying costs. 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, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. Mississippi Power ~~received $310.0 million in equity contributions and a $220.0 million loan from~~is primarily dependent upon Southern Company ~~which was repaid on September 29, 2014. In October 2014,~~to meet its financing needs. Mississippi Power ~~received an additional $100 million in~~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. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets and bank credit arrangements. Management intends to utilize 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"~~Activities herein for additional information.

During the first nine months of 2015, Mississippi Power received $150 million in equity contributions from Southern Company and issued an 18-month promissory note for $301 million to 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.

Net cash provided from operating activities totaled ~~$504.7~~$349 million for the first nine months of ~~2014, an increase~~2015, a decrease of ~~$218.0~~$156 million as compared to the corresponding period in ~~2013.~~2014. The ~~increase~~decrease in cash provided from operating activities is primarily due to lower R&E tax deductions and lower incremental benefit of ITCs from the Kemper IGCC ~~collections that are being deferred for future rate mitigation, a decrease in receivables,~~ and ~~increases in~~timing of payments of accounts payable, ~~and accrued compensation,~~ partially offset by ~~investment tax credits related 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.~~fuel recovery, and a decrease

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

in receivables. See Notes (B) and Note (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled ~~$1.0 billion~~$686 million for the first nine 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~~$300 million for the first nine 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 and short term borrowings. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. 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 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 bylong-term debt with short-term loans. Additionally, long-term debt increased $292 million and interest-bearing refundable deposits decreased $275 million, due to an intercompany loan for the ~~end~~repayment of the ~~third quarter 2015, as well as an increase in the interest-bearing refundable deposit from~~ SMEPA of

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~~MISSISSIPPI POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~$75 million.~~deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased ~~$212.4 million, other regulatory asset, deferred increased $54.8~~$490 million and ~~other~~the Mirror CWIP regulatory ~~liabilities,~~liability increased $98 million primarily associated with construction and collections related to the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current increased $544 million, unrecognized tax benefits increased $359 million, and accumulated deferred income taxes increased ~~$122.7~~$389 million primarily due to R&E tax deductions and the related reserve. Accumulated deferred ITCs decreased $278 million primarily due to the ~~Kemper IGCC. Additional changes included an increase in prepaid income taxes~~likely repayment of ~~$128.0 million, an increase in accrued income taxes of $86.4 million, and an increase in deferred charges related to income taxes of $57.4 million primarily related to R&E~~unrecognized tax ~~deductions and investment~~benefits associated with the Phase II tax credits related to the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Income Tax ~~Matters"~~Matters – Investment Tax Credits" herein for additional information. Total common stockholder's equity ~~decreased $155.5~~increased $219 million primarily due to the ~~estimated probable loss on the Kemper IGCC partially offset by the~~ receipt of ~~$310.0~~$150 million in capital contributions from Southern ~~Company.~~Company and net income during the nine months ended September 30, 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 30, ~~2015~~2016 to fund maturities of ~~long-term~~bank term loans scheduled to mature on April 1, 2016 and $25 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collections of approximately $369 million, including associated carrying costs, beginning in November 2015. 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, $477 million in 2016, and $221 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~~$834 million ~~for~~in 2015 and ~~$75~~$281 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 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 and its ability to obtain funds needed for normal business operations and completion of the construction and start-up of the Kemper IGCC were 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, the required refund of Mirror CWIP rate collections beginning in early November 2015 of approximately $369 million, including associated carrying costs, the termination of the Mirror CWIP rate, and the likely repayment of unrecognized tax benefits associated with the Phase II tax credits of $235 million. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September (on August 19), subject to refund and certain other conditions, and is scheduled to issue a final order on or before December 8, 2015 related to permanent rates for the In-Service Asset Proposal. 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," " – 2015 Mississippi Supreme Court Decision," and " – 2015 Rate Case" 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.

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. 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 issue a similar promissory note to Southern Company to fund the Mirror CWIP refund. Any cash funding requirements necessary for Mississippi Power to repay the Phase II tax credits to the IRS are also expected to be provided by Southern Company. As of September 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $1.3 billion primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $25 million of short-term debt, the required refund of approximately $369 million in Mirror CWIP and associated carrying costs, and the likely repayment of unrecognized tax benefits associated with the Phase II tax credits of $235 million. 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power's current liabilities exceeded current assets by approximately $1 billion at September 30, 2014, primarily because of securities due within one year. Management intends to utilize 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 capital needs.

At September 30, ~~2014,~~2015, Mississippi Power had approximately ~~$89.9~~$96 million of cash and cash equivalents. Committed credit arrangements with banks at September 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	15	$	220	$	235	$	210	$	30	$	30	$	60	$	175


~~(a)~~(*)	NoSubsequent to September 30, 2015, this $15 million bank credit ~~arrangements expire in 2017 or 2018.~~arrangement expired pursuant to its terms.

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.

A portion of the $210 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, 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.

needed. In connection therewith, Mississippi Power may ~~also meet~~seek to extend the maturity dates and/or increase or decrease the lending commitments thereunder.

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

~~Mississippi Power had no commercial paper or short-term debt outstanding during the three-month period ended September 30, 2014.~~



	Short-term Debt at September 30, 2015			Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Amount Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Short-term bank debt	$	500	1.4%	$	513	1.3%	$	515


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 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 have required or could require collateral, but not accelerated payment, in the event of a credit rating change to ~~below BBB-~~BBB and/or ~~Baa3.~~Baa2 or below. These contracts are for physical electricity sales, fuel transportation and storage, ~~and~~ energy price risk ~~management.~~management, and transmission. At September 30, ~~2014,~~2015, the maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 ~~were~~equaled approximately ~~$259~~$286 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 Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Additionally, a credit rating downgrade has impacted and may continue to impact the ability of Mississippi Power to access capital markets, and would be likely to impact the cost at which it does so.

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.

On August 14, 2015, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Baa2 from Baa1. Moody's maintained the negative ratings outlook for Mississippi Power.

On August 17, 2015, S&P downgraded the issuer rating of Mississippi Power to BBB+ from A. S&P revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its consolidated credit rating outlook of Southern Company (including Mississippi Power) from stable to negative following the announcement of the Merger.

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 short-term 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 deposits 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 September 30,						For the Nine Months Ended September 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		$	295		$	332		$	776		$	870
Wholesale revenues, affiliates	102,631			96,795			242,527			263,624			104			103			303			243
Other revenues	747			2,220			2,293			5,517			2			—			7			2
Total operating revenues	435,256			364,767			1,114,913			974,969			401			435			1,086			1,115
Operating Expenses:
Fuel	178,281			133,464			420,896			363,466			118			178			361			421
Purchased power, non-affiliates	28,156			19,673			72,643			56,553			17			28			52			73
Purchased power, affiliates	12,796			7,011			58,475			21,158			5			13			18			58
Other operations and maintenance	46,347			41,309			168,392			154,920			62			46			184			168
Depreciation and amortization	59,508			41,094			162,524			126,152			64			60			183			163
Taxes other than income taxes	5,458			5,719			16,842			16,526			6			5			17			17
Total operating expenses	330,546			248,270			899,772			738,775			272			330			815			900
Operating Income	104,710			116,497			215,141			236,194			129			105			271			215
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22,983		)	(12,961		)	(66,952		)	(53,923		)	(18		)	(23		)	(62		)	(67		)
Other income (expense), net	5,511			(791		)	5,596			(2,739		)	1			5			1			6
Total other income and (expense)	(17,472		)	(13,752		)	(61,356		)	(56,662		)	(17		)	(18		)	(61		)	(61		)
Earnings Before Income Taxes	87,238			102,745			153,785			179,532			112			87			210			154
Income taxes	21,960			17,592			22,177			37,265			1			22			14			22
Net Income	65,278			85,153			131,608			142,267			111			65			196			132
Less: Net income attributable to noncontrolling interest	1,647			—			3,694			—
Less: Net income attributable to noncontrolling interests													9			1			15			4
Net Income Attributable to Southern Power Company	$	63,631		$	85,153		$	127,914		$	142,267		$	102		$	64		$	181		$	128

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 September 30,				For the Nine Months Ended September 30,
	2015		2014		2015		2014
	(in millions)				(in millions)
Net Income	$	111	$	65	$	196	$	132
Other comprehensive income (loss)	—		—		—		—
Less: Comprehensive income attributable to noncontrolling interests	9		1		15		4
Comprehensive Income Attributable to Southern Power Company	$	102	$	64	$	181	$	128

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 STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2015			2014
	(in thousands)						(in millions)
Operating Activities:
Net income	$	131,608		$	142,267		$	196		$	132
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	158,264			131,955			187			166
Deferred income taxes	(6,340		)	83,331			222			(6		)
Investment tax credits	38,215			(25,137		)	294			38
Amortization of investment tax credits							(14		)	(8		)
Deferred revenues	(2,452		)	3,136			15			(2		)
Accrued income taxes, non-current							100			—
Other, net	3,853			962			10			3
Changes in certain current assets and liabilities —
-Receivables	(62,757		)	(28,486		)	(28		)	(63		)
-Fossil fuel stock	(1,565		)	881			6			(2		)
-Materials and supplies	(3,455		)	(5,902		)
-Prepaid income taxes	38,716			(12,485		)	(116		)	39
-Other current assets	(720		)	(2,017		)	(5		)	(4		)
-Accounts payable	26,989			(4,282		)	1			27
-Accrued taxes	62,124			12,550			(247		)	62
-Accrued interest	(13,451		)	(8,306		)
-Other current liabilities	2,000			235			(12		)	(11		)
Net cash provided from operating activities	371,029			288,702			609			371
Investing Activities:
Plant acquisition	(217,547		)	(111,600		)
Plant acquisitions							(1,128		)	(218		)
Property additions	(14,782		)	(463,873		)	(348		)	(15		)
Change in construction payables	(3,282		)	292			88			(3		)
Payments pursuant to long-term service agreements	(41,782		)	(40,978		)	(65		)	(42		)
Investment in restricted cash	(166		)	(20,000		)
Other investing activities	(9,996		)	(1,724		)	(1		)	(10		)
Net cash used for investing activities	(287,555		)	(637,883		)	(1,454		)	(288		)
Financing Activities:
Increase in notes payable, net	19,995			120,798			18			20
Proceeds —
Senior notes	—			300,000			650			—
Capital contributions	(3,628		)	1,897			226			(4		)
Other long-term debt	10,199			22,722			400			10
Repayments — Other long-term debt	(818		)	(220		)
Distributions to noncontrolling interest	(150		)	(146		)
Contributions from noncontrolling interest	7,492			16,802
Redemptions — Senior notes							(525		)	—
Distributions to noncontrolling interests							(6		)	—
Contributions from noncontrolling interests							274			7
Payment of common stock dividends	(98,340		)	(96,840		)	(98		)	(98		)
Other financing activities	(184		)	(2,287		)	(8		)	—
Net cash provided from (used for) financing activities	(65,434		)	362,726			931			(65		)
Net Change in Cash and Cash Equivalents	18,040			13,545			86			18
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		$	161		$	87
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 $4 and $- capitalized for 2015 and 2014, respectively)							$	69		$	78
Income taxes, net	(91,193		)	(6,518		)	(215		)	(91		)
Noncash transactions — accrued property additions at end of period	549			36,370
Noncash transactions — Accrued property additions at end of period							120			1

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 September 30, 2015		At December 31, 2014
	(in thousands)				(in millions)
Current Assets:
Cash and cash equivalents	$	86,784	$	68,744	$	161	$	75
Receivables —
Customer accounts receivable	103,740		73,497		100		77
Other accounts receivable	9,107		3,983		35		15
Affiliated companies	46,089		38,391		50		34
Fossil fuel stock, at average cost	20,743		19,178		16		22
Materials and supplies, at average cost	58,234		54,780		60		58
Prepaid service agreements — current	30,996		81,206
Prepaid income taxes	47,374		54,732		136		19
Other prepaid expenses	8,518		7,915
Assets from risk management activities	810		182
Deferred income taxes, current					—		306
Other current assets					19		21
Total current assets	412,395		402,608		577		627
Property, Plant, and Equipment:
In service	4,941,745		4,696,134		6,049		5,657
Less accumulated provision for depreciation	981,568		871,963		1,189		1,035
Plant in service, net of depreciation	3,960,177		3,824,171		4,860		4,622
Construction work in progress	11,329		9,843		977		11
Total property, plant, and equipment	3,971,506		3,834,014		5,837		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 $11 and $8 at September 30, 2015 and December 31, 2014, respectively					318		47
Total other property and investments	49,626		45,344		320		49
Deferred Charges and Other Assets:
Prepaid long-term service agreements	83,403		73,676		157		124
Other deferred charges and assets — affiliated	2,556		4,605		3		5
Other deferred charges and assets — non-affiliated	89,097		68,853		146		112
Total deferred charges and other assets	175,056		147,134		306		241
Total Assets	$	4,608,583	$	4,429,100	$	7,040	$	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 September 30, 2015		At December 31, 2014
	(in thousands)				(in millions)
Current Liabilities:
Securities due within one year	$	531,184	$	599	$	400	$	525
Notes payable	19,995		—		213		195
Accounts payable —
Affiliated	89,853		56,661		69		78
Other	11,842		20,747		161		30
Accrued taxes —
Accrued income taxes	8,939		161		3		72
Other accrued taxes	13,115		2,662
Accrued interest	14,901		28,352		14		30
Other current liabilities	6,549		18,492		56		17
Total current liabilities	696,378		127,674		916		947
Long-term Debt	1,098,078		1,619,241		1,742		1,095
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	749,528		724,390		779		863
Accumulated deferred investment tax credits	396,020		340,269		688		601
Accrued income taxes, non-current					100		—
Deferred capacity revenues — affiliated	26,989		15,279		39		15
Other deferred credits and liabilities — affiliated	858		1,621		—		1
Other deferred credits and liabilities — non-affiliated	10,740		7,896		25		18
Total deferred credits and other liabilities	1,184,135		1,089,455		1,631		1,498
Total Liabilities	2,978,591		2,836,370		4,289		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		1,401		1,176
Retained earnings	561,573		531,998		657		573
Accumulated other comprehensive income	3,199		2,919		3		3
Total common stockholder's equity	1,590,179		1,563,952		2,061		1,752
Total Liabilities and Stockholder's Equity	$	4,608,583	$	4,429,100
Noncontrolling Interest					649		219
Total Stockholders' Equity					2,710		1,971
Total Liabilities and Stockholders' Equity					$	7,040	$	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 QUARTER ~~2014~~2015 vs. THIRD 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 nine months ended September 30, 2015, Southern Power acquired ~~all~~or commenced construction of ~~the outstanding membership interests~~approximately 857 MWs 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 five Georgia construction projects located in ~~May 2014 with the approximate 20-MW Adobe~~Taylor and Decatur Counties, as well as four solar ~~photovoltaic facility serving a PPA with~~projects located in California. Southern ~~California Edison (SCE) through 2034~~Power has also entered into agreements to acquire approximately 450 MWs of wind facilities, located in Oklahoma, contingent upon certain construction and ~~the approximate 50-MW Macho Springs solar photovoltaic facility serving a PPA with El Paso Electric Company (EPE) also through 2034.~~

project milestones. Subsequent to September 30, ~~2014,~~2015, 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 constructing~~ an ~~approximately 150-MW~~additional 15-MW solar ~~photovoltaic~~ 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 certain terms~~California. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and ~~conditions, including the payment of~~"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 quarter ~~2014~~2015 was ~~$63.6~~$102 million compared to ~~$85.2~~$64 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,~~increased revenues from PPAs, including solar, and lower ~~ITCs in~~ income taxes primarily related to ITCs, partially offset by ~~an increase in energy revenue from non-affiliates primarily~~increased other operations and maintenance expenses due to ~~increased revenue from~~ new solar ~~contracts.~~facilities.

Net income attributable to Southern Power for year-to-date ~~2014~~2015 was ~~$127.9~~$181 million compared to ~~$142.3~~$128 million for the corresponding period in ~~2013.~~2014. The ~~decrease~~increase was primarily due to ~~a decrease in capacity~~increased revenues ~~increased depreciation arising~~ from new

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

PPAs, including solar, ~~facilities,~~and lower ~~ITCs in~~ income taxes ~~and lower capitalized interest due~~primarily related to ~~reduced construction. The decrease was~~ITCs, partially offset by ~~an increase in energy revenue from non-affiliates~~increased depreciation and other operations and maintenance expenses primarily ~~from~~due to new solar ~~contracts and beneficial changes in certain state income taxes.~~facilities.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 of the changes in wholesale~~Wholesale revenues from non-affiliates for the third 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 %

$295 million compared to $332 million for the corresponding period in 2014. The ~~increase~~decrease was due to a $27 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 anew 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~~7% decrease in the average price of energy and a ~~47.0% and 26.8% increase~~6% decrease in KWH ~~sales~~sales. In addition, capacity revenues decreased $10 million primarily due to PPA expirations.

Wholesale revenues from non-affiliates for year-to-date 2015 were $776 million compared to $870 million for the ~~third quarter and year-to-date 2014, respectively.~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Power Sales Agreements"~~corresponding period in 2014. The decrease was due to a $71 million decrease in energy sales, primarily as a result of ~~Southern Power~~decreased fuel costs passed through in ~~Item 7~~PPA revenues due to lower natural gas prices, partially offset by new solar PPAs. The decrease in energy revenues reflects a 13% decrease in the average price of ~~the Form 10-K for additional information.~~energy. In addition, capacity revenues decreased $23 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 quarter ~~2014~~2015 were ~~$102.6~~$104 million compared to ~~$96.8~~$103 million for the corresponding period in ~~2013.~~2014. The increase was the result of a ~~$9.3~~$20 million increase in capacity revenues, partially offset by a $19 million decrease in energy ~~revenue, primarily due to an~~revenues. The increase in capacity revenues was primarily the result of new PPAs. The decrease in energy ~~sales under~~revenues was primarily the ~~IIC, reflecting~~result of a ~~13.2% increase~~42% decrease in the average price of energy partially offset by a 28% increase in KWH sales primarily from new PPAs.

Wholesale revenues from affiliates for year-to-date 2015 were $303 million compared to $243 million for the corresponding period in 2014. The increase was the result of a $31 million increase in energy revenues and a $29 million increase in capacity revenues. The increase in energy revenues was 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, as well as new PPAs. The increase ~~was~~in energy revenues reflects a 71% increase in KWH sales, partially offset by a ~~$3.5 million~~29% 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



	Third Quarter 2015 vs. Third Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(60	)	(33.7)	$	(60	)	(14.3)
Purchased power – non-affiliates	(11		)	(39.3)	(21		)	(28.8)
Purchased power – affiliates	(8		)	(61.5)	(40		)	(69.0)
Total fuel and purchased power expenses	$	(79	)		$	(121	)

Southern Power's PPAs for natural gas-fired generation generally provide that the ~~completion~~purchasers are responsible for either procuring the fuel (tolling agreements), or reimbursing Southern Power for substantially all of the cost of fuel relating to all the energy delivered under such PPAs. Consequently, any increase or decrease in such fuel cost is generally accompanied by an ~~existing contract for Plant Dahlberg.~~increase or decrease in related fuel revenues under the PPAs and does not have a

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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 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 quarter ~~2014,~~2015, total fuel and purchased power expenses were ~~$219.2~~$140 million compared to ~~$160.1~~$219 million for the corresponding period in ~~2013. Fuel and purchased power expenses increased $59.1~~2014. The decrease was the result of a $46 million ~~reflecting a 13.7% increase~~decrease in the average cost of ~~natural gas~~fuel and ~~a 14.2% increase in the average cost of~~ purchased power primarily ~~as a result of higher~~due to lower natural gas prices and ~~the availability of lower cost affiliate power. This increase also reflects~~ a ~~19.1% increase~~$33 million decrease in the total volume of KWHs ~~purchased~~generated and purchased; however, total KWHs generated ~~primarily as a result of higher demand.~~increased 5% when taking into account generation for tolling and solar PPAs.

For year-to-date ~~2014,~~2015, total fuel and purchased power expenses were ~~$552.0~~$431 million compared to ~~$441.2~~$552 million for the corresponding period in ~~2013. Fuel~~2014. The decrease was a result of a $185 million decrease in the average cost of fuel and purchased power ~~expenses~~primarily due to lower natural gas prices, partially offset by a $64 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. Total KWHs generated increased 22% when taking into account generation for tolling and solar PPAs.

Fuel

In the third quarter 2015, fuel expense was $118 million ~~reflecting~~compared to $178 million for the corresponding period in 2014. The decrease was due to a ~~24.2% increase in~~27% decrease associated with the average cost of natural gas per KWH generated, and a ~~20.1% increase in~~10% decrease associated with the ~~average cost~~volume of ~~purchased power primarily as a result of higher natural gas prices~~KWHs generated, which excludes tolling and ~~the availability of lower cost affiliate power.~~solar PPAs.

~~Fuel~~

~~In the third quarter 2014,~~For year-to-date 2015, fuel expense was ~~$178.3~~$361 millioncompared to ~~$133.4~~$421 million for the corresponding period in ~~2013.~~2014. The ~~increase~~decrease was due to a ~~$22.5 million increase~~34% decrease associated with the ~~higher~~ average cost of ~~fuel~~natural gas per KWH generated, ~~primarily due to higher average natural gas prices and~~partially offset by a ~~$22.4 million~~30% 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, which excludes tolling and solar PPAs.

~~For year-to-date 2014, fuel~~Purchased Power – Non-Affiliates and Affiliates

In the third quarter 2015, purchased power expense was ~~$420.9~~$22 million compared to ~~$363.5~~$41 million for the corresponding period in ~~2013.~~2014. For year-to-date 2015, purchased power expense was $70 million compared to $131 million for the corresponding period in 2014. The decreases were primarily the result of 38% and 43% decreases in the volume of KWHs purchased in the third quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices.

Other Operations and Maintenance Expenses

In the third quarter 2015, other operations and maintenance expenses were $62 million compared to $46 million for the corresponding period in 2014. The increase was primarily due to an increase in expenses associated with business development and support services, new plants placed in service in 2014 and 2015, and generation maintenance.

For year-to-date 2015, other operations and maintenance expenses were $184 million compared to $168 million for the corresponding period in 2014. The increase was primarily due to a ~~$79.1~~$31 million increase in expenses associated with ~~the higher average cost of fuel per KWH~~business development and support services, new plants placed in service in 2014 and 2015, transmission costs, and generation maintenance, partially offset by a $15 million decrease in outage expense.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

generated primarily due to higher average natural gas prices, partially offset by a $21.7 million decrease associated with the volume of KWHs generated primarily as a result of the availability of lower cost affiliate power.Depreciation and Amortization

~~Purchased Power~~

In the third quarter ~~2014, purchased power expense~~2015, depreciation and amortization was ~~$40.9~~$64 million compared to ~~$26.7~~$60 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to ~~a $9.1 million increase associated with the volume of KWHs purchased due~~additional depreciation related to ~~the availability of lower cost affiliate power~~solar facilities placed in service in 2014 and ~~a $5.1 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices.~~2015, partially offset by rate changes related to component depreciation.

For year-to-date ~~2014, purchased power expense~~2015, depreciation and amortization was ~~$131.1~~$183 million compared to ~~$77.7~~$163 million for the corresponding period in ~~2013.~~2014. The increase was primarily due to ~~a $31.5 million increase associated with the volume of KWHs purchased due~~additional depreciation related to ~~the availability of lower cost affiliate power~~solar facilities placed in service in 2014 and ~~a $21.9 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices.~~2015.

~~Other Operations and Maintenance Expenses~~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)
$5.0 12.2 $13.5 8.7

In the third quarter ~~2014, other operations and maintenance expenses~~2015, income taxes were ~~$46.3~~$1 million compared to ~~$41.3~~$22 million for the corresponding period in ~~2013.~~ 2014. The decrease was primarily due to increased federal income tax benefits related to ITCs in 2015, partially offset by higher pre-tax earnings in 2015.

For year-to-date ~~2014, other operations and maintenance expenses~~2015, income taxes were ~~$168.4~~$14 million compared to ~~$154.9~~$22 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.~~2014. 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 of new plants placed in service in 2014 and 2013, a change to theincreased federal income tax ~~filing method for North Carolina, an increase~~benefits related to ITCs in 2015, partially offset by higher pre-tax earnings in 2015 and beneficial state income tax ~~credits, and beneficial~~ changes in ~~certain state income tax laws partially offset by lower ITC-related items.~~2014.

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 and other 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.

~~Environmental Statutes and Regulations~~

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~~additional rulemaking 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

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.~~revisions to effluent guidelines.

On ~~August 15, 2014,~~November 3, 2015, the EPA published a final ~~rule establishing standards~~revisions to technology-based limits for ~~reducing effects on fish~~certain wastestreams from steam electric power plants. These revisions impose stringent steam effluent guidelines and ~~other aquatic life caused by new~~technology requirements for wastewater discharges at affected units. Compliance with these revisions could result in significant additional capital expenditures and ~~existing cooling water intake structures at existing power plants~~could affect future unit retirement and ~~manufacturing facilities, which became effective October 14, 2014.~~replacement decisions. The ultimate ~~outcome~~impact of ~~this final rule~~these revisions will depend on ~~the results of additional studies~~any legal challenges 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 challengesfinal revisions and cannot be determined at this time.

Global Climate Issues

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

On ~~June 18, 2014,~~October 23, 2015, two final actions by the EPA that would limit CO₂ emissions from fossil fuel-fired electric generating units were published in the ~~proposed Clean Power Plan, setting forth~~Federal Register. One of the final actions contains specific emission standards governing CO₂ emissions from new, modified, and reconstructed units. The other final action 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, a proposed federal plan and proposed model rule were published 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 ~~for modified~~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

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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 oneongoing review of the ~~EPA's compliance scenarios. These costs could be significant to~~final rules; the ~~utility industry and the Southern Company system. However, the ultimate financial and operational impact~~outcome 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;any legal challenges; individual state implementation of ~~these~~the EPA's final 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 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

~~Adobe Solar, LLC~~

~~See MANAGEMENT'S DISCUSSION AND ANALYSIS~~ – ~~FUTURE EARNINGS POTENTIAL~~ – ~~"Acquisitions" of~~During 2015, Southern Power ~~in Item 7 of the Form 10-K and Note (I)~~Company acquired or contracted 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 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 SCE.

~~Macho Springs Solar, LLC~~

On May 22, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Macho Springs from First Solar Development, LLC, the original developer of the project. Macho Springs constructed and owns an approximately 50-MW solar photovoltaic facility in Luna County, New Mexico. The solar facility began commercial operation on May 23, 2014 and the entire output of the plant is contracted under a 20-year PPA with EPE. ~~See Note (I) to the Condensed Financial Statements herein for additional information.~~

~~SG2 Imperial Valley, LLC~~

~~Subsequent to September 30, 2014, Southern Power,~~acquire through its wholly-owned ~~subsidiary Holdings, acquired all~~subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc. (SRE), the following projects in accordance with its overall growth strategy, which are included in its capital program estimates for 2015. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.

Project Entity

Seller; Acquisition Date

Approx. Nameplate Capacity

Location

Southern Power Percentage Ownership

Expected/Actual Commercial Operation Date

PPA
Counterparties for Entire Plant Output

PPA Contract Period

Approx. Purchase Price

(MW)

(in millions)

WIND

Kay Wind, LLC

Apex Clean Energy Holdings, LLC

299

Kay County, Oklahoma

100

Fourth quarter 2015

Westar Energy, Inc. and Grant River Dam Authority

20 years

492

(a)

Grant Wind, LLC

Apex Clean Energy Holdings, LLC

151

Grant County, Oklahoma

100

First quarter 2016

Western Farmers, East Texas, and Northeast Texas Electric Cooperative

20 years

264

(a)

SOLAR

Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell)

First Solar, Inc. (First Solar)
April 15, 2015

Kern County, California

(b)

April 17, 2015

City of Roseville, California/Pacific Gas and Electric Company

29 years

(c)

NS Solar Holdings, LLC (North Star)

First Solar
April 30, 2015

Fresno County, California

(b)

June 20, 2015

Pacific Gas and Electric Company

20 years

211

(d)

Tranquillity

Recurrent Energy, LLC
August 28, 2015

204

Fresno County, California

(b)

Fourth quarter 2016

Shell Energy North America (US), LP/Southern California Edison Company

18 years

100

(e)

Desert Stateline Holdings, LLC (Desert Stateline)

First Solar
August 31, 2015

300

San Bernardino County, California

(b)

8 Phases from December 2015 to Third quarter 2016

Southern California Edison Company

20 years

439

(f)

GASNA 31P, LLC (Morelos)

Solar Frontier Americas Holding, LLC
October 22, 2015

Kern County, California

Fourth quarter 2015

Pacific Gas and Electric Company

20 years

(g)

(a) On February 24, 2015 and September 4, 2015, Southern Power entered into agreements to acquire Kay Wind, LLC and Grant Wind, LLC, respectively. The completion of each acquisition is subject to the outstanding membership interests of SG2 from a wholly-owned subsidiary of First Solar, the developer of the project. SG2 is constructing the Imperial Facility, an approximately 150-MW solar photovoltaic facility in Southern California, whichseller achieving certain construction and project milestones, as well as various other customary conditions to closing. Each acquisition is expected to ~~begin~~close at or near the expected commercial operation ~~later in the fourth quarter 2014. The Imperial Facility's output is contracted under a 25-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy.~~

date. In connection with 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, and

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~~subsidiaries~~addition, the final purchase price may be adjusted based on performance testing as specified in the applicable purchase agreement. The Grant Wind, LLC purchase price includes contingent consideration. The ultimate outcome of ~~each of~~this matter cannot be determined at this time.

(b) Southern Power and First Solar, as members of Holdings, will make 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 the acquisition is approximately $508 million. Following these capital contributions, Southern Power will indirectly ownowns 100% of the class A membership interests and a wholly-owned subsidiary of ~~Holdings and be entitled to 51% of all cash distributions from Holdings, and First Solar will indirectly own~~the seller owns 100% of the class B membership ~~interests of Holdings~~interests. Southern Power and bethe class B member are entitled to 51% and 49%, respectively, of all cash distributions from ~~Holdings.~~the respective project. In addition, Southern Power ~~will be~~is entitled to substantially all of the federal tax benefits with respect to ~~this~~the respective transaction.

If(c) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the ~~Imperial Facility does~~class B membership interests for approximately $33 million. The fair values of the assets acquired through the business combination were recorded as follows: $98 million as property, plant, and equipment and $9 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not ~~achieve substantial completion by~~been finalized.

(d) Concurrently, a ~~certain date,~~wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $100 million. The fair values of the assets acquired through the business combination were recorded as follows: $266 million as property, plant, and equipment, $24 million as an 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.

(e) Concurrently, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests of Tranquillity after contributing approximately $157 million of assets and receiving an initial distribution of $100 million. The fair values of the assets acquired were recorded as follows: $170 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Subsequent to the acquisition, Southern Power ~~may require that First Solar~~and Recurrent Energy, LLC are expected to make ~~a rescission payment to Southern Power in an amount equal to Southern Power's investment in Holdings,~~additional construction payments of approximately $215 million and ~~Southern Power would be required to transfer its ownership interests in SG2 back to First Solar.~~

$106 million, respectively. The ultimate outcome of this matter cannot be determined at this time.

(f) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million. As of September 30, 2015, the fair values of the assets acquired, which includes Southern Power's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Southern Power's and First Solar's remaining combined future payments, including construction payments, are estimated to be between $827 million to $844 million. The ultimate outcome of this matter cannot be determined at this time.

(g) On October 22, 2015, SRE and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC, a jointly-owned subsidiary owned 90% by SRE, acquired all of the outstanding membership interests of Morelos. The total purchase price, including TRE's 10% ownership, is approximately $50 million.

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 September 30, 2015 was $299 million. The ultimate outcome of these matters cannot be determined at this time.

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Southern Power Company's construction projects, excluding the Tranquillity and Desert Stateline construction projects discussed above, are detailed in the table below:

Solar Project

Seller

Approx. Nameplate Capacity

County Location in Georgia

Expected Commercial Operation Date

PPA Counterparties
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

(c)

Decatur County

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(b)

20 years

$47

(c)

Butler

CERSM, LLC and Community Energy, Inc.

103

Taylor

December 2016

Georgia Power^(b)

30 years

220

$230

(c)

Pawpaw

Longview Solar, LLC

Taylor

December 2015

Georgia Power^(a)

30 years

$80

(c)

Butler Solar Farm

Strata Solar Development, LLC

Taylor

December 2015

Georgia Power^(b)

20 years

$48

(c)


(a)	Approved by the FERC subsequent to September 30, 2015.


(b)	Subject to FERC approval.


(c)	Includes the acquisition price of all outstanding membership 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 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

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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.

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 continues to evaluate these requirements. The ultimate impact of this ASU has not yet been determined.

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~~policies~~unamortized debt issuance costs in other deferred charges and ~~estimates related to Revenue Recognition, Impairment~~assets – non-affiliated on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results 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.~~operations, financial position, or cash flows of Southern ~~Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.~~Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at September 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~~$609 million for the first nine months of ~~2014, an increase of $82.3~~2015, compared to $371 million ~~as compared to~~for the first nine months of ~~2013.~~2014. The increase in cash provided from operating activities was primarily due to ~~cash~~an increase in income tax benefits received ~~for ITCs related to~~and increased revenues from new ~~plants placed in service in 2013 and 2014.~~PPAs, including solar. Net cash used for investing activities totaled ~~$287.6~~$1.45 billion for the first nine months of 2015 primarily due to the Lost Hills Blackwell, North Star, Tranquillity, and Desert Stateline acquisitions and expenditures related to the construction of new solar facilities. Net cash provided from financing activities totaled $931 million for the first nine months of 2014 primarily due to expenditures related to the acquisitions of Adobe and Macho Springs and payments pursuant to long-term service agreements. Net cash used for financing activities totaled $65.4 million for the first nine months of 20142015 primarily due to the ~~payment~~issuance of ~~common stock dividends.~~additional senior notes in May 2015, and a 13-month bank loan in August 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 months of ~~2014~~2015 include a ~~$136.0~~$966 million increase in CWIP, a $238 million increase in plant in service, ~~net of depreciation~~and a $271 million increase in other intangible assets, primarily due to the ~~acquisitions~~acquisition and construction of ~~Adobe and Macho Springs.~~new solar facilities. Other significant changes ~~which were~~include an increase in long-term debt of $647 million primarily ~~the~~as a result of the ~~timing~~issuance of senior notes in May 2015 and ~~amount of ITCs recognized in 2014 as compared to 2013, include a $55.8 million~~an increase in ~~accumulated deferred investment tax credits, and a $25.1~~noncontrolling interests of $430 million ~~increase in accumulated deferred income taxes. Additionally, there was a $20.0 million increase in notes payable~~primarily due to contributions made by the class B members for ~~commercial paper and a $33.2 million increase in affiliated accounts payable.~~their shares of the related acquisitions. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. Approximately ~~$525~~$400 million will be required to repay long-term debt due September 28, 2016. There are no other scheduled maturities of long-term debt through September 30, ~~2015 to fund maturities of long-term debt.~~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~~$2.3 billion for ~~2014,~~2015, which includes ~~expenditures related to the acquisition~~approximately $2.2 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.

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,

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Sources of Capital~~

Southern Power may use operating cash flows, external funds, or equity capital or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.

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 and banks to issue additional senior notes and bank term loans, respectively, and expects to utilize the capital 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 30, ~~2014~~2015 cash and cash equivalents of approximately ~~$86.8 million and~~$161 million. In August 2015, Southern Power Company ~~had a~~amended and restated its committed credit facility (Facility), which, among other things, extended the maturity date from 2018 to 2020. Southern Power Company increased its borrowing ability under this Facility to $600 million from $500 million. As of ~~$500~~September 30, 2015, $567 million ~~(Facility) expiring in 2018, of which $499 million is~~was 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.

In connection with the construction by Tranquillity of a solar facility in California, RE Tranquillity LLC, an indirect subsidiary of Southern ~~Power's~~Power Company, entered into the Tranquillity Credit Agreement which is non-recourse to Southern Power Company. The Tranquillity Credit Agreement provides (a) a senior secured construction loan credit facility of up to $86 million, (b) a senior secured bridge loan facility of up to $172 million, and (c) a senior secured letter of credit facility to issue up to $77 million under one or more letters of credit. All three facilities are secured by the membership interests of the project companies held by Tranquillity and are expected to mature on the earlier of the commercial operation date or December 31, 2016. Proceeds from the Tranquillity Credit Agreement are being used to finance project costs related to Tranquillity's solar facility currently under construction. As of September 30, 2015, the entire amount of the Tranquillity Credit Agreement was unused.

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.~~purposes, including maturing debt. 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

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

~~Management~~



	Commercial Paper at the End of the Period				Commercial Paper During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
September 30, 2015:	$	213	0.5	%	$	281	0.5	%	$	385


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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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~~Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, ~~and~~ energy price risk ~~management.~~management, and transmission.

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~~SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

The maximum potential collateral requirements under these contracts at September 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
At BBB and/or Baa2			$	11
At BBB- and/or Baa3	318		334
Below BBB- and/or Baa3	1,018		1,077

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~~a credit rating downgrade could impact the ability of Southern Power ~~Company's ability~~ to access capital markets, ~~particularly~~and would be likely to impact the ~~short-term debt market.~~cost at which it does so.

In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern ~~Power'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

In August 2015, Southern Power Company entered into a $400 million aggregate principal amount 13-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes, including Southern Power's growth strategy and continuous construction program.

During the nine months ended September 30, ~~2014,~~2015, Southern Power prepaid ~~$0.8~~$2.6 million of long-term debt ~~payable~~ to ~~TRE and issued $3.9~~TRE.

Subsequent to September 30, 2015, RE Tranquillity LLC borrowed approximately $37 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~~of construction loans pursuant to the ~~financing~~Tranquillity Credit Agreement at a floating rate based on one-month LIBOR. In addition, RE Tranquillity LLC issued $51 million of ~~Adobe, Macho Springs, Campo Verde Solar, LLC, and Apex Nevada Solar, LLC, respectively.~~letters of credit.

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 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 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

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(UNAUDITED)

continue 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 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. Early adoption is permitted and each registrant intends to adopt the ASU in the fourth quarter 2015. The ASU is required to be applied retrospectively to all periods presented beginning in the year of adoption. 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, which became effective on October 19, 2015. 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 below are based on information as of September 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 for closure in place. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the ~~present value~~quantities of CCR at each site, and the ~~ultimate costs~~determination of timing, including the potential for ~~an asset's future retirement and are recorded in~~closing ash ponds prior to the ~~period in which~~end of their currently anticipated useful life, 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.~~continue to periodically update these estimates.

As of September 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
(in millions)
Balance at beginning of year $ 730

$ 589
Liabilities incurred —

—
Liabilities settled (2 )
—
Accretion 33

29
Cash flow revisions 52

102
Balance at end of period $ 813

$ 720

~~The increase in cash flow revisions as of September 30, 2014 primarily relates to an increase in Alabama Power's AROs associated with asbestos at its steam generation facilities.~~



	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	644			402			—			101		97
Liabilities settled	(19		)	(1		)	(18		)	—		—
Accretion	83			38			42			1		2
Cash flow revisions	214			20			193			3		25
Balance at end of period	$	3,123		$	1,288		$	1,472		$	122	$	172

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(UNAUDITED)

~~Depreciation~~The increases in liabilities incurred and cash flow revisions for the nine months ended September 30, 2015 primarily relate to an increase in AROs associated with facilities impacted by the CCR Rule.

~~Beginning~~In connection with permitting activity 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 coststhird quarter 2015 related to the ~~usage~~coal ash pond at the retired Plant Scholz facility, Gulf Power recorded additional AROs 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$30 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.

AGL Resources Merger Litigation

AGL Resources and each member of the AGL Resources board of directors have been named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia in September and October 2015. These actions were filed on behalf of named plaintiffs and other AGL Resources shareholders challenging the Merger and seeking, among other things, preliminary and permanent injunctive relief enjoining the Merger, and, in certain circumstances, damages. Southern Company and Merger Sub were also named as defendants in two of these lawsuits. Southern Company intends to vigorously defend these suits. Southern Company does not believe these suits will impact the completion of the Merger, and they are not expected to have a material impact on Southern Company's financial statements. However, the ultimate outcome of these matters cannot be determined at this time. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" herein for additional information regarding the Merger.

Environmental Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. ~~These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units.~~ The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) ~~has been actively litigated~~was partially settled in 2006 through a consent decree with the EPA. On August 24, 2015, the U.S. District Court for the Northern District of Alabama ~~resulting in a settlement in 2006 of~~entered an order approving the ~~alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for~~joint stipulation among Alabama Power, onthe EPA, and the U.S. Department of Justice modifying the 2006 consent decree to resolve all remaining claims ~~and dismissal of~~in the case ~~with prejudice in 2011. In September 2013,~~against Alabama Power. Under the ~~U.S. Court of Appeals for the Eleventh Circuit affirmed in part~~modified consent decree, Alabama Power will, without admitting liability, operate certain units subject to emission rates and ~~reversed in part the 2011 judgment in favor of~~an annual emissions cap; use only

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~Alabama Power,~~natural gas at certain other units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and ~~the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.~~

~~Southern Company~~Barry; pay a $100,000 civil penalty; and ~~each traditional operating company believe each such traditional operating company complied with applicable laws and regulations~~invest $1.5 million 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.electric transportation infrastructure projects over three years.

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 September 30, ~~2014~~2015 was ~~$19~~$29 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~~PRPs at the Brunswick site have completed ~~the~~a removal ~~of wastes from the Brunswick site~~action as ordered by the EPA. Additional ~~cleanup and claims for recovery of natural resource damages~~response actions at this site orare anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the ~~assessment~~Brunswick site. Assessment and potential cleanup of other sites are anticipated.

Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.

In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In ~~February~~ 2013, the U.S. District Court for the Eastern District of North Carolina Western Division ~~granted Georgia Power's summary judgment motion ruling~~ruled 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~~action and, on March 20, 2015, the U.S. Court of Appeals for the Fourth ~~Circuit.~~Circuit affirmed the lower court's ruling. Therefore, the private action is now concluded. While the EPA has not withdrawn the UAO, Georgia Power believes it is unlikely that the EPA would pursue any claims against Georgia Power for this matter given the conclusion of this private action.

The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory ~~treatment.~~treatment for environmental remediation expenditures.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately ~~$49.5~~$46 million as of September 30, ~~2014.~~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

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

~~(UNAUDITED)~~

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~~these liabilities have no impact on net ~~income as a result of these liabilities.~~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 ~~December~~ 2013 and, onin March ~~28,~~ 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Power's environmental remediation liability ~~is $0.6~~was $0.3 million as of September 30, ~~2014~~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.

AsIn December 2014, the Court of Federal Claims entered a ~~result~~judgment in favor of Georgia Power and Alabama Power in the ~~first~~second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. On March 19, 2015, Georgia Power recovered approximately ~~$27~~$18 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.$26 million. In ~~2012, Alabama Power credited the award to cost of service for the benefit of customers. Also in 2012,~~March 2015, Georgia Power credited the award to accounts where the original costs were charged and ~~used it to reduce~~reduced rate base, fuel, and cost of service for the benefit of customers. Alabama Power expects its portion of the damage amounts collected to be used 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.~~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 September 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.

~~On-site dry spent fuel storage facilities are operational at all three plants~~FERC Matters

Municipal and ~~can be expanded to accommodate spent fuel through the expected life of each plant.~~

~~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 Southern Company ~~under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, Note 3 to the financial statements of~~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,~~Under a 2014 settlement agreement, an adjustment to Mississippi Power's wholesale revenue requirement was allowed in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore, Mississippi Power ~~reached~~has recorded a regulatory asset as a result of a portion of the Kemper IGCC being placed in service prior to the projected date and is amortizing this regulatory asset over the nine months ending December 31, 2015.

On May 13, 2015, the FERC accepted a settlement agreement ~~with~~between Mississippi Power and its wholesale customers ~~and filed~~to forgo a ~~request with the FERC for an increase in the~~ Municipal and Rural Associations (MRA) cost-based electric ~~tariff.~~tariff increase by, among other things, increasing the accrual of AFUDC and lowering the portion of CWIP in rate base, effective April 1, 2015. 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 rates effective for services rendered beginning May 1, 2014.

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additional resulting AFUDC is estimated to be approximately $13 million annually, of which $10 million relates to the Kemper IGCC.

Fuel Cost Recovery

Market-Based Rate Authority

The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request 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	September 30, 2014		December 31, 2013		Balance Sheet Line Item	September 30, 2015		December 31, 2014
		(in millions)					(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	—	$	7
Rate CNP Compliance^*– Under						Deferred under recovered regulatory clause revenues	$	—	$	2
	Under recovered regulatory clause revenues, current	25		—		Under recovered regulatory clause revenues, current	38		47
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	46		18		Deferred under recovered regulatory clause revenues	66		29
	Under recovered regulatory clause revenues, current	9		—		Under recovered regulatory clause revenues, current	30		27
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	44		27		Deferred over recovered regulatory clause revenues	128		47
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	87		96		Other regulatory liabilities, deferred	76		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

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Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism and the NPNS exception for wind PPAs.

On August 14, 2015, the FASB issued ASU 2015-13, allowing 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. The new accounting guidance will have no impact on Southern Company's or Alabama Power's financial statements.

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. On August 24, 2015, the U.S. District Court for the Northern District of Alabama entered an order approving the NSR joint stipulation. In accordance with the joint stipulation, Alabama Power retired Plant Barry Unit 3 (225 MWs) and it is no longer available for generation. See "Environmental Matters – New Source Review Actions" herein for additional information regarding the NSR actions.

Georgia Power

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional ~~information on Georgia Power's 2013 ARP.~~information.

In accordance with the terms of the 2013 ARP, on October ~~3, 2014,~~2, 2015, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, ~~2015~~2016 pending its approval:

~~Increase the~~increase in traditional base tariffs by approximately ~~$107 million to cover additional capacity costs;~~$49 million;

~~Increase~~increase in the environmental compliance cost recovery tariff by approximately ~~$32~~$75 million;

~~Increase~~increase in the demand-side management tariffs by approximately $3$7 million; and

~~Increase~~increase in the municipal franchise fee tariff by approximately ~~$3 million, consistent with the adjustments above.~~$13 million.

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

~~Renewables Development~~

See 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 for additional information.

As a result 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-term

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obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See Note 7 to the financial statements of Georgia Power under "Commitments – Fuel and Purchased Power Agreements" in Item 8 of the Form 10-K for additional information.

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.

~~Georgia Power filed a request~~To comply with the ~~Georgia PSC~~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 ~~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. On October 13, 2015, Plant Kraft Units 1 through 4 (316 MWs) were retired.

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 September 30, 2015 and December 31, 2014, Georgia Power's under recovered fuel balance totaled ~~$175~~$41 million and $199 million, respectively. For September 30, 2015 and December 31, 2014, the balance is included in current assets and current assets and other deferred charges and ~~other~~ assets, respectively, on Southern Company's and Georgia Power's Condensed Balance Sheets herein. ~~As of December 31, 2013,~~On September 18, 2015, 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 bePower filed a rate request with the Georgia PSC to lower total annual billings by ~~February 27,~~approximately $268 million effective January 1, 2016. The Georgia PSC is scheduled to vote on this matter on December 15, 2015. The ultimate outcome of this matter cannot be 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 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.

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. Current anticipated in-service dates for Plant Vogtle Units 3 and 4 are the second quarter 2019 and the second quarter 2020, respectively.

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

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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, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. The Vogtle 3 and 4 Agreement 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.

Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (S&W) (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation (Toshiba) and The Shaw

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Group Inc. (Shaw Group) (a subsidiary of Chicago Bridge & Iron Company, N.V. (CB&I)), 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~~may arise 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 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 the Georgia PSC. Accordingly, Georgia Power's eighth VCM report filed in February 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to ~~$4.8 billion~~ and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the construction period are estimated to total approximately $2.0 billion.

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~~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 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 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~~extensions of the guaranteed substantial completion dates of 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. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the decision of the U.S. District Court for the District of Columbia, which had dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The case is pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). 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 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).

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regulatory changes in law; (iii) enhanced dispute resolution procedures will be implemented; (iv) the guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement will be revised to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4 (as discussed below); (v) delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (vi) Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. In addition, the Vogtle Owners and the Contractor resolved other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the proposed settlement and in connection with Westinghouse's proposed acquisition of S&W: (i) the Vogtle Owners will terminate the parent guarantee of Shaw Group with respect to certain obligations of S&W, subject to obtaining the consent of the DOE under loan guarantee agreements relating to Plant Vogtle Units 3 and 4, while the parent guarantee of Toshiba with respect to certain obligations of Westinghouse will remain in place; (ii) Westinghouse will make provisions to engage Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (iii) the Vogtle Owners, CB&I, and Shaw Group also will enter into mutual releases of any and all claims against each other arising out of the construction of Plant Vogtle Units 3 and 4.

Georgia Power ~~does not agree~~will submit the ultimate settlement agreement terms and the related amendments to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated owner-related costs, which include approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost ~~or schedule adjustments or~~of Plant Vogtle Units 3 and 4 to $5.0 billion. 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 ~~Vogtle Owners have~~certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any ~~responsibility for~~ costs ~~related to these issues. Litigation is ongoing and~~incurred by Georgia Power ~~intends to vigorously defend the positions~~in excess of the ~~Vogtle Owners.~~certified amount will be included in rate base, provided Georgia Power ~~also expects negotiations~~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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(UNAUDITED)

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.

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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		Balance Sheet Location	September 30, 2015		December 31, 2014
		(in millions)					(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	41.3	$	21.0	Under recovered regulatory clause revenues	$	2	$	40
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	6.8		—		Other regulatory liabilities, current	3		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery - Over						Other regulatory liabilities, current	5		—
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	6.3		14.4		Under recovered regulatory clause revenues	—		10
Energy Conservation Cost Recovery – Over						Other regulatory liabilities, current	3		—
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	2.6		7.0		Under recovered regulatory clause revenues	—		3

~~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~~2015 Rate Case

~~See Note 3 to the financial statements of~~On May 15, 2015 and July 10, 2015, Mississippi Power ~~under "Retail Regulatory Matters – Energy Efficiency" in Item 8~~filed alternative rate proposals related to recovery of Kemper IGCC-related costs with the ~~Form 10-K for additional information.~~

Mississippi PSC. On ~~June 3, 2014,~~August 13, 2015, the Mississippi PSC approved ~~Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio~~the implementation of ~~energy efficiency programs. On October 17, 2014, Mississippi Power filed a revised compliance filing, which proposed an increase~~interim rates designed to collect approximately $159 million annually. See "Integrated Coal Gasification Combined Cycle – Rate Recovery of ~~$6.7 million in retail revenues~~Kemper IGCC Costs – 2015 Rate Case" herein for ~~the period December 2014 through December 2015. The Mississippi PSC approved the revised filing on November 4, 2014.~~additional information.

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 31 to the financial statements of Mississippi Power under ~~"Retail Regulatory Matters – System Restoration Rider"~~"Provision for Property Damage" in Item 8 of the Form 10-K for additional information.

On ~~April 1, 2014,~~October 6, 2015, the Mississippi PSC approved Mississippi Power's request to continue a zero System Restoration Rider (SRR) rate for ~~2014~~2015 and to accrue approximately ~~$3.3~~$3 million to the property damage reserve in ~~2014.~~2015.

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.~~PSC and information on Plant Watson Units 4 and 5.

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(UNAUDITED)

In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct ~~a scrubber~~scrubbers on Plant Daniel Units 1 and 2.2, which are scheduled to be placed in service in the fourth quarter 2015. 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~~$660 million,, with Mississippi Power's portion being ~~$330~~$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.~~project. As of September 30, ~~2014,~~2015, total project expenditures were ~~$464.1~~$626 million, of which Mississippi Power's portion was ~~$236.3~~$320 million, ~~plus~~excluding AFUDC of ~~$16.1~~$32 million.

On ~~August 1, 2014,~~February 25, 2015, Mississippi Power ~~entered into a settlement agreement with~~submitted its annual ECO filing for 2015, which indicated an annual increase in revenues of approximately $8 million. On February 27, 2015, the ~~Sierra Club (Sierra Club Settlement Agreement)~~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 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 burningsupported coal ~~and other solid fuel~~generation at Plant Watson Units 4 and 5 ~~(750 MWs)~~were retired. The remaining net book value of these two units was approximately $32 million, excluding the reserve for cost of removal, and ~~begin operating those units solely~~has been reclassified to other regulatory assets, deferred, on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi ~~Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the~~

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~~CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On August 28, 2014, the Chancery Court dismissed the appeal.~~

InPower's Condensed Balance Sheet herein in accordance with ~~a 2011~~an accounting order from the Mississippi ~~PSC,~~PSC. Mississippi Power ~~has~~expects to recover through its rates the ~~authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related~~remaining book value of the retired assets and certain 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~~including unusable inventory, associated with the ~~remaining net book value~~retirements; however, the ultimate method and timing of ~~coal-related equipment~~recovery 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~~considered 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.~~PSC in future rate proceedings.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for information regarding Mississippi Power's retail fuel cost recovery.

At September 30, ~~2014,~~2015, the amount of ~~under~~over recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was ~~$13.1~~$44 million compared to ~~over~~under recovered retail fuel costs of ~~$14.5~~$2 million at December 31, ~~2013.~~2014.

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.

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 ~~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.

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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) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline

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facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to ~~$2.88~~$2.88 billion,, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. ~~Exceptions~~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 ~~$2.88 billion~~cost cap ~~include~~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)~~, 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~~ Mississippi Power's 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 on natural gas on 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 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 to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" herein for additional information.

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

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~~Mississippi Power's~~ 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of September 30, ~~2014~~2015, as adjusted for the ~~Kemper IGCC~~Court's decision, are as follows:


Cost Category	2010 Project Estimate^(f)		Current Estimate		Actual Costs at September 30, 2014		2010 Project Estimate^(f)		Current Estimate^(a)		Actual Costs
	(in billions)						(in billions)
Plant Subject to Cost Cap^(a)(g)	$	2.40	$	4.86	$	4.06	$	2.40	$	5.11	$	4.66
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
AFUDC^(c)							0.17		0.66		0.55
Combined Cycle and Related Assets Placed in Service – Incremental^(d)(g)	—		—		—		—		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^(e)(g)							—		0.20		0.17
Total Kemper IGCC^(c)	$	2.97	$	6.10	$	4.97	$	2.97	$	6.43	$	5.80


(a)	Amounts in the Current Estimate reflect estimated costs through June 30, 2016.

(b)


~~(b)~~(c)	Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs."


~~(c)~~	~~Amounts in~~ The current estimate reflects the ~~Current Estimate reflect costs through March 31, 2016.~~impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.


(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."

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(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.


(g)	Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with placed in service and other non-construction work in progress accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the current cost estimate and actual costs at September 30, 2015.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, ~~2014, $2.88~~2015, $3.45 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of ~~$1.98~~$2.23 billion), ~~$104.3~~$2 million in other property and investments, $62 million in fossil fuel stock, $43 million in materials and supplies, $50 million in other regulatory assets, current, $158 million in other regulatory assets, deferred, and ~~$3.9~~$15 million in other deferred charges and assets in ~~Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and $1.1 million was previously expensed.~~the balance sheet.

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 above the cost cap of ~~$418.0~~$150 million ($~~258.1~~93 million after tax) in the third quarter ~~2014~~2015 and ~~$380.0~~a total of $182 million ($~~234.7~~112 million after tax) infor the ~~first quarter 2014.~~nine months ended September 30, 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. The first quarter~~, $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, ~~revised~~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 2015 primarily ~~reflected~~reflect costs for increased efforts related to ~~decreases~~equipment rework, scope modifications, and the related additional labor costs in ~~construction labor productivity at the Kemper IGCC due in large part to adverse weather, unexpected excessive craft labor turn-over,~~support of start-up and ~~unanticipated installation inefficiencies,~~operational readiness activities, as well as additional ~~risk related to the expected in-service date. The third quarter 2014 revised cost estimate primarily reflects~~schedule costs related to the extension of the project schedule for the remainder of the Kemper IGCC (including the gasifier and the gas clean-up facilities) as a result 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.through June 30, 2016. The current estimate includes costs through ~~March 31,~~June 30, 2016. Any ~~further~~ extension of the in-service date beyond June 30, 2016 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond June 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $12 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees. Beginning in the third quarter 2015, in connection with the implementation of interim rate recovery, certain of these ongoing project costs are being expensed, with the remainder being deferred as regulatory assets and are estimated to total approximately $6 million per month. For additional information, see "2015 Rate Case" herein.

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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.

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(UNAUDITED)

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~~Case (as defined below) 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 Southern Company's or Mississippi Power's financial statements.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, ~~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.

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~~$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 ~~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.

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~~(UNAUDITED)~~

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.

Kemper IGCC. 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 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~~Liabilities" for additional information. Any action by the Mississippi PSC that ~~assets be placed in service in 2014. While~~is inconsistent with the treatment requested by Mississippi Power ~~placed~~could have a material impact on the results of operations, financial condition, and liquidity of Southern Company and Mississippi Power.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. 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. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Through July 2015 billings, Mississippi Power had collected $342 million through rates under the 2013 MPSC Rate Order and had accrued $27 million in associated carrying costs through September 30, 2015. Refunds will begin in early November 2015.

2015 Rate Case

As a result of the 2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On 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). In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.

Furthermore, on July 10, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presented 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 requested 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 requested that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal.

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(UNAUDITED)

Mississippi Power ~~would~~expects to seek additional rate relief to address recovery ~~through alternate means, which could include a traditional rate case.~~

Prudence Reviews

Regulatory Assets and Liabilities

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~~Table~~PSC’s final order in the 2015 Rate Case. Other regulatory assets associated with the remainder of ~~Contents~~

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

~~(UNAUDITED)~~

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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(UNAUDITED)

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.

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) 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.

~~162~~

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

~~(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 30, 2014, Mississippi Power had recorded~~These tax ~~benefits totaling $276.4 million for the Phase II~~ credits ~~of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and~~ are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. ~~A portion of~~Through September 30, 2015, Southern Company and Mississippi Power had recorded tax benefits totaling $276 million for the Phase II ~~tax~~ credits, ~~will be subject to recapture upon completion~~ of ~~SMEPA's purchase of an undivided interest in~~which approximately $235 million had been utilized. While the ~~Kemper IGCC as described above.~~

~~In January 2013,~~in-service date for 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 portionremainder of the Kemper IGCC is currently expected to occur in the first half of 2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, but has not made a final determination to that ~~were placed in service~~effect. Due to this uncertainty, Southern Company and Mississippi Power have reflected these tax credits as unrecognized tax benefits and reclassified the Phase II credits to a current liability on ~~August 9, 2014. The~~their September 30, 2015 balance sheets, with no impact to net income. Repayment to the IRS would occur with the quarterly estimated tax payment following a final determination that the in-service date would occur subsequent to April 19, 2016. Any cash ~~flow benefit is approximately $100 million.~~funding requirements necessary for Mississippi Power to make this repayment are expected to be provided by Southern Company. See ~~"Rate Recovery of Kemper IGCC Costs~~ Note (G) herein under "Unrecognized Tax Benefits – ~~Seven-Year Rate Plan" herein~~ Investment Tax Credits" for additional information.

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

178

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~~Other Matters~~

~~Sierra Club Settlement Agreement~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

~~On August 1, 2014,~~(UNAUDITED)

Section 174 Research and Experimental Deduction

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, 2014, and ~~the scrubber project at Plant Daniel Units 1 and 2.~~2015. 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 $414 million as of ~~three years from~~September 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.

~~163~~179

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


(C)	FAIR VALUE MEASUREMENTS

As of September 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 September 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	$	—	$	4	$	—	$	4
Interest rate derivatives									—		20		—		20
Nuclear decommissioning trusts^(a)	632		875		2		1,509		587		869		16		1,472
Cash equivalents	955		—		—		955		747		—		—		747
Other investments	9		—		1		10		9		—		1		10
Total	$	1,596	$	887	$	3	$	2,486	$	1,343	$	893	$	17	$	2,253
Liabilities:
Energy-related derivatives	$	—	$	53	$	—	$	53	$	—	$	211	$	—	$	211
Interest rate derivatives	—		2		—		2		—		36		—		36
Total	$	—	$	55	$	—	$	55	$	—	$	247	$	—	$	247

Alabama Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	5	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts^(b)
Domestic equity	399		78		—		477		346		72		—		418
Foreign equity	34		65		—		99		46		45		—		91
U.S. Treasury and government agency securities	—		34		—		34		—		28		—		28
Corporate bonds	—		98		—		98		10		126		—		136
Mortgage and asset backed securities	—		19		—		19		—		18		—		18
Other	—		8		2		10		—		4		16		20
Cash equivalents	543		—		—		543		484		—		—		484
Total	$	976	$	307	$	2	$	1,285	$	886	$	295	$	16	$	1,197
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	11	$	—	$	54	$	—	$	54
Interest rate derivatives	—		1		—		1		—		17		—		17
Total	$	—	$	12	$	—	$	12	$	—	$	71	$	—	$	71

~~164~~180

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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 September 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	$	—	$	2	$	—	$	2
Interest rate derivatives									—		9		—		9
Nuclear decommissioning trusts^{(b) (c)}
Domestic equity	191		2		—		193		169		1		—		170
Foreign equity	—		132		—		132		—		109		—		109
U.S. Treasury and government agency securities	—		126		—		126		—		112		—		112
Municipal bonds	—		25		—		25		—		74		—		74
Corporate bonds	—		169		—		169		—		166		—		166
Mortgage and asset backed securities	—		114		—		114		—		109		—		109
Other	8		5		—		13		16		5		—		21
Cash equivalents									37		—		—		37
Total	$	199	$	574	$	—	$	773	$	222	$	587	$	—	$	809
Liabilities:
Energy-related derivatives	$	—	$	12	$	—	$	12	$	—	$	16	$	—	$	16
Interest rate derivatives									—		19		—		19
Total									$	—	$	35	$	—	$	35

Gulf Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Cash equivalents	18		—		—		18		$	18	$	—	$	—	$	18
Total	$	18	$	3	$	—	$	21
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	19	—		94		—		94

Mississippi Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents	45		—		—		45		$	64	$	—	$	—	$	64
Total	$	45	$	2	$	—	$	47
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	10	—		47		—		47

Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Interest rate derivatives									$	—	$	1	$	—	$	1
Cash equivalents	80		—		—		80		103		—		—		103
Total	$	80	$	1	$	—	$	81	$	103	$	1	$	—	$	104
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.

~~165~~181

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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,~~2015, approximately ~~$58~~$69 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, which are reflected as "Other" in the table above, 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.

~~166~~182

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of September 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 September 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

109

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

112

None

Daily

15 days

Cash equivalents:

Money market funds

955

None

Daily

Not applicable

747

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

112

None

Daily

15 days

Cash equivalents:

Money market funds

543

None

Daily

Not applicable

484

None

Daily

Not applicable

Georgia Power

Nuclear decommissioning trusts:

Foreign equity funds

132

None

Monthly

5 days

109

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

Cash equivalents:

Money market funds

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

None

Daily

Not applicable

Southern Power

Cash equivalents:

Money market funds

None

Daily

Not applicable

103

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

183

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.

~~167~~

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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 months ended September 30, ~~2014,~~2015, the change in fair value of the funds, including reinvested interest and dividends ~~reduced by~~and excluding the funds' expenses, decreased by ~~$13~~$65 million and ~~increased by $70~~$33 million, respectively, at Southern Company. For the three and nine months ended September 30, ~~2014,~~2015, Alabama Power recorded a decrease in fair value of $8$39 million and ~~an increase of $39~~$19 million, respectively, as ~~an increase~~a decrease in regulatory liabilities. For the three and nine months ended September 30, 2015, Georgia Power recorded a decrease in fair value of $5$26 million and ~~an increase of $31~~$14 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~~184

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of September 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	$	25,489	$	26,099
Alabama Power	$	6,625	$	7,195	$	7,295	$	7,558
Georgia Power	$	9,597	$	10,167	$	9,887	$	10,231
Gulf Power	$	1,444	$	1,517	$	1,310	$	1,338
Mississippi Power	$	2,365	$	2,397	$	2,273	$	2,228
Southern Power	$	1,629	$	1,745	$	2,142	$	2,149

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 September 30, 2015	Three Months Ended September 30, 2014	Nine Months Ended September 30, 2015	Nine Months Ended September 30, 2014
	(in millions)				(in millions)
As reported shares	898	878	894	874	910	898	910	894
Effect of options and performance share award units	4	3	4	5	2	4	3	4
Diluted shares	902	881	898	879	912	902	913	898

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 15 million and 1 million for the three and nine months ended September 30, 2015, respectively, and were 16 million and 17 million for the three and nine months ended September 30, 2014, ~~respectively, and were 16 million and 1 million for the three and nine months ended September 30, 2013.~~respectively.

~~169~~185

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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														—		—			2,096			—				—			2,096
Other comprehensive income (loss)														—		—			(7		)	—				—			(7		)
Stock issued														3,769		—			136			—				—			136
Stock-based compensation														—		—			78			—				—			78
Stock repurchased, at cost														—		(2,599	)		(115		)	—				—			(115		)
Cash dividends on common stock														—		—			(1,465		)	—				—			(1,465		)
Preference stock redemption														—		—			—			(150		)		—			(150		)
Contributions from noncontrolling interest														—		—			—			—				429			429
Distributions to noncontrolling interest														—		—			—			—				(13		)	(13		)
Net income attributable to noncontrolling interest														—		—			—			—				13			13
Other														—		(8	)		(8		)	3				—			(5		)
Balance at September 30, 2015														912,271		(3,332	)		$	20,664		$	609			$	650		$	21,923
	(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			—		—			1,680			—				—			1,680
Other comprehensive income (loss)	—	—		6				—			6			—		—			6			—				—			6
Treasury stock re-issued	—	4,996		225				—			225			—		4,996			225			—			��	—			225
Stock issued	7,781	—		332				—			332			7,781		—			332			—				—			332
Stock repurchased, at cost	—	—		(5		)		—			(5		)	—		—			(5		)	—				—			(5		)
Cash dividends on common stock	—	—		(1,390		)		—			(1,390		)	—		—			(1,390		)	—				—			(1,390		)
Other	—	(51	)	1				—			1			—		(51	)		1			—				—			1
Balance at September 30, 2014	900,514	(702	)	$	19,857			$	756		$	20,613		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


(*)	Primarily related to Southern Power Company.

Stock Repurchased

~~170~~186

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

$115 million. There were no repurchases during the three months ended September 30, 2015 and no further repurchases under this program are anticipated.


(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 30, ~~2014~~2015 was approximately $1.8 ~~billion.~~billion (comprised of approximately $810 million at Alabama Power, $872 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at September 30, ~~2014,~~2015, the traditional operating companies had ~~$423~~approximately $354 million (comprised of approximately $200 million at Alabama Power, $121 million at Georgia Power, and $33 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.~~months, of which $120 million were remarketed by Alabama Power subsequent to September 30, 2015. 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 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		2020	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(a)	$	—	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	1,000	$1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	70		158		50		—		1,030		1,308		1,308		58		—		58		170		—		40		—		500		800	1,340		1,339		—		—		—		40
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—		—		—		—		—		1,750	1,750		1,732		—		—		—		—
Gulf Power	20		60		165		30		—		275		275		50		—		50		30		20		225		30		—		—	275		275		50		—		50		195
Mississippi Power(b)	15		120		165		—		—		300		300		25		40		65		70		15		220		—		—		—	235		210		30		30		60		175
Southern Power(c)	—		—		—		—		500		500		499		—		—		—		—		—		—		—		—		600	600		567		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		50		—		70		—		—		—	70		70		—		—		—		70
Total	$	105	$	408	$	530	$	30	$	4,130	$	5,203	$	5,188	$	153	$	40	$	193	$	320	$	35	$	555	$	30	$	1,500	$4,400	$	6,520	$	6,443	$	80	$	30	$	110	$	480


(a)	Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.


(b)	Subsequent to September 30, 2015, a $15 million bank credit arrangement expired pursuant to its terms.

(c)

As reflected in the table above, in August 2015, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended and restated their multi-year credit arrangements, which, among other things, extended the maturity dates from 2018 to 2020. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $1.25 billion from $1.0 billion and to $600 million from $500 million, respectively. Georgia Power increased its ~~subsidiaries expect~~borrowing ability by $150 million under its facility maturing in 2020, and terminated its aggregate $150 million facilities maturing in 2016. In September 2015, Southern Company entered into an additional multi-year credit arrangement for $1.0 billion with a maturity date of 2018, which contains a covenant that limits debt levels to ~~renew their~~70% of total capitalization, as defined in the agreement. Additionally, Southern Company amended its existing multi-year credit ~~arrangements~~arrangement to increase the limit on debt levels to 70% from 65% of total capitalization, as ~~needed, prior to expiration.~~defined in the agreement. Alabama Power entered into a new $500 million three-year credit arrangement which replaced a majority of Alabama Power's bi-lateral credit arrangements.

~~171~~187

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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.

Financing Activities

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


Company	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^(a)		Revenue Bond Maturities and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(b)
	(in millions)														(in millions)
Southern Company	$	750	$	350	$	—	$	—	$	—		$	—		$	600	$	400	$	—	$	—	$	400	$	—
Alabama Power	400		—		—		—		—			—			975		250		80		134		—		—
Georgia Power	—		—		40		37		1,000			4			—		525		274		268		600		20
Gulf Power	200		—		42		29		—			—			—		60		13		13		—		—
Mississippi Power	—		—		—		—		493			222			—		—		—		—		—		352
Southern Power	—		—		—		—		10			1			650		525		—		—		400		3
Other	—		—		—		—		—			15			—		—		—		—		—		13
Elimination^(c)	—		—		—		—		(220		)	(220		)
Total	$	1,350	$	350	$	82	$	66	$	1,283		$	22		$	2,225	$	1,760	$	367	$	415	$	1,400	$	388

(a)

Includes ~~remarketing~~a reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds purchased and held since April 2015; reofferings by Georgia Power of $104.6 million and $65 million aggregate principal amount of revenue bonds purchased and held since 2013 and April 2015, respectively; and a reoffering by Gulf Power of $13 million aggregate principal amount of revenue bonds ~~previously~~ purchased and held ~~by Gulf Power since December 2013~~in July 2015. Also includes repurchases and ~~remarketing~~reofferings by Georgia Power of ~~$40~~$94.6 million and $10 million aggregate principal amount of revenue bonds ~~previously purchased and held by Georgia Power since 2010.~~in August 2015 in connection with optional tenders.


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


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

Southern Company

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

188

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

In September 2015, Southern Company entered into a $400 million aggregate principal amount 18-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.

Subsequent to September 30, 2015, Southern Company issued $1.0 billion aggregate principal amount of Series ~~2014B 2.15% Senior~~2015A 6.25% Junior Subordinated Notes due ~~September 1, 2019.~~October 15, 2075. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.

Alabama Power

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 in May 2015 to redeem 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.

Georgia Power

~~Pursuant~~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 ~~loan guarantee program established under Title XVII of the Energy Policy Act of 2005,~~public in May 2015.

In May 2015, 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 makereoffered to the ~~FFB under the guarantee.~~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 since 2013.

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,In June 2015, Georgia Power made ~~initial~~additional borrowings under the FFB Credit Facility in an aggregate principal amount of

~~172~~

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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. $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~~the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and ~~the~~4. Georgia Power settled $350 million of interest rate ~~applicable~~swaps related to ~~the remaining $500 million is 3.488%~~this borrowing for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately ~~$66~~$6 million, which will be amortized to interest expense over ~~the life of the borrowings under the FFB Credit Facility.~~10 years.

~~See Note 6 to the financial statements of Southern Company and~~In August 2015, in connection with optional tenders, Georgia Power ~~in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.~~

~~In July 2014, Georgia Power~~repurchased and reoffered to the public ~~$40~~$94.6 million aggregate principal amount of Development Authority of ~~Monroe~~Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant ~~Scherer~~Bowen Project), First Series 2009 ~~which had been previously purchased~~ and ~~held by Georgia Power since 2010.~~

~~Gulf Power~~

~~In April 2014, Gulf Power executed a loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075~~$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue ~~Refunding~~ Bonds (Georgia Power Company Plant Vogtle Project), First Series 2014 (Gulf Power Company Project) due April 1, 2044 for the benefit of Gulf Power. The proceeds were used to redeem $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).

In June 2014, Gulf Power reoffered to the public $13 million aggregate principal amount 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, 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.

~~Mississippi Power~~

In January 2014, Mississippi Power entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $250 million aggregate principal amount, and proceeds were used for working capital and other general corporate purposes, including Mississippi Power's continuous construction program.

In January 2014 and subsequent to September 30, 2014, Mississippi Power received an additional $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. See Note 3 to the financial statements of Southern Company and Mississippi Power in Item 8 of the Form 10-K under "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" 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~~189

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Mississippi Power

In April 2015, Mississippi Power entered into two short-term floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

In June 2015, Mississippi Power issued an 18-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposits in connection with the termination of the APA. See Note (B) under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

Southern Power

In May 2015, Southern Power Company issued $350 million aggregate principal amount of Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to ~~reimburse Mississippi Power~~repay a portion of its outstanding short-term indebtedness, for ~~the cost~~other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the ~~acquisition, construction, equipping, installation, and improvement~~repayment at maturity of ~~certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances~~$525 million aggregate principal amount of ~~the Series 2013A bonds will be~~Southern Power Company's 4.875% Senior Notes on July 15, 2015.

working capital and other general corporate purposes, including Southern ~~Power~~Power's growth strategy and continuous construction program.

During the nine months ended September 30, ~~2014,~~2015, Southern Power prepaid ~~$0.8~~$2.6 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.LLC.


(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.~~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.

~~174~~190

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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~~2015 and ~~2013~~2014 were as follows:


Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)															(in millions)
Three Months Ended September 30, 2015
Service cost																$	65		$	14		$	18		$	3		$	3
Interest cost																111			26			38			5			5
Expected return on plan assets																(181		)	(44		)	(62		)	(8		)	(8		)
Amortization:
Prior service costs																6			2			2			1			—
Net (gain)/loss																53			14			19			2			3
Net cost																$	54		$	12		$	15		$	3		$	3
Nine Months Ended September 30, 2015
Service cost																$	193		$	44		$	54		$	9		$	9
Interest cost																333			79			115			15			16
Expected return on plan assets																(543		)	(133		)	(188		)	(24		)	(25		)
Amortization:
Prior service costs																19			5			7			1			1
Net (gain)/loss																161			41			57			7			8
Net cost																$	163		$	36		$	45		$	8		$	9
Three Months Ended September 30, 2014
Service cost	$	53		$	12		$	16		$	4		$	3		$	53		$	12		$	16		$	4		$	3
Interest cost	109			26			39			4			5			109			26			39			4			5
Expected return on plan assets	(161		)	(42		)	(57		)	(7		)	(8		)	(161		)	(42		)	(57		)	(7		)	(8		)
Amortization:
Prior service costs	6			2			2			—			—			6			2			2			—			—
Net (gain)/loss	28			7			10			1			2			28			7			10			1			2
Net cost	$	35		$	5		$	10		$	2		$	2		$	35		$	5		$	10		$	2		$	2
Nine Months Ended September 30, 2014
Service cost	$	160		$	36		$	47		$	8		$	8		$	160		$	36		$	47		$	8		$	8
Interest cost	326			78			115			14			15			326			78			115			14			15
Expected return on plan assets	(484		)	(126		)	(170		)	(21		)	(22		)	(484		)	(126		)	(170		)	(21		)	(22		)
Amortization:
Prior service costs	19			5			7			1			1			19			5			7			1			1
Net (gain)/loss	83			23			30			3			4			83			23			30			3			4
Net cost	$	104		$	16		$	29		$	5		$	6		$	104		$	16		$	29		$	5		$	6
Three Months Ended September 30, 2013
Service cost	$	58		$	12		$	17		$	3		$	3
Interest cost	97			23			35			4			5
Expected return on plan assets	(151		)	(39		)	(54		)	(6		)	(7		)
Amortization:
Prior service costs	7			2			3			—			1
Net (gain)/loss	50			13			19			2			2
Net cost	$	61		$	11		$	20		$	3		$	4
Nine Months Ended September 30, 2013
Service cost	$	174		$	39		$	52		$	8		$	8
Interest cost	291			69			104			13			14
Expected return on plan assets	(452		)	(117		)	(160		)	(19		)	(20		)
Amortization:
Prior service costs	20			5			8			1			1
Net (gain)/loss	150			39			56			6			7
Net cost	$	183		$	35		$	60		$	9		$	10

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(UNAUDITED)


Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)															(in millions)
Three Months Ended September 30, 2015
Service cost																$	6		$	1		$	2		$	1		$	—
Interest cost																20			5			9			—			1
Expected return on plan assets																(15		)	(6		)	(6		)	—			—
Amortization:
Prior service costs																1			2			—			—			—
Net (gain)/loss																4			—			2			—			—
Net cost																$	16		$	2		$	7		$	1		$	1
Nine Months Ended September 30, 2015
Service cost																$	17		$	4		$	5		$	1		$	1
Interest cost																59			15			26			2			3
Expected return on plan assets																(44		)	(19		)	(18		)	(1		)	(1		)
Amortization:
Prior service costs																3			3			—			—			—
Net (gain)/loss																13			1			8			—			—
Net cost																$	48		$	4		$	21		$	2		$	3
Three Months Ended September 30, 2014
Service cost	$	5		$	1		$	2		$	—		$	—		$	5		$	1		$	2		$	—		$	—
Interest cost	19			5			9			—			—			19			5			9			—			—
Expected return on plan assets	(14		)	(6		)	(6		)	—			—			(14		)	(6		)	(6		)	—			—
Amortization:
Prior service costs	1			1			—			—			—			1			1			—			—			—
Net (gain)/loss	1			—			—			—			—			1			—			—			—			—
Net cost	$	12		$	1		$	5		$	—		$	—		$	12		$	1		$	5		$	—		$	—
Nine Months Ended September 30, 2014
Service cost	$	16		$	4		$	5		$	1		$	1		$	16		$	4		$	5		$	1		$	1
Interest cost	59			15			26			2			2			59			15			26			2			2
Expected return on plan assets	(44		)	(19		)	(19		)	(1		)	(1		)	(44		)	(19		)	(19		)	(1		)	(1		)
Amortization:
Prior service costs	3			3			—			—			—			3			3			—			—			—
Net (gain)/loss	2			—			1			—			—			2			—			1			—			—
Net cost	$	36		$	3		$	13		$	2		$	2		$	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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(UNAUDITED)


(G)	~~EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS~~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. 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 $212 million of federal income tax benefits as of September 30, 2015, compared to $305 million as of December 31, 2014. The carryforwards as of September 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.

~~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)~~(20.9)% for the nine months ended September 30, ~~2014~~2015 compared to ~~(42.1)~~(45.5)% for the corresponding period in ~~2013.~~2014. The ~~change in the tax benefit~~increase was primarily due to ~~an increase~~a reduction in tax benefits related to the estimated probable losses on construction of the Kemper IGCC, and a decrease in non-taxable AFUDC equity related to ~~the construction of~~placing the Kemper IGCC ~~partially offset by a lower net loss for the current period compared to the corresponding period~~combined cycle in ~~2013.~~service in August 2014.

Southern Power

Southern Power's effective tax rate was ~~14.4%~~6.9% for the nine months ended September 30, ~~2014~~2015 compared to ~~20.5%~~14.4% for the corresponding period in ~~2013.~~2014. The decrease was primarily due to ~~the impact of state apportionment changes which reduced Southern Power's deferred tax liabilities, a change in filing method for North Carolina~~increased federal income tax ~~an increase~~benefits related to ITCs in 2015, partially offset by higher pre-tax earnings in 2015 and beneficial state income tax ~~credits, and beneficial~~ changes in ~~certain state income tax laws. The decrease was partially offset by less federal income tax benefit related to investment tax credits in the current year.~~2014.

Unrecognized Tax Benefits

~~For~~See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.

Changes during 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	24		7			31
Tax positions from prior periods	459		(6		)	456
Reductions due to settlements	—		—			—
Balance as of September 30, 2015	$	648	$	6		$	657

The tax positions from prior periods relate primarily to 2008 through 2013 amended federal income tax ~~year,~~ returns that were filed to include deductions for Kemper IGCC-related R&E expenditures and deferred federal investment tax credits that no longer meet the more-likely-than-not recognition threshold. See "Section 174 Research and Experimental Deduction" and "Investment Tax Credits" herein for additional information.

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(UNAUDITED)

The impact on the effective tax rate, if recognized, was as follows:



	As of September 30, 2015							As of December 31, 2014
	Mississippi Power			Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	(2	)	$	6	$	7	$	10
Tax positions not impacting the effective tax rate	650			—		650		160
Balance of unrecognized tax benefits	$	648		$	6	$	657	$	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 and deferred federal investment tax credits that no longer meet the more-likely-than-not recognition threshold. See "Section 174 Research and Experimental Deduction" and "Investment Tax Credits" 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 2015, and included in its 2013 and 2014 consolidated federal income tax ~~return a deduction~~returns 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 Southern Company and Mississippi Power ~~and Southern Company~~ believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power ~~and Southern Company recorded an~~had related unrecognized tax ~~benefit~~benefits associated with these R&E deductions of approximately ~~$100~~$414 million and associated interest of $2$7 million as of September 30, ~~2014.~~

2015. The ultimate outcome of this matter cannot be determined at this time.

Investment Tax Credits

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. These tax credits 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. Through September 30, 2015, Southern Company and Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $235 million had been utilized. While the in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016, Mississippi Power now anticipates the in-service date to occur subsequent to April 19, 2016, but has not made a final determination to that effect. As of September 30, 2015, the more-likely-than-not threshold had no longer been met for recognition of these benefits; therefore, Southern Company and Mississippi Power have reflected these tax credits as unrecognized tax benefits and reclassified the Phase II credits to a current liability on their September 30, 2015 balance sheets, with no impact to net income. Repayment to the IRS would occur with the quarterly estimated tax payment following a final determination that the in-service date would occur subsequent to April 19, 2016. The ultimate outcome of this matter cannot be determined at this time.

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(UNAUDITED)


(H)	DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate ~~risk, and occasionally foreign currency~~ risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note (C) herein for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating ~~activities and the cash impacts of settled foreign currency derivatives are recorded as investing~~ activities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel 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 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

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(UNAUDITED)

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	221	2020	2017
Alabama Power	57	2017	—	50	2018
Georgia Power	47	2017	—	50	2017
Gulf Power	77	2018	—	83	2020
Mississippi Power	49	2017	—	37	2018
Southern Power	2	—	2017	1	2016	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,~~ 4 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 30, ~~2015~~2016 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.

~~At September 30, 2014,~~ Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in 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 )
statements of income as incurred.

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(UNAUDITED)

~~Subsequent to~~At September 30, ~~2014, Alabama Power entered into forward-starting~~2015, the following 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.~~derivatives were outstanding:

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 September 30, 2015
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power	$	200		3-month LIBOR	2.93%	October 2025		$	(17	)
Georgia Power	350			3-month LIBOR	2.57%	November 2025		(18		)
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		8
Georgia Power	250			5.40%	3-month LIBOR + 4.02%	June 2018		3
Georgia Power	200			4.25%	3-month LIBOR + 2.46%	December 2019		5
Derivatives not Designated as Hedges
Southern Power^(a)	65		^(b)	3-month LIBOR	2.50%	October 2016	^(c)	1
Total	$	2,065						$	(16	)


(a)	Swaption at RE Tranquillity LLC, a subsidiary of Tranquillity. See Note (I) to the Condensed Financial Statements herein for additional information regarding Tranquillity.


(b)	Amortizing notional amount.


(c)	Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending September 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~~

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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.~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Financial Statement Presentation and Amounts

At September 30, ~~2014,~~2015, 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
Asset Derivatives at September 30, 2015													Asset Derivatives at September 30, 2015
	Fair Value													Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power			Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)													(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	9	$	4	$	1	$	2	$	2				$	3	$	1	$	2	$	—	$	—
Other deferred charges and assets	2		1		—		1		—					1		1		—		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	11	$	5	$	1	$	3	$	2	N/A			$	4	$	2	$	2	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	2	$	—	$	—	$	—	$	—	$	—		$	11	$	—	$	5	$	—	$	—	$	—
Other deferred charges and assets														8		—		4		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges														$	19	$	—	$	9	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Interest rate derivatives:
Other deferred charges and assets														$	1	$	—	$	—	$	—	$	—	$	1
Total asset derivatives	$	13	$	5	$	1	$	3	$	2	$	—		$	24	$	2	$	11	$	—	$	—	$	1



Liability Derivatives at September 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^(*)	$	117	$	36	$	14	$	41	$	26
Other deferred credits and liabilities	94		18		2		53		21
Total derivatives designated as hedging instruments for regulatory purposes	$	211	$	54	$	16	$	94	$	47	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities^(*)	$	36	$	17	$	19	$	—	$	—	$	—
Total liability derivatives	$	247	$	71	$	35	$	94	$	47	$	—


(*)	Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At December 31, 2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:



Asset Derivatives at December 31, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	7	$	1	$	6	$	—	$	—
Other deferred charges and assets	—		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	1	$	7	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	5	$	—	$	—	$	—
Other deferred charges and assets	1		—		1		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	8	$	—	$	6	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets	$	6	$	—	$	—	$	—	$	—	$	5
Total asset derivatives	$	21	$	1	$	13	$	—	$	—	$	5

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


Liability Derivatives at September 30, 2014
Liability Derivatives at December 31, 2014													Liability 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:
Liabilities from risk management activities ^(a)	$	27	$	5	$	10	$	7	$	5
Other current liabilities^(*)														$	118	$	32	$	23	$	37	$	26
Other deferred credits and liabilities	25		6		2		12		5					79		21		4		35		19
Total derivatives designated as hedging instruments for regulatory purposes	$	52	$	11	$	12	$	19	$	10	N/A			$	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	$	4	$	1	$	—	$	—	$	—	$	—		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	$	56	$	12	$	12	$	19	$	10	$	—		$	225	$	61	$	41	$	72	$	45	$	4


~~(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."

~~At December 31, 2013, 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
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 $ 16
$ 5
$ 3
$ 5
$ 3

Other deferred charges and assets 7
2
2
2
2

Total derivatives designated as hedging instruments for regulatory purposes $ 23
$ 7
$ 5
$ 7
$ 5
N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets $ 3
$ —
$ —
$ —
$ —
$ —
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets 1
—
—
—
—
1
Total asset derivatives $ 27
$ 7
$ 5
$ 7
$ 5
$ 1

~~181~~

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

~~(UNAUDITED)~~

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 Power includes liabilities from risk management activities in other current liabilities.~~

The derivative contracts of Southern Company, the traditional operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and are reported gross on each registrant's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at September 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.~~

Derivative Contracts at September 30, 2014
Fair Value

Southern
Company

Alabama
Power

Georgia
Power

Gulf
Power

Mississippi
Power

Southern
Power
(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)
$ 12
$ 5
$ 1
$ 3
$ 2
$ 1
Gross amounts not offset in the Balance Sheet ^(b)
(11 ) (4 ) (1 ) (3 ) (2 ) —
Net energy-related derivative assets $ 1
$ 1
$ —
$ —
$ —
$ 1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)
$ 53
$ 11
$ 12
$ 19
$ 10
$ 1
Gross amounts not offset in the Balance Sheet ^(b)
(11 ) (4 ) (1 ) (3 ) (2 ) —
Net energy-related derivative liabilities $ 42
$ 7
$ 11
$ 16
$ 8
$ 1

(a) None of the registrants offset 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.~~

~~182~~200

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Contracts at December 31, 2013
Fair Value

Southern
Company

Alabama
Power

Georgia
Power

Gulf
Power

Mississippi
Power

Southern
Power
(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)
$ 24
$ 7
$ 5
$ 7
$ 5
$ 1
Gross amounts not offset in the Balance Sheet ^(b)
(22 ) (5 ) (5 ) (6 ) (4 ) —
Net energy-related derivative assets $ 2
$ 2
$ —
$ 1
$ 1
$ 1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)
$ 56
$ 8
$ 21
$ 17
$ 10
$ 1
Gross amounts not offset in the Balance Sheet ^(b)
(22 ) (5 ) (5 ) (6 ) (4 ) —
Net energy-related derivative liabilities $ 34
$ 3
$ 16
$ 11
$ 6
$ 1

~~(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.~~

At September 30, 2014 and December 31, 2013, 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
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 $ (27 ) $ (5 ) $ (10 ) $ (7 ) $ (5 )
Other regulatory assets, deferred (25 ) (6 ) (2 ) (12 ) (5 )
Other regulatory liabilities, current 9
4
1
2
2
Other regulatory liabilities, deferred ^(a)
2
1
—
1
—
Total energy-related derivative gains (losses) $ (41 ) $ (6 ) $ (11 ) $ (16 ) $ (8 )



Derivative Contracts at September 30, 2015
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power		Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	4		$	2		$	2		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet ^(b)	(4		)	(2		)	(2		)	—		—		—
Net energy-related derivative assets	$	—		$	—		$	—		$	—	$	—	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet ^(a)	$	20		$	—		$	9		$	—	$	—	$	1
Gross amounts not offset in the Balance Sheet ^(b)	(9		)	—			(2		)	—		—		—
Net interest rate derivative assets	$	11		$	—		$	7		$	—	$	—	$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	211		$	54		$	16		$	94	$	47	$	—
Gross amounts not offset in the Balance Sheet ^(b)	(4		)	(2		)	(2		)	—		—		—
Net energy-related derivative liabilities	$	207		$	52		$	14		$	94	$	47	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet ^(a)	$	36		$	17		$	19		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet ^(b)	(9		)	—			(2		)	—		—		—
Net interest rate derivative liabilities	$	27		$	17		$	17		$	—	$	—	$	—


(a)	~~Georgia Power includes other regulatory~~None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities ~~deferred in other deferred credits~~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 ~~liabilities.~~any cash/financial collateral pledged or received.

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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 )



Derivative Contracts at December 31, 2014
	Fair Value
	Southern Company			Alabama Power		Georgia Power			Gulf Power		Mississippi Power		Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	13		$	1	$	7		$	—	$	—	$	5
Gross amounts not offset in the Balance Sheet ^(b)	(9		)	—		(7		)	—		—		—
Net energy-related derivative assets	$	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)	$	201		$	53	$	27		$	72	$	45	$	4
Gross amounts not offset in the Balance Sheet ^(b)	(9		)	—		(7		)	—		—		—
Net energy-related derivative liabilities	$	192		$	53	$	20		$	72	$	45	$	4
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet ^(a)	$	24		$	8	$	14		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet ^(b)	(8		)	—		(6		)	—		—		—
Net interest rate derivative liabilities	$	16		$	8	$	8		$	—	$	—	$	—


(a)	None of the registrants 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At September 30, 2015 and December 31, 2014, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:



Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at September 30, 2015
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	$	(117	)	$	(36	)	$	(14	)	$	(41	)	$	(26	)
Other regulatory assets, deferred	(94		)	(18		)	(2		)	(53		)	(21		)
Other regulatory liabilities, current ^(a)	3			1			2			—			—
Other regulatory liabilities, deferred ^(b)	1			1			—			—			—
Total energy-related derivative gains (losses)	$	(207	)	$	(52	)	$	(14	)	$	(94	)	$	(47	)


(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 ~~and nine~~ months ended September 30, ~~2014~~2015 and 2013, 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,2014, the pre-tax effects of interest rate derivatives designated as ~~fair value~~cash flow hedging instruments onwere 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	$	(28	)	$	(1	)	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Alabama Power
Interest rate derivatives	$	(10	)	$	(1	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Georgia Power
Interest rate derivatives	$	(18	)	$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)

For the ~~statements of income were offset by changes to the carrying value of long-term debt~~nine months ended September 30, 2015 and 2014, the pre-tax effects of ~~foreign currency~~interest rate derivatives designated as ~~fair value~~cash flow hedging instruments ~~on the statements~~were as follows:

203

Table of ~~income were offset by changes in the fair value of the purchase commitment related to equipment purchases.~~Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)



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	$	(26	)	$	(1	)	Interest expense, net of amounts capitalized	$	(7	)	$	(6	)
Alabama Power
Interest rate derivatives	$	(9	)	$	(1	)	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Georgia Power
Interest rate derivatives	$	(17	)	$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(2	)
Mississippi Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)

For the three and nine months ended September 30, ~~2014~~2015 and ~~2013,~~2014, 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 months ended September 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:



Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
Derivative Category	Statements of Income Location	2015		2014
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	15	$	(1	)
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	7	$	—

For the nine months ended September 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:



Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
Derivative Category	Statements of Income Location	2015		2014
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	19	$	(4	)
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	9	$	—

For the three and nine months ended September 30, 2015 and 2014, 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and nine months ended September 30, ~~2014~~2015 and ~~2013,~~2014, the pre-tax effects of energy-related derivatives and ~~foreign currency~~interest rate 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 income for the three and nine months ended September 30, 2014 and 2013. This third party hedging activity has been discontinued.

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 30, ~~2014,~~2015, the registrants' collateral posted with their derivative counterparties was immaterial.

At September 30, ~~2014,~~2015, the fair value of derivative liabilities with contingent features was ~~$26~~$54 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~~$54 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have

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~~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~~Southern Company

~~See Note 2~~Proposed Merger with AGL Resources

On August 23, 2015, Southern Company, AGL Resources, and Merger Sub entered into the Merger Agreement. Under the terms of the Merger Agreement, subject to the ~~financial statements~~satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned direct subsidiary of Southern ~~Power under "Adobe Solar, LLC" in Item 8~~Company. Upon the consummation of the ~~Form 10-K for additional information.~~

~~On April 17, 2014, Southern Power~~Merger, each share of common stock of AGL Resources issued and ~~TRE, through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, acquired all~~outstanding immediately prior to the effective time of the ~~outstanding membership interests~~Merger (Effective Time), other than shares owned by AGL Resources as treasury stock, shares owned by a subsidiary of ~~Adobe~~AGL Resources, and shares owned by shareholders who have properly exercised and perfected dissenters' rights, will be converted into the right to receive $66 in cash, without interest and less any applicable withholding taxes. Other equity-based securities of AGL Resources will be cancelled for cash consideration or converted into new awards from ~~Sun Edison, LLC,~~Southern Company as described in 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 inMerger Agreement.

In accordance with ~~Southern Power's overall growth strategy.~~

~~Southern Power's~~GAAP, the Merger will be accounted for using the acquisition method of Adobe included cash consideration of approximately $96.2 million. The fair values of the assets, liabilities, and intangibles acquired were recorded as follows: $83.5 million to property, plant, and equipment, $14.5 million to receivables related to reimbursable transmission costs and $6.3 million to PPA intangible, resulting in a $5.1 million bargain purchase gain 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. Acquisition-related costs were expensed as incurred and were not material.

~~Macho Springs Solar, LLC~~

~~On May 22, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of~~ ~~Macho Springs~~ ~~from First Solar Development, LLC, the original developer of the project. Macho Springs constructed and owns an approximately~~ 50~~-MW solar photovoltaic facility in Luna County, New Mexico. The solar facility began commercial operation on May 23,~~ ~~2014~~ ~~and the entire output of the plant is contracted under a~~ 20~~-year PPA with~~ ~~El Paso 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 approximately $130.0 million. As of September 30, 2014, the fair value of~~accounting whereby the assets acquired ~~was recorded primarily~~and liabilities assumed are recognized at fair value as ~~property, plant, and equipment; however,~~of the ~~allocation~~acquisition date. The excess of the purchase price ~~to individual~~over the fair values of AGL Resources' 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~~

Subsequent to September 30, 2014, 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 constructing an approximately 150-MW solar photovoltaic facility in Southern California (Imperial Facility), which is expected to begin commercial operation later in the fourth quarter 2014. The Imperial Facility's output is contracted under a 25-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy. This PPAliabilities will be ~~accounted for~~recorded as ~~an operating lease. The acquisition~~goodwill. Southern Company expects total cash of $8.2 billion to be required to fund the ~~Imperial Facility aligns with Southern Power's overall growth strategy.~~

~~In connection with this acquisition, Holdings made an aggregate payment (consisting of cash consideration and a secured promissory note)~~purchase price of approximately ~~$128 million~~$8.0 billion to ~~the subsidiary~~acquire AGL Resources common stock, options to purchase shares of ~~First Solar~~AGL Resources common stock, and ~~became obligated~~restricted stock units payable in shares of AGL Resources common stock and to ~~pay the contract price as it becomes due under the construction contract for the Imperial Facility. The allocation~~fund acquisition-related expenses and financing costs of approximately $200 million. Southern Company will also assume AGL Resources' outstanding indebtedness.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Consummation of the ~~purchase price~~Merger is subject to ~~individual assets has not been finalized. In addition,~~the satisfaction or waiver of certain closing conditions, including, among others, (i) approval of the Merger Agreement by AGL Resources' shareholders, which is scheduled for vote on November 19, 2015, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, (iii) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC, New Jersey Board of Public Utilities, and Virginia State Corporation Commission, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources and any other approval which Southern Company and AGL Resources agree are required, (iv) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (v) other customary closing conditions, including (a) subject to certain ~~terms~~materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement. Southern Company expects to complete the required state regulatory filings in the fourth quarter 2015.

Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all conditions ~~a subsidiary~~to closing other than those relating to (i) regulatory approvals and (ii) the absence of ~~First Solar~~legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied. Upon termination of the Merger Agreement under certain specified circumstances, AGL Resources 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~~required to pay ~~off~~Southern Company a termination fee of $201 million or reimburse Southern Company's expenses up to $5 million (which reimbursement shall reduce on a dollar-for-dollar basis any termination fee subsequently payable by AGL Resources). Southern Company currently expects to complete the ~~previously~~transaction in the second half of 2016.

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

Merger Financing

Southern Company intends to initially fund the cash consideration for the Merger using approximately $7.0 billion of debt and $1.0 billion of equity. Southern Company expects to issue approximately $2.0 billion of additional equity through 2019 to offset a portion of the debt issued ~~secured promissory note and~~ to fund the cash consideration for the Merger. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. See Note (E) under "Bank Credit Arrangements" herein for additional information regarding the Bridge Agreement.

Southern Power

See Note 2 to the financial statements of Southern Power under "2014 – SG2 Imperial ~~Facility's~~Valley, LLC" in Item 8 of the Form 10-K for additional information. During the second quarter 2015, the fair values of the assets acquired of SG2 Imperial Valley, LLC were finalized and recorded as follows: $707 million as property, plant, and equipment and $20 million as prepayments related to transmission services.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

During 2015, Southern Power Company acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc. (SRE), the following projects in accordance with its overall growth strategy, which are included in its capital program estimates for 2015. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.

Project Entity

Seller; Acquisition Date

Approx. Nameplate Capacity

Location

Southern Power Percentage Ownership

Expected/Actual Commercial Operation Date

PPA
Counterparties for Entire Plant Output

PPA Contract Period

Approx. Purchase Price

(MW)

(in millions)

WIND

Kay Wind, LLC

Apex Clean Energy Holdings, LLC

299

Kay County, Oklahoma

100

Fourth quarter 2015

Westar Energy, Inc. and Grant River Dam Authority

20 years

492

(a)

Grant Wind, LLC

Apex Clean Energy Holdings, LLC

151

Grant County, Oklahoma

100

First quarter 2016

Western Farmers, East Texas, and Northeast Texas Electric Cooperative

20 years

264

(a)

SOLAR

Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell)

First Solar, Inc. (First Solar)
April 15, 2015

Kern County, California

(b)

April 17, 2015

City of Roseville, California/Pacific Gas and Electric Company

29 years

(c)

NS Solar Holdings, LLC (North Star)

First Solar
April 30, 2015

Fresno County, California

(b)

June 20, 2015

Pacific Gas and Electric Company

20 years

211

(d)

Tranquillity

Recurrent Energy, LLC
August 28, 2015

204

Fresno County, California

(b)

Fourth quarter 2016

Shell Energy North America (US), LP/Southern California Edison Company

18 years

100

(e)

Desert Stateline Holdings, LLC (Desert Stateline)

First Solar
August 31, 2015

300

San Bernardino County, California

(b)

8 Phases from December 2015 to Third quarter 2016

Southern California Edison Company

20 years

439

(f)

GASNA 31P, LLC (Morelos)

Solar Frontier Americas Holding, LLC
October 22, 2015

Kern County, California

Fourth quarter 2015

Pacific Gas and Electric Company

20 years

(g)

(a) On February 24, 2015 and September 4, 2015, Southern Power entered into agreements to acquire Kay Wind, LLC and Grant Wind, LLC, respectively. The completion of each acquisition is subject to the seller achieving certain construction ~~costs. As a result of these capital contributions,~~and project milestones, as well as various other customary conditions to closing. Each acquisition is expected to close at or near the ~~aggregate~~expected commercial operation date. In addition, the final purchase price ~~payable by~~may be adjusted based on performance testing as specified in the applicable purchase agreement. The Grant Wind, LLC purchase price includes contingent consideration. The ultimate outcome of this matter cannot be determined at this time.

(b) Southern Power ~~for the acquisition is approximately $508 million. Following these capital contributions, Southern Power will indirectly own~~owns 100% of the class A membership interests and a wholly-owned subsidiary of ~~Holdings and be entitled to 51% of all cash distributions from Holdings, and First Solar will indirectly own~~the seller owns 100% of the class B membership ~~interests of Holdings~~interests. Southern Power and bethe class B member are entitled to 51% and 49%, respectively, of all cash distributions from ~~Holdings.~~the respective project. In addition, Southern Power ~~will be~~is entitled to substantially all of the federal tax benefits with respect to ~~this~~the respective transaction.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

equipment and $9 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not ~~achieve substantialcompletion by~~been finalized.

$106 million, respectively. The ultimate outcome of this matter cannot be determined at this ~~time; however, Holdings believes the likelihood~~time.

(f) Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the ~~Rescission Payment~~class B membership interests for approximately $223 million. As of September 30, 2015, the fair values of the assets acquired, which includes Southern Power's and ~~Transfer~~First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Southern Power's and First Solar's remaining combined future payments, including construction payments, are estimated to be ~~remote~~between $827 million to $844 million. The ultimate outcome of this matter cannot be determined at this time.

(g) On October 22, 2015, SRE and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC, a jointly-owned subsidiary owned 90% by SRE, acquired all of the ~~acquisition date.~~outstanding membership interests of Morelos. The total purchase price, including TRE's 10% ownership, is approximately $50 million.

Construction Projects

~~186~~208

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power Company's construction projects, excluding the Tranquillity and Desert Stateline construction projects discussed above, are detailed in the table below:

Solar Project

Seller

Approx. Nameplate Capacity

County Location in Georgia

Expected Commercial Operation Date

PPA Counterparties
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

(c)

Decatur County

TradeWind Energy, Inc.

Decatur

December 2015

Georgia Power^(b)

20 years

$47

(c)

Butler

CERSM, LLC and Community Energy, Inc.

103

Taylor

December 2016

Georgia Power^(b)

30 years

220

$230

(c)

Pawpaw

Longview Solar, LLC

Taylor

December 2015

Georgia Power^(a)

30 years

$80

(c)

Butler Solar Farm

Strata Solar Development, LLC

Taylor

December 2015

Georgia Power^(b)

20 years

$48

(c)


(a)	Approved by the FERC subsequent to September 30, 2015.


(b)	Subject to FERC approval.


(c)	Includes the acquisition price of all outstanding membership interests.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(J) SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $104 million and $303 million for the three and nine months ended September 30, 2015, respectively, and $103 million and $243 million for the three and nine months ended September 30, 2014, ~~respectively, and $97 million and $264 million for the three and nine months ended September 30, 2013,~~ 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 months ended September 30, ~~2014~~2015 and ~~2013~~2014 was as follows:

Electric Utilities

Traditional
Operating
Companies

Southern
Power
Eliminations Total
All
Other
Eliminations Consolidated
(in millions)
Three Months Ended September 30, 2014:
Operating revenues $ 5,007
$ 435
$ (115 ) $ 5,327
$ 34
$ (22 ) $ 5,339
Segment net income (loss)^(a)(b)
658
64
—
722
(2 ) (2 ) 718
Nine Months Ended September 30, 2014:
Operating revenues $ 13,594
$ 1,115
$ (301 ) $ 14,408
$ 114
$ (72 ) $ 14,450
Segment net income (loss)^(a)(c)
1,557
128
—
1,685
—
(5 ) 1,680
Total assets at September 30, 2014 $ 62,419
$ 4,609
$ (166 ) $ 66,862
$ 1,304
$ (512 ) $ 67,654
Three Months Ended September 30, 2013:
Operating revenues $ 4,744
$ 365
$ (104 ) $ 5,005
$ 35
$ (23 ) $ 5,017
Segment net income (loss)^(a)(b)
765
85
—
850
(1 ) 3
852
Nine Months Ended September 30, 2013:
Operating revenues $ 12,430
$ 975
$ (285 ) $ 13,120
$ 108
$ (68 ) $ 13,160
Segment net income (loss)^(a)(c)
1,099
142
—
1,241
(12 ) 1
1,230
Total assets at December 31, 2013 $ 59,447
$ 4,429
$ (101 ) $ 63,775
$ 1,077
$ (306 ) $ 64,546

~~(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 30, 2014 and September 30, 2013 includes a $418.0 million pre-tax charge ($258.1 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.



	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2015:
Operating revenues	$	5,098	$	401	$	(109	)	$	5,390	$	37		$	(26	)	$	5,401
Segment net income (loss)^(a)(b)	874		102		—			976		(18		)	1			959
Nine Months Ended September 30, 2015:
Operating revenues	$	13,123	$	1,086	$	(322	)	$	13,887	$	120		$	(86	)	$	13,921
Segment net income (loss)^(a)(c)	1,912		181		—			2,093		3			—			2,096
Total assets at September 30, 2015	$	67,750	$	7,040	$	(404	)	$	74,386	$	1,480		$	(651	)	$	75,215
Three Months Ended September 30, 2014:
Operating revenues	$	5,007	$	435	$	(115	)	$	5,327	$	34		$	(22	)	$	5,339
Segment net income (loss)^(a)(b)	658		64		—			722		(2		)	(2		)	718
Nine Months Ended September 30, 2014:
Operating revenues	$	13,594	$	1,115	$	(301	)	$	14,408	$	114		$	(72	)	$	14,450
Segment net income (loss)^(a)(c)	1,557		128		—			1,685		—			(5		)	1,680
Total assets at December 31, 2014	$	64,644	$	5,550	$	(131	)	$	70,063	$	1,156		$	(296	)	$	70,923

(c) Segment net income (loss) for the traditional operating companies for the nine months ended September 30, 2014 and September 30, 2013 includes $798.0 million in pre-tax charges ($492.8 million after tax) and $1.14 billion in pre-tax charges ($704.0 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.


(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 30, 2015 and September 30, 2014 includes pre-tax charges of $150 million ($93 million after tax) and a pre-tax charge of $418 million ($258 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 months ended September 30, 2015 and September 30, 2014 includes pre-tax charges of $182 million ($112 million after tax) and pre-tax charges of $798 million ($493 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services


	Electric Utilities' Revenues								Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total		Retail		Wholesale		Other		Total
	(in millions)								(in millions)
Three Months Ended September 30, 2015									$	4,701	$	520	$	169	$	5,390
Three Months Ended September 30, 2014	$	4,558	$	600	$	169	$	5,327	4,558		600		169		5,327
Three Months Ended September 30, 2013	4,319		520		166		5,005

Nine Months Ended September 30, 2015									$	11,958	$	1,435	$	494	$	13,887
Nine Months Ended September 30, 2014	$	12,186	$	1,719	$	503	$	14,408	12,186		1,719		503		14,408
Nine Months Ended September 30, 2013	11,237		1,406		477		13,120

~~188~~211

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~~In addition to the factors described in RISK FACTORS in Item 1A of the Form 10-K, Southern Company faces the following additional risks:

Risks Related to the Proposed Merger with AGL Resources

Southern Company and AGL Resources may encounter difficulties in satisfying the conditions for the completion of the Merger, including receipt of all required regulatory approvals, which could delay the completion of the Merger or impose conditions that could have a material adverse effect on the combined company or that could cause either party to abandon the Merger.

Consummation of the Merger is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval of the Merger Agreement by AGL Resources' shareholders, which is scheduled for vote on November 19, 2015, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, (iii) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC, New Jersey Board of Public Utilities, and Virginia State Corporation Commission, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources and any other approval which Southern Company and AGL Resources agree are required, (iv) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (v) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement.

Southern Company expects to complete the required state regulatory filings in the fourth quarter 2015. These governmental entities may decline to approve the Merger or may impose conditions on the completion, or require changes to the terms, of the Merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following the Merger.

Satisfying the conditions to completion of the Merger may take longer, and could cost more, than Southern Company expects. Any delay in completing the Merger or any additional conditions imposed in order to complete the Merger may materially adversely affect the benefits that Southern Company expects to achieve from the Merger and the integration of the companies' respective businesses.

In addition, conditions to the completion of the Merger may fail to be satisfied. Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied.

Any delay in completing the Merger, conditions imposed by governmental entities, or failure to complete the Merger could have a material adverse effect on the financial condition, net income, and cash flows of Southern Company.

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Table of Contents

Failure to complete the Merger could negatively impact Southern Company's stock price and Southern Company's future business and financial results.

Completion of the Merger is not assured and is subject to risks, including the risks that approval of the transaction by governmental entities will not be obtained or that certain other closing conditions will not be satisfied. If the Merger is not completed, Southern Company's ongoing businesses and financial results may be adversely affected and Southern Company will be subject to a number of risks, including the following:

Southern Company will be required to pay significant costs relating to the Merger, including legal, accounting, and financial advisory costs, whether or not the Merger is completed;

matters relating to the Merger (including integration planning) may require substantial commitments of time and resources by Southern Company management, which could otherwise have been devoted to other opportunities that may have been beneficial to Southern Company; and

negative publicity and a negative impression of Southern Company in the investment community.

The occurrence of any of these events, individually or in combination, could cause the share price of Southern Company to decline if and to the extent that the current market prices reflect an assumption by the market that the Merger will be completed.

If completed, the Merger may not achieve its intended results.

Southern Company entered into the Merger Agreement with the expectation that the Merger would result in various benefits. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the business of AGL Resources is integrated in an efficient and effective manner, conditions imposed on the Merger by federal and state public utility, antitrust, and other regulatory authorities prior to approval, general market and economic conditions, and general competitive factors in the market place. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company, and diversion of management's time and energy and could have an adverse effect on the combined company's financial condition, net income, and cash flows.

The Southern Company system will be subject to business uncertainties while the Merger is pending that could adversely affect Southern Company's financial results.

Uncertainty about the effect of the Merger on employees, suppliers, and customers of the Southern Company system may have an adverse effect on Southern Company. These uncertainties may impair the Southern Company system's ability to attract, retain, and motivate key personnel until the Merger is completed and for a ~~discussion~~period of time thereafter and could cause customers, suppliers, and others that deal with the Southern Company system to seek to change existing business relationships.

Employee retention and recruitment may be particularly challenging prior to the completion of the ~~risk factors~~Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If key employees depart or fail to accept employment with the Southern Company system because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, Southern Company's financial results could be adversely affected.

The pursuit of the ~~registrants. There~~Merger and the preparation for the integration of AGL Resources into the Southern Company system may place a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could adversely affect Southern Company's financial results.

Southern Company is obligated to complete the Merger whether or not it has obtained the required financing.

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Table of Contents

Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. The Bridge Agreement is subject to various conditions contained in the Bridge Agreement and the issuance of long-term debt and equity sales to finance the Merger will be subject to future market conditions.

Pending shareholder suits filed in connection with the Merger, the outcomes of which are uncertain, could delay or prevent the completion of the Merger.

AGL Resources and each member of the AGL Resources board of directors have been ~~no material changes to~~named as defendants in four purported shareholder class action lawsuits filed on behalf of named plaintiffs and other AGL Resources shareholders challenging the Merger and seeking, among other things, preliminary and permanent injunctive relief enjoining the Merger, and, in certain circumstances, damages. Southern Company and Merger Sub were also named as defendants in two of these ~~risk factors~~lawsuits. If a plaintiff in these or any other future litigation is successful in obtaining an injunction prohibiting the parties from ~~those previously disclosed~~completing the Merger on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Merger in the ~~Form 10-K.~~expected timeframe or altogether. If completion of the Merger is prevented or delayed, it could result in substantial costs to Southern Company. In addition, Southern Company could incur significant costs in connection with the lawsuits, including the costs associated with defending these lawsuits or any other liabilities or costs the parties may incur in connection with the litigation or settlement of these lawsuits.

Following the Merger, stockholders of Southern Company will own equity interests in a company whose subsidiary owns and operates a natural gas business.

AGL Resources is an energy services holding company whose primary business is the distribution of natural gas through natural gas distribution utilities. AGL Resources is involved in several other businesses that are mainly related and complementary to its primary business including: retail operations including the provision of natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice, wholesale services including natural gas storage, gas pipeline arbitrage, and natural gas asset management and/or related logistics services, and midstream operations including high deliverability natural gas storage facilities and select pipelines. As a result, the combined company will be subject to various risks to which Southern Company is not currently subject, including risks related to transporting and storing natural gas. As stockholders of the combined company following the Merger, Southern Company stockholders may be adversely affected by these risks.

Southern Company may record goodwill that could become impaired and adversely affect its operating results.

In accordance with GAAP, the Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of AGL Resources' assets and liabilities will be recorded as goodwill.

The amount of goodwill, which could be material, will be allocated to the appropriate reporting units of the combined company. Southern Company is required to assess goodwill for impairment at least annually by comparing the fair value of reporting units to the carrying value of those reporting units. To the extent the carrying value of any of those reporting units is greater than the fair value, a second step comparing the implied fair value of goodwill to the carrying amount would be required to determine if the goodwill is impaired. Such a potential impairment could result in a material charge that would have a material impact on Southern Company's future operating results and consolidated balance sheet.

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Table of Contents

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 ^(*)
July 1 – July 31	—	N/A	N/A	N/A
August 1 – August 31	—	N/A	N/A	N/A
September 1 – September 30	—	N/A	N/A	N/A
Total	—	N/A	N/A	17,400,634

(*)

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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.



		(2) Plan of acquisition, reorganization, arrangement, liquidation or succession

		Southern Company

		(a)1	-	Agreement and Plan of Merger by and among Southern Company, Merger Sub, and AGL Resources, dated August 23, 2015. (Designated in Form 8-K dated August 23, 2015, File No. 1-3526, as Exhibit 2.1.)

		(3) Articles of Incorporation and By-Laws

		Mississippi Power

		(e)1	-	By-laws of Mississippi Power as amended effective October 19, 2015, and as presently in effect. (Designated in Form 8-K dated October 19, 2015, File No. 1-3164, as Exhibit 3.1.)

		(4) Instruments Describing Rights of Security Holders, Including Indentures

		Southern Company

		(a)1	-	~~Ninth Supplemental Indenture to the Senior~~Subordinated Note Indenture, dated as of ~~August 22, 2014, providing for the issuance of the Series 2014A 1.30% Senior Notes due August 15, 2017.~~October 1, 2015, between Southern Company and Wells Fargo Bank, National Association, as Trustee. (Designated in Form 8-K dated ~~August 19, 2014,~~October 1, 2015, File No. 1-3526, as Exhibit ~~4.2(a).~~4.3.)

		(a)2	-	~~Tenth~~First Supplemental Indenture to ~~the Senior~~Subordinated Note Indenture, dated as of ~~August 22, 2014,~~October 8, 2015, providing for the issuance of the Series ~~2014B 2.15% Senior~~2015A 6.25% Junior Subordinated Notes due ~~September 1, 2019.~~October 15, 2075. (Designated in Form 8-K dated ~~August 19, 2014,~~October 1, 2015, File No. 1-3526, as Exhibit ~~4.2(b).~~4.4.)

	~~Alabama Power~~	(10) Material Contracts

		Southern Company

	~~(b)~~	(a)1	-	~~Fifty-Second Supplemental Indenture to the Senior Note Indenture~~Commitment Letter, dated ~~as of~~ August ~~26, 2014, providing for the issuance of the Series 2014A 4.150% Senior Notes due August 15, 2044.~~23, 2015. (Designated in Form 8-K dated August ~~20, 2014,~~23, 2015, File No. ~~1-3164,~~1-3526, as Exhibit ~~4.6.~~10.1.)

��		(a)2	-	Bridge Credit Agreement, dated as of September 30, 2015, among Southern Company, as the Borrower, the Lenders identified therein, and Citibank, N.A., as Administrative Agent. (Designated in Form 8-K dated September 30, 2015, File No. 1-3526, as Exhibit 10.1.)

		Southern Power

	~~Gulf~~*	(f)1	-	Amended and Restated Engineering, Procurement and Construction Agreement between Desert Stateline Holdings, LLC and First Solar Electric (California), Inc. dated as of August 31, 2015. (Southern Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Southern Power omitted such portions from the filing and filed them separately with the SEC.)

	~~(d)1~~	-	Twenty-First Supplemental Indenture to the Senior Note Indenture dated as of September 23, 2014, providing for the issuance of the Series 2014A 4.55% Senior Notes due October 1, 2044. (Designated in Form 8-K dated September 16, 2014, File No. 001-31737, as Exhibit 4.2.)

	(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.~~.)

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Table of Contents



	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.~~.)

~~189~~

~~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. (Designated in the Form 10-Q for the quarter ended June 30, 2015, File No. 001-31737 as Exhibit 24(d)2.)

	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.

*	(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.

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Table of Contents



	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.

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(32) Section 906 Certifications

	Southern Company

*	(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.


Alabama Power

*	(b)	-	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

	Georgia Power

*	(c)	-	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

	Gulf Power

*	(d)	-	Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

	Mississippi Power

*	(e)	-	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

	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~~218

Table of Contents

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~~5, 2015

~~192~~219

Table of Contents

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~~5, 2015

~~193~~220

Table of Contents

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~~5, 2015

~~194~~221

Table of Contents

GULF POWER COMPANY

SIGNATURES



		GULF POWER COMPANY

By		S. W. Connally, Jr.
		Chairman, 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~~5, 2015

~~195~~222

Table of Contents

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~~5, 2015

~~196~~223

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~~5, 2015

~~197~~224



	Third Quarter 2014				Year-to-Date 2014
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	4,319			$	11,237
Estimated change resulting from –
Rates and pricing	89		2.1		242		2.1
Sales growth	9		0.2		29		0.3
Weather	87		2.0		238		2.1
Fuel and other cost recovery	54		1.2		440		3.9
Retail – current year	$	4,558	5.5	%	$	12,186	8.4	%



	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



Note		Page Number
A	Introduction	~~145~~160
B	Contingencies and Regulatory Matters	~~146~~162
C	Fair Value Measurements	~~164~~180
D	Stockholders' Equity	~~169~~185
E	Financing	~~171~~187
F	Retirement Benefits	~~174~~190
G	~~Effective Tax Rate and Unrecognized Tax Benefits~~Income Taxes	~~177~~193
H	Derivatives	~~178~~195
I	Acquisitions	~~185~~205
J	Segment and Related Information	~~187~~210



Asset 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:
Other current assets	$	16	$	5	$	3	$	5	$	3
Other deferred charges and assets	7		2		2		2		2
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	7	$	5	$	7	$	5	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	3	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	1		—		—		—		—		1
Total asset derivatives	$	27	$	7	$	5	$	7	$	5	$	1

Third Quarter 2015 vs. Third Quarter 2014

Year-to-Date 2015 vs. Year-to-Date 2014

(change in millions)

(% change)

(change in millions)

(% change)