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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2015

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to            

 

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

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Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Registrant		Large Accelerated Filer		Accelerated Filer		Non- accelerated Filer		Smaller Reporting Company
The Southern Company		X
Alabama Power Company						X
Georgia Power Company						X
Gulf Power Company						X
Mississippi Power Company						X
Southern Power Company						X

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ (Response applicable to all registrants.)

 

Registrant		Description of Common Stock		Shares Outstanding at June 30, 2015
The Southern Company		Par Value $5 Per Share		908,424,808
Alabama Power Company		Par Value $40 Per Share		30,537,500
Georgia Power Company		Without Par Value		9,261,500
Gulf Power Company		Without Par Value		5,642,717
Mississippi Power Company		Without Par Value		1,121,000
Southern Power Company		Par Value $0.01 Per Share		1,000

This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

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INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 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	40
	Condensed Statements of Comprehensive Income	40
	Condensed Statements of Cash Flows	41
	Condensed Balance Sheets	42
	Management's Discussion and Analysis of Financial Condition and Results of Operations	44
	Georgia Power Company
	Condensed Statements of Income	60
	Condensed Statements of Comprehensive Income	60
	Condensed Statements of Cash Flows	61
	Condensed Balance Sheets	62
	Management's Discussion and Analysis of Financial Condition and Results of Operations	64
	Gulf Power Company
	Condensed Statements of Income	82
	Condensed Statements of Comprehensive Income	82
	Condensed Statements of Cash Flows	83
	Condensed Balance Sheets	84
	Management's Discussion and Analysis of Financial Condition and Results of Operations	86
	Mississippi Power Company
	Condensed Statements of Operations	102
	Condensed Statements of Comprehensive Income (Loss)	102
	Condensed Statements of Cash Flows	103
	Condensed Balance Sheets	104
	Management's Discussion and Analysis of Financial Condition and Results of Operations	106
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	134
	Condensed Consolidated Statements of Comprehensive Income	134
	Condensed Consolidated Statements of Cash Flows	135
	Condensed Consolidated Balance Sheets	136
	Management's Discussion and Analysis of Financial Condition and Results of Operations	138
	Notes to the Condensed Financial Statements	149
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	38

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INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2015

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

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DEFINITIONS

 

Term	Meaning
2012 MPSC CPCN Order	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
2013 ARP	Alternative Rate Plan approved by the Georgia PSC for Georgia Power for the years 2014 through 2016
AFUDC	Allowance for funds used during construction
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
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 and 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, 2014
GAAP	Generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany interchange contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
ITC	Investment tax credit
Kemper IGCC	IGCC facility under construction in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
MATS rule	Mercury and Air Toxics Standards rule
Mirror CWIP	A regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt

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DEFINITIONS

(continued)

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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

•

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

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

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

•

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

•	available sources and costs of fuels;

•	effects of inflation;

•

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

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

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

•	advances in technology;

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

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

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

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

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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

•	the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's order implementing such decision, and any further related legal or regulatory proceedings;

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

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

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

•	interest rate fluctuations and financial market conditions and the results of financing efforts;

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

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

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

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

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

•	the effect of accounting pronouncements issued periodically by standard-setting bodies; and

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.

The registrants expressly disclaim any obligation to update any forward-looking statements.

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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 June 30,								For the Six Months Ended June 30,
	2015				2014				2015				2014
	(in millions)								(in millions)
Operating Revenues:
Retail revenues	$	3,714			$	3,770			$	7,256			$	7,628
Wholesale revenues	448				515				915				1,119
Other electric revenues	162				169				325				334
Other revenues	13				13				24				30
Total operating revenues	4,337				4,467				8,520				9,111
Operating Expenses:
Fuel	1,200				1,462				2,412				3,109
Purchased power	171				133				315				320
Other operations and maintenance	1,100				1,019				2,222				2,005
Depreciation and amortization	500				504				987				1,001
Taxes other than income taxes	245				246				497				493
Estimated loss on Kemper IGCC	23				—				32				380
Total operating expenses	3,239				3,364				6,465				7,308
Operating Income	1,098				1,103				2,055				1,803
Other Income and (Expense):
Allowance for equity funds used during construction	39				62				102				119
Interest expense, net of amounts capitalized	(180		)		(210		)		(393		)		(416		)
Other income (expense), net	(12		)		(6		)		(19		)		(13		)
Total other income and (expense)	(153		)		(154		)		(310		)		(310		)
Earnings Before Income Taxes	945				949				1,745				1,493
Income taxes	302				321				576				497
Consolidated Net Income	643				628				1,169				996
Dividends on Preferred and Preference Stock of Subsidiaries	14				17				31				34
Consolidated Net Income After Dividends on Preferred and    Preference Stock of Subsidiaries	$	629			$	611			$	1,138			$	962
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.69			$	0.68			$	1.25			$	1.08
Diluted EPS	$	0.69			$	0.68			$	1.25			$	1.07
Average number of shares of common stock outstanding (in millions)
Basic	909				895				910				892
Diluted	912				899				914				896
Cash dividends paid per share of common stock	$	0.5425			$	0.5250			$	1.0675			$	1.0325

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

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

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2015				2014
	(in millions)
Operating Activities:
Consolidated net income	$	1,169			$	996
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,171				1,182
Deferred income taxes	783				46
Allowance for equity funds used during construction	(102		)		(119		)
Stock based compensation expense	66				40
Estimated loss on Kemper IGCC	32				380
Income taxes receivable, non-current	(444		)		—
Other, net	(6		)		23
Changes in certain current assets and liabilities —
-Receivables	(158		)		(579		)
-Fossil fuel stock	136				419
-Materials and supplies	(21		)		(20		)
-Other current assets	(78		)		(88		)
-Accounts payable	(311		)		(231		)
-Accrued taxes	(60		)		72
-Accrued compensation	(269		)		(40		)
-Mirror CWIP	82				67
-Other current liabilities	117				(78		)
Net cash provided from operating activities	2,107				2,070
Investing Activities:
Property additions	(2,647		)		(2,692		)
Nuclear decommissioning trust fund purchases	(933		)		(445		)
Nuclear decommissioning trust fund sales	928				443
Cost of removal, net of salvage	(87		)		(54		)
Change in construction payables, net	56				89
Prepaid long-term service agreement	(110		)		(93		)
Other investing activities	27				(17		)
Net cash used for investing activities	(2,766		)		(2,769		)
Financing Activities:
Increase in notes payable, net	184				339
Proceeds —
Long-term debt issuances	3,075				1,314
Interest-bearing refundable deposit	—				75
Common stock issuances	116				318
Short-term borrowings	320				—
Redemptions and repurchases—
Long-term debt	(939		)		(431		)
Interest-bearing refundable deposits	(275		)		—
Preferred and preference stock	(412		)		—
Common stock	(115		)		(5		)
Short-term borrowings	(250		)		—
Payment of common stock dividends	(972		)		(920		)
Payment of dividends on preferred and preference stock of subsidiaries	(36		)		(34		)
Other financing activities	66				(33		)
Net cash provided from financing activities	762				623
Net Change in Cash and Cash Equivalents	103				(76		)
Cash and Cash Equivalents at Beginning of Period	710				659
Cash and Cash Equivalents at End of Period	$	813			$	583
Supplemental Cash Flow Information:
Cash paid (received) during the period for --
Interest (net of $57 and $47 capitalized for 2015 and 2014, respectively)	$	374			$	365
Income taxes, net	(16		)		212
Noncash transactions — Accrued property additions at end of period	345				509

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

Assets		At June 30, 2015				At December 31, 2014
		(in millions)
Current Assets:
Cash and cash equivalents		$	813			$	710
Receivables —
Customer accounts receivable		1,312				1,090
Unbilled revenues		579				432
Under recovered regulatory clause revenues		173				136
Other accounts and notes receivable		209				307
Accumulated provision for uncollectible accounts		(17		)		(18		)
Fossil fuel stock, at average cost		795				930
Materials and supplies, at average cost		1,043				1,039
Vacation pay		177				177
Prepaid expenses		564				665
Deferred income taxes, current		499				506
Other regulatory assets, current		382				346
Other current assets		76				50
Total current assets		6,605				6,370
Property, Plant, and Equipment:
In service		71,462				70,013
Less accumulated depreciation		23,918				24,059
Plant in service, net of depreciation		47,544				45,954
Other utility plant, net		87				211
Nuclear fuel, at amortized cost		889				911
Construction work in progress		8,487				7,792
Total property, plant, and equipment		57,007				54,868
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,572				1,546
Leveraged leases		751				743
Miscellaneous property and investments		232				203
Total other property and investments		2,555				2,492
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,533				1,510
Unamortized debt issuance expense		208				202
Unamortized loss on reacquired debt		234				243
Other regulatory assets, deferred		4,763				4,334
Income taxes receivable, non-current		444				—
Other deferred charges and assets		832				904
Total deferred charges and other assets		8,014				7,193
Total Assets		$	74,181			$	70,923

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

Liabilities and Stockholders' Equity		At June 30, 2015				At December 31, 2014
		(in millions)
Current Liabilities:
Securities due within one year		$	3,643			$	3,333
Interest-bearing refundable deposits		—				275
Notes payable		1,057				803
Accounts payable		1,395				1,593
Customer deposits		398				390
Accrued taxes —
Accrued income taxes		12				151
Other accrued taxes		391				487
Accrued interest		241				295
Accrued vacation pay		222				223
Accrued compensation		305				576
Mirror CWIP		353				271
Other current liabilities		677				570
Total current liabilities		8,694				8,967
Long-term Debt		22,674				20,841
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		12,187				11,568
Deferred credits related to income taxes		186				192
Accumulated deferred investment tax credits		1,290				1,208
Employee benefit obligations		2,375				2,432
Asset retirement obligations		2,860				2,168
Other cost of removal obligations		1,206				1,215
Other regulatory liabilities, deferred		408				398
Other deferred credits and liabilities		996				594
Total deferred credits and other liabilities		21,508				19,775
Total Liabilities		52,876				49,583
Redeemable Preferred Stock of Subsidiaries		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 — June 30, 2015: 912 million shares
— December 31, 2014: 909 million shares
Treasury — June 30, 2015: 3.3 million shares
— December 31, 2014: 0.7 million shares
Par value		4,555				4,539
Paid-in capital		6,123				5,955
Treasury, at cost		(142		)		(26		)
Retained earnings		9,767				9,609
Accumulated other comprehensive loss		(121		)		(128		)
Total Common Stockholders' Equity		20,182				19,949
Preferred and Preference Stock of Subsidiaries		609				756
Noncontrolling Interest		355				221
Total Stockholders' Equity		21,146				20,926
Total Liabilities and Stockholders' Equity		$	74,181			$	70,923

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

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SECOND QUARTER 2015 vs. SECOND QUARTER 2014

AND

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

OVERVIEW

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

In addition, 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.

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects, and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$18		2.9		$176		18.3

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

Southern Company's year-to-date 2015 net income after dividends on preferred and preference stock of subsidiaries was $1.1 billion ($1.25 per share) compared to $962 million ($1.08 per share) for the corresponding period in 2014. The increase was primarily the result of lower pre-tax charges of $32 million ($20 million after tax) recorded in 2015 compared to a pre-tax charge of $380 million ($235 million after tax) recorded in the corresponding period in 2014 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper

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

Retail Revenues

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(56)		(1.5)		$(372)		(4.9)

In the second quarter 2015, retail revenues were $3.7 billion compared to $3.8 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $7.3 billion compared to $7.6 billion for the corresponding period in 2014.

Details of the changes in retail revenues were as follows:

		Second Quarter 2015							Year-to-Date 2015
		(in millions)				(% change)			(in millions)				(% change)
Retail – prior year		$	3,770						$	7,628
Estimated change resulting from –
Rates and pricing		30				0.8			107				1.4
Sales growth		23				0.6			41				0.5
Weather		46				1.2			8				0.1
Fuel and other cost recovery		(155		)		(4.1	)		(528		)		(6.9	)
Retail – current year		$	3,714			(1.5	)%		$	7,256			(4.9	)%

Revenues associated with changes in rates and pricing increased in the second 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. The increase was partially offset by the correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power. See Note (A) to the Condensed Financial Statements herein and 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 for additional information.

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

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

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

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this adjustment, second quarter 2015 weather-adjusted residential sales increased 1.4%, weather-adjusted commercial sales increased 0.5%, and industrial KWH sales increased 0.1% as compared to the corresponding period in 2014. Also, without this adjustment, year-to-date 2015 weather-adjusted residential sales increased 0.6%, weather-adjusted commercial sales increased 0.4%, and industrial KWH sales increased 1.0% as compared to the corresponding period in 2014.

Fuel and other cost recovery revenues decreased $155 million and $528 million in the second 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 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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(67)		(13.0)		$(204)		(18.2)

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

In the second quarter 2015, wholesale revenues were $448 million compared to $515 million for the corresponding period in 2014 related to a $44 million decrease in energy revenues and a $23 million decrease in capacity revenues. For year-to-date 2015, wholesale revenues were $915 million compared to $1.1 billion for the corresponding period in 2014 related to a $162 million decrease in energy revenues and a $42 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

		Second Quarter 2015 vs. Second Quarter 2014						Year-to-Date 2015 vs. Year-to-Date 2014
		(change in millions)				(% change)		(change in millions)				(% change)
Fuel		$	(262	)		(17.9)		$	(697	)		(22.4)
Purchased power		38				28.6		(5		)		(1.6)
Total fuel and purchased power expenses		$	(224	)				$	(702	)

In the second quarter 2015, total fuel and purchased power expenses were $1.4 billion compared to $1.6 billion for the corresponding period in 2014. The decrease was primarily the result of a $337 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $113 million increase in the volume of KWHs generated and purchased primarily due to increased demand resulting from warmer weather in the second quarter 2015 as compared to the corresponding period in 2014.

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

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

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

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

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

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Fuel

In the second quarter 2015, fuel expense was $1.2 billion compared to $1.5 billion for the corresponding period in 2014. The decrease was primarily due to a 27.8% decrease in the average cost of natural gas per KWH generated, an 11.1% decrease in the average cost of coal per KWH generated, and a 10.6% decrease in the volume of KWHs generated by coal, partially offset by a 19.7% increase in the volume of KWHs generated by natural gas.

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

Purchased Power

In the second quarter 2015, purchased power expense was $171 million compared to $133 million for the corresponding period in 2014. The increase was primarily due to a 50.0% increase in the volume of KWHs purchased primarily as a result of increased demand from warmer weather in the second quarter 2015 as compared to the corresponding period in 2014, partially offset by a 24.0% decrease in the average cost per KWH purchased.

For year-to-date 2015, purchased power expense was $315 million compared to $320 million for the corresponding period in 2014. The decrease was primarily due to a 23.7% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by an 18.0% increase in the volume of KWHs 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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$81		7.9		$217		10.8

In the second 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 $32 million increase in generation expenses primarily related to non-outage operations and maintenance, a $23 million 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, partially offset by a $7 million decrease in transmission and distribution costs primarily related to overhead line maintenance. In addition, in the second quarter 2014, Alabama Power deferred approximately $16 million of certain non-nuclear outage expenditures under an accounting order.

For year-to-date 2015, other operations and maintenance expenses were $2.2 billion compared to $2.0 billion for the corresponding period in 2014. The increase was primarily due to a $58 million increase in employee compensation and benefits including pension costs, a $41 million increase in generation expenses primarily related to non-outage operations and maintenance, a $30 million increase in scheduled outage and maintenance costs at generation facilities, and a $22 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs. In addition, in the first half of 2014, Alabama Power deferred approximately $41 million of certain non-nuclear outage expenditures under an accounting order.

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

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Depreciation and Amortization

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(4)		(0.8)		$(14)		(1.4)

For year-to-date 2015, depreciation and amortization was $987 million compared to $1.0 billion for the corresponding period in 2014. The decrease was primarily due to a $49 million reduction in depreciation rates at Alabama Power, a $14 million reduction in depreciation at Gulf Power, as approved by the Florida PSC, and a $9 million reduction in other cost of removal at Georgia Power, partially offset by a $49 million increase as a result of additional plant in service at the traditional operating companies and Southern Power. 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.

Estimated Loss on Kemper IGCC

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$23		N/M		$(348)		(91.6)

N/M – Not meaningful

In the second quarter 2015, an estimated probable loss on the Kemper IGCC of $23 million was recorded at Southern Company. For year-to-date 2015 and 2014, estimated probable losses on the Kemper IGCC of $32 million and $380 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.

Allowance for Equity Funds Used During Construction

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(23)		(37.1)		$(17)		(14.3)

In the second quarter 2015, AFUDC equity was $39 million compared to $62 million for the corresponding period in 2014. For year-to-date 2015, AFUDC equity was $102 million compared to $119 million for the corresponding period in 2014. The decreases were primarily due to Mississippi Power placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and lower AFUDC equity at Georgia Power. Additionally, for year-to-date 2015, the decrease in AFUDC equity was partially offset by environmental and transmission projects at the traditional operating companies. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

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Interest Expense, Net of Amounts Capitalized

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(30)		(14.3)		$(23)		(5.5)

In the second quarter 2015, interest expense, net of amounts capitalized was $180 million compared to $210 million in the corresponding period in 2014. For year-to-date 2015, interest expense, net of amounts capitalized was $393 million compared to $416 million in the corresponding period in 2014. The decreases were primarily due to a $41 million decrease related to the termination of the asset purchase agreement (APA) between Mississippi Power and SMEPA which required the return of SMEPA's deposits at a lower rate of interest than accrued, partially offset by an increase in outstanding long-term debt. Also contributing to the year-to-date decrease was an increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC. See Note (E) to the Condensed Financial Statements herein for additional information. Also see Note (B) "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

Income Taxes

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(19)		(5.9)		$79		15.9

In the second quarter 2015, income taxes were $302 million compared to $321 million for the corresponding period in 2014. The decrease is primarily due to state income tax benefits realized in 2015 and increased federal income tax benefits related to ITCs in 2015 at Southern Power, partially offset by a decrease in non-taxable AFUDC equity, higher pre-tax earnings, and beneficial changes that impacted 2014 state income taxes.

For year-to-date 2015, income taxes were $576 million compared to $497 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, beneficial changes that impacted 2014 state income taxes, and a decrease in non-taxable AFUDC equity, partially offset by otherwise lower pre-tax earnings in 2015, state income tax benefits realized in 2015, and increased federal income tax benefits related to ITCs in 2015 at Southern Power.

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 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 creditworthiness of customers, total generating capacity available and related costs, future acquisitions and

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

Environmental Matters

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

New Source Review Actions

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

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

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

Environmental Statutes and Regulations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations," – "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, and the Cross State Air Pollution Rule (CSAPR).

On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, Mississippi, North Carolina, and 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

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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.

Water Quality

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

On 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 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. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Coal Combustion Residuals" of 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, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Southern Company recorded incremental asset retirement obligations (ARO) of approximately $700 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding these AROs.

Global Climate Issues

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

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

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. Georgia Power expects to file its next fuel case in September 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

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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.

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

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

Environmental Accounting Order

In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Subject to the final approval of the New Source Review stipulation, Alabama Power will also retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See Note (B) to the Condensed Financial Statements herein for additional information regarding the New Source Review actions.

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

Renewable Energy

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

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Georgia Power

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

Renewables Development

As part 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 a 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia by the end of 2016.

Integrated Resource Plan

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

Gulf Power

Renewables

On 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. 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

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, the projects are expected to be in service by the end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of this matter cannot be determined at this time.

Construction Program

Overview

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new generating facilities, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings.

The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 (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 Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, see Note (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 June 30, 2015, Southern Company recorded pre-tax charges totaling $2.08 billion ($1.28 billion after tax) for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

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

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

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

Nuclear Construction

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

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

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

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

Income Tax Matters

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

Section 174 Research and Experimental Deduction

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

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

Other Matters

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

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

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 2015, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.

As a result of the revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.08 billion ($1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2015.

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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 readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

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

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

Asset Retirement Obligations

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

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

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

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

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

Recently Issued Accounting Standards

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

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 2015. Through June 30, 2015, Southern Company has incurred non-recoverable cash expenditures of $1.62 billion and is expected to incur approximately $0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $2.1 billion for the first six months of 2015, an increase of $37 million from the corresponding period in 2014. The increase in net cash provided from operating activities was primarily due to an increase in fuel cost recovery, partially offset by timing of accounts payable. Net cash used for investing activities totaled $2.8 billion for the first six months of 2015 primarily due to gross property additions for installation of equipment to comply with environmental standards, construction of generation, transmission, and distribution facilities, and acquisitions of solar facilities. Net cash provided from financing activities totaled $762 million for the first six months of 2015. This was primarily due to issuances of long-term debt, partially offset by common stock dividend payments and redemptions of long-term debt and preferred and preference stock. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

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

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

At the end of the second quarter 2015, the market price of Southern Company's common stock was $41.90 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.22 per share, representing a market-to-book ratio of 189%, compared to $49.11, $21.98, and 223%, respectively, at the end of 2014. Southern Company's common stock dividend for the second quarter 2015 was $0.5425 per share compared to $0.5250 per share in the second quarter 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 $3.7 billion will be required through June 30, 2016 to fund maturities and announced redemptions of long-term debt. See "Sources of Capital" herein for additional information.

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

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt to be raised in 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which may be used to reimburse Georgia Power for Eligible 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. Eligible Project Costs incurred through June 30, 2015 would allow for borrowings of up to $2.2 billion under the FFB Credit Facility, of which Georgia Power has borrowed $1.8 billion. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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

As of June 30, 2015, Southern Company's current liabilities exceeded current assets by $2.1 billion, primarily due to long-term debt that is due within one year of $3.6 billion, including approximately $0.4 billion at Southern Company, $0.6 billion at Alabama Power, $1.7 billion at Georgia Power, $0.4 billion at Mississippi Power, and $0.5 billion at Southern Power. In addition, Mississippi Power has $0.5 billion in short-term bank loans scheduled to mature on April 1, 2016. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional operating companies, and Southern Power intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional operating companies and Southern Power, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, for the remainder of 2015, Georgia Power expects to utilize borrowings through the FFB Credit Facility as its primary source of long-term borrowed funds.

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

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

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

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

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

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

		Short-term Debt at June 30, 2015							Short-term Debt During the Period(*)
		Amount Outstanding				Weighted Average Interest Rate			Average Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
		(in millions)							(in millions)							(in millions)
Commercial paper		$	512			0.3	%		$	1,155			0.3	%		$	1,563
Short-term bank debt		545				1.3	%		717				1.2	%		795
Total		$	1,057			0.7	%		$	1,872			0.7	%

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

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

Credit Rating Risk

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

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

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

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

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

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

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

Financing Activities

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through June 30, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.

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

Company(a)	Senior Note Issuances				Senior Note Redemptions				Revenue Bond Issuances and Reofferings of Purchased Bonds(b)				Revenue Bond Maturities and Repurchases				Other Long-Term Debt Issuances				Other Long-Term Debt Redemptions and Maturities(c)
	(in millions)
Southern Company	$	600			$	—			$	—			$	—			$	—			$	—
Alabama Power	975				250				80				134				—				—
Georgia Power	—				125				170				65				600				5
Mississippi Power	—				—				—				—				—				351
Southern Power	650				—				—				—				—				—
Other	—				—				—				—				—				9
Total	$	2,225			$	375			$	250			$	199			$	600			$	365

(a)	Gulf Power did not issue or redeem any long-term debt during the first six months of 2015.

(b)	Includes reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds previously purchased and held by Alabama Power since April 2015 and reofferings by Georgia Power of $104.6 million and $65 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2013 and April 2015, respectively.

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

In June 2015, Southern Company issued $600 million aggregate principal amount of Series 2015A 2.750% Senior Notes due June 15, 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 issuance 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.

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million in June 2015. The interest rate applicable to the $600 million principal amount is 3.283% for an interest period that extends to 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 4. Georgia Power settled $350 million of interest rate swaps related to this borrowing for approximately $6 million, which will be amortized to interest expense over 10 years.

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 proceeds were used for working capital and other general corporate purposes and the loan was repaid at maturity.

In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

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

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

Subsequent to June 30, 2015, Southern Power Company repaid at maturity $525 million aggregate principal amount of its 4.875% Senior Notes on July 15, 2015.

Also subsequent to June 30, 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.

Also subsequent to June 30, 2015, Gulf Power announced the redemption in September 2015 of $60 million aggregate principal amount of its Series L 5.65% Senior Notes due September 1, 2035.

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

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PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the six months ended June 30, 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 second quarter 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 June 30,								For the Six Months Ended June 30,
	2015				2014				2015				2014
	(in millions)								(in millions)
Operating Revenues:
Retail revenues	$	1,326			$	1,249			$	2,594			$	2,546
Wholesale revenues, non-affiliates	57				65				123				150
Wholesale revenues, affiliates	20				68				35				137
Other revenues	52				55				104				112
Total operating revenues	1,455				1,437				2,856				2,945
Operating Expenses:
Fuel	343				414				653				846
Purchased power, non-affiliates	45				39				86				96
Purchased power, affiliates	49				37				103				86
Other operations and maintenance	370				330				768				655
Depreciation and amortization	160				172				318				347
Taxes other than income taxes	90				88				184				177
Total operating expenses	1,057				1,080				2,112				2,207
Operating Income	398				357				744				738
Other Income and (Expense):
Allowance for equity funds used during construction	14				11				29				21
Interest expense, net of amounts capitalized	(69		)		(63		)		(134		)		(125		)
Other income (expense), net	(14		)		(3		)		(18		)		(8		)
Total other income and (expense)	(69		)		(55		)		(123		)		(112		)
Earnings Before Income Taxes	329				302				621				626
Income taxes	122				119				235				246
Net Income	207				183				386				380
Dividends on Preferred and Preference Stock	7				10				17				20
Net Income After Dividends on Preferred and Preference Stock	$	200			$	173			$	369			$	360

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

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

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

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

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

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

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ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

 

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

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

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ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

 

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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2015 vs. SECOND QUARTER 2014

AND

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

OVERVIEW

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

Many factors affect the opportunities, challenges, and risks of Alabama Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. 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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$27		15.6		$9		2.5

Alabama Power's net income after dividends on preferred and preference stock for the second quarter 2015 was $200 million compared to $173 million for the corresponding period in 2014. The increase was primarily related to an increase in rates under rate stabilization and equalization (Rate RSE) effective January 1, 2015, warmer weather in the second quarter 2015 compared to the corresponding period in 2014, and a decrease in depreciation, partially offset by an increase in non-fuel operations and maintenance expenses. Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2015 was $369 million compared to $360 million for the corresponding period in 2014. The increase was primarily related to an increase under Rate RSE and a decrease in depreciation, partially offset by an increase in non-fuel operations and maintenance expenses.

Retail Revenues

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$77		6.2		$48		1.9

In the second quarter 2015, retail revenues were $1.33 billion compared to $1.25 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $2.59 billion compared to $2.55 billion for the corresponding period in 2014.

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Details of the changes in retail revenues were as follows:

		Second Quarter 2015							Year-to-Date 2015
		(in millions)				(% change)			(in millions)				(% change)
Retail – prior year		$	1,249						$	2,546
Estimated change resulting from –
Rates and pricing		56				4.5			103				4.1
Sales growth		1				0.1			10				0.4
Weather		18				1.5			(2		)		(0.1	)
Fuel and other cost recovery		2				0.1			(63		)		(2.5	)
Retail – current year		$	1,326			6.2	%		$	2,594			1.9	%

Revenues associated with changes in rates and pricing increased in the second quarter 2015 and year-to-date 2015 when compared to the corresponding periods in 2014 primarily due to a Rate RSE increase effective January 1, 2015. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales remained relatively flat in the second quarter 2015 and increased slightly year-to-date 2015 when compared to the corresponding periods in 2014. Industrial KWH energy sales slightly increased 0.2% year-to-date 2015 as a result of an increase in demand resulting from changes in production levels primarily in the pipelines, stone, clay, and glass, automotive, and plastics sectors, offset by a decrease in demand in the primary metals and forest products sectors. Weather-adjusted residential and commercial KWH energy sales were relatively flat for year-to-date 2015.

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

Revenues resulting from changes in weather remained relatively flat year-to-date 2015 primarily due to milder weather experienced in Alabama Power's service territory in the first quarter 2015 offset by warmer weather in the second quarter 2015 as compared to the corresponding periods in 2014.

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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(8)		(12.3)		$(27)		(18.0)

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

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an increase or decrease in fuel costs and do not have a significant impact on net income.

In the second quarter 2015, wholesale revenues from sales to non-affiliates were $57 million compared to $65 million for the corresponding period in 2014. The decrease was primarily due to a 12.0% decrease in KWH sales. For year-to-date 2015, wholesale revenues from sales to non-affiliates were $123 million compared to $150 million for the corresponding period in 2014. The decrease was primarily due to a 10.3% decrease in KWH sales and an 8.7% decrease in the price of 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 and decreased availability of hydro generation, due to less rainfall, resulted in lower sales of Alabama Power's generation to non-affiliates.

Wholesale Revenues – Affiliates

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(48)		(70.6)		$(102)		(74.5)

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.

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

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

Fuel and Purchased Power Expenses

		Second Quarter 2015 vs. Second Quarter 2014						Year-to-Date 2015 vs. Year-to-Date 2014
		(change in millions)				(% change)		(change in millions)				(% change)
Fuel		$	(71	)		(17.1)		$	(193	)		(22.8	)
Purchased power – non-affiliates		6				15.4		(10		)		(10.4	)
Purchased power – affiliates		12				32.4		17				19.8
Total fuel and purchased power expenses		$	(53	)				$	(186	)

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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.

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

		Second Quarter 2015		Second Quarter 2014		Year-to-Date 2015		Year-to-Date 2014
Total generation (billions of KWHs)		15		16		29		33
Total purchased power (billions of KWHs)		2		1		4		3
Sources of generation (percent) —
Coal		59		53		53		53
Nuclear		20		24		23		23
Gas		15		16		17		16
Hydro		6		7		7		8
Cost of fuel, generated (cents per net KWH) —
Coal		2.89		3.30		2.89		3.35
Nuclear		0.82		0.85		0.81		0.86
Gas		3.10		3.80		3.06		3.99
Average cost of fuel, generated (cents per net KWH)(a)		2.50		2.76		2.41		2.83
Average cost of purchased power (cents per net KWH)(b)		5.48		5.88		5.00		6.18

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

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

Fuel

In the second quarter 2015, fuel expense was $343 million compared to $414 million for the corresponding period in 2014. The decrease was primarily due to an 18.4% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 14.6% decrease in the volume of KWHs generated by natural gas, and a 12.3% decrease in the average cost of coal per KWH generated. The decrease was partially offset by a 21.4% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall.

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

Purchased Power – Non-Affiliates

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

Purchased Power – Affiliates

In the second quarter 2015, purchased power expense from affiliates was $49 million compared to $37 million for the corresponding period in 2014. The increase was related to a 45.2% increase in the amount of energy purchased primarily due to the availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation as a result of less rainfall. The increase was partially offset by a 7.0% decrease in the average cost per KWH purchased due to lower natural gas prices.

For year-to-date 2015, purchased power expense from affiliates was $103 million compared to $86 million for the corresponding period in 2014. The increase was related to a 39.5% increase in the amount of energy purchased primarily due to the availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation as a result of less rainfall. The increase was partially offset by a 14.2% decrease in the average cost per KWH purchased due to lower natural gas prices.

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

Other Operations and Maintenance Expenses

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$40		12.1		$113		17.3

In the second quarter 2015, other operations and maintenance expenses were $370 million compared to $330 million for the corresponding period in 2014. The increase was primarily due to the implementation of an accounting order in 2014 allowing the deferral of non-nuclear outage costs. Alabama Power deferred approximately $16 million of non-nuclear outage expenditures in the second quarter 2014. In addition, employee benefits including pension costs increased $11 million and steam generation costs increased $5 million primarily due to non-outage and maintenance costs.

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

See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Cost of Removal Accounting Order" in Item 8 of the Form 10-K for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Depreciation and Amortization

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(12)		(7.0)		$(29)		(8.4)

In the second quarter 2015, depreciation and amortization was $160 million compared to $172 million for the corresponding period in 2014. For year-to-date 2015, depreciation and amortization was $318 million compared to $347 million for the corresponding period in 2014. These decreases were primarily due to 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.

Allowance for Equity Funds Used During Construction

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$3		27.3		$8		38.1

In the second quarter 2015, AFUDC equity was $14 million compared to $11 million for the corresponding period in 2014. For year-to-date 2015, AFUDC equity was $29 million compared to $21 million for the corresponding period in 2014. These increases were primarily due to additional capital expenditures for steam power environmental projects.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$6		9.5		$9		7.2

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

Other Income (Expense), Net

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(11)		N/M		$(10)		(125.0)

N/M - Not meaningful

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

Income Taxes

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$3		2.5		$(11)		(4.5)

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

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

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

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

New Source Review Actions

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

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

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

Environmental Statutes and Regulations

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Air Quality

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

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 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 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. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.

Water Quality

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

On 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 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. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

Coal Combustion Residuals

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

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

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

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

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 April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Alabama 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 Alabama 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 Alabama Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

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

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

Retail Regulatory Matters

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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

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

Environmental Accounting Order

In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Subject to the final approval of the New Source Review stipulation, Alabama Power will also retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See Note (B) to the Condensed Financial Statements herein for additional information regarding the New Source Review actions.

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

Renewable Energy

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Asset Retirement Obligations

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

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

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

Recently Issued Accounting Standards

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

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 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 $597 million for the first six months of 2015, a decrease of $77 million as compared to the first six months of 2014. The decrease in net cash provided from operating activities was primarily due to the timing of fossil fuel stock purchases and payments of accounts payable, partially offset by the timing of income tax payments and refunds associated with bonus depreciation. Net cash used for investing activities totaled $626 million for the first six months of 2015 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash used for financing activities totaled $49 million for the first six months of 2015 primarily due to the redemptions and repurchases of long-term debt and preferred and preference stock and payments of common stock dividends, partially offset by 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 six months of 2015 include increases of $690 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, and steam generation and $423 million in 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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

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

Sources of Capital

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

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

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

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

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

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

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross default provisions to other

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

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

Details of short-term borrowings were as follows:

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

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

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

Credit Rating Risk

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

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

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

Financing Activities

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

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.

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

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2015				2014				2015				2014
	(in millions)								(in millions)
Operating Revenues:
Retail revenues	$	1,872			$	2,000			$	3,686			$	4,050
Wholesale revenues, non-affiliates	50				80				118				189
Wholesale revenues, affiliates	4				10				12				31
Other revenues	90				96				178				185
Total operating revenues	2,016				2,186				3,994				4,455
Operating Expenses:
Fuel	503				619				1,029				1,371
Purchased power, non-affiliates	78				63				138				142
Purchased power, affiliates	115				166				263				350
Other operations and maintenance	467				451				943				878
Depreciation and amortization	202				209				418				417
Taxes other than income taxes	97				106				195				209
Total operating expenses	1,462				1,614				2,986				3,367
Operating Income	554				572				1,008				1,088
Other Income and (Expense):
Interest expense, net of amounts capitalized	(93		)		(90		)		(182		)		(174		)
Other income (expense), net	1				11				16				15
Total other income and (expense)	(92		)		(79		)		(166		)		(159		)
Earnings Before Income Taxes	462				493				842				929
Income taxes	180				177				320				343
Net Income	282				316				522				586
Dividends on Preferred and Preference Stock	5				5				9				9
Net Income After Dividends on Preferred and Preference Stock	$	277			$	311			$	513			$	577

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

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

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

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

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

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

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

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

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

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SECOND QUARTER 2015 vs. SECOND QUARTER 2014

AND

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

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service 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, 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, 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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(34)		(10.9)		$(64)		(11.1)

Georgia Power's net income after dividends on preferred and preference stock for the second quarter 2015 was $277 million compared to $311 million for the corresponding period in 2014. For year-to-date 2015, net income after dividends on preferred and preference stock was $513 million compared to $577 million for the corresponding period in 2014. The decreases were primarily due to higher non-fuel operations and maintenance expenses and the correction of an error affecting billings to a small number of large commercial and industrial customers, partially offset by increases in retail base revenues effective January 1, 2015 as authorized by the Georgia PSC. Additionally, warmer weather in the second quarter 2015 compared to the corresponding period in 2014 contributed to increases in retail base revenues.

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

Retail Revenues

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(128)		(6.4)		$(364)		(9.0)

In the second quarter 2015, retail revenues were $1.87 billion compared to $2.00 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $3.69 billion compared to $4.05 billion for the corresponding period in 2014.

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Details of the changes in retail revenues were as follows:

		Second Quarter 2015							Year-to-Date  2015
		(in millions)				(% change)			(in millions)				(% change)
Retail – prior year		$	2,000						$	4,050
Estimated change resulting from –
Rates and pricing		(27		)		(1.3	)		3				0.1
Sales growth		21				1.0			37				0.9
Weather		22				1.1			6				0.1
Fuel cost recovery		(144		)		(7.2	)		(410		)		(10.1	)
Retail – current year		$	1,872			(6.4	)%		$	3,686			(9.0	)%

Revenues associated with changes in rates and pricing decreased in the second quarter 2015 when compared to the corresponding period in 2014 primarily due to the correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing, partially offset by base tariff increases approved under the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, which were both effective January 1, 2015. Revenues associated with changes in rates and pricing increased slightly year-to-date 2015 when compared to the corresponding period in 2014 primarily due to the base tariff increases and increases in collections for financing costs described above, partially offset by the error correction. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales increased in the second quarter and year-to-date 2015 when compared to the corresponding periods in 2014. Weather-adjusted residential KWH sales increased 2.6%, weather-adjusted commercial KWH sales increased 1.1%, and weather-adjusted industrial KWH sales remained flat in the second quarter 2015 when compared to the corresponding period in 2014. For year-to-date 2015, weather-adjusted residential KWH sales increased 1.8%, weather-adjusted commercial KWH sales increased 1.0%, and weather-adjusted industrial KWH sales increased 2.0% when compared to the corresponding period in 2014. An increase of approximately 28,000 residential customers since June 30, 2014 contributed to the increase in weather-adjusted residential KWH sales. Increased customer usage and an increase of approximately 3,000 commercial customers since June 30, 2014 contributed to the increase in weather-adjusted commercial sales. Increased demand in the paper, stone, clay, and glass, food processing, transportation, rubber, and pipeline sectors was the main contributor to the increase in weather-adjusted industrial KWH sales, partially offset by a decrease in the chemicals sector.

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

Wholesale Revenues – Non-Affiliates

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(30)		(37.5)		$(71)		(37.6)

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are

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recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

In the second quarter 2015, wholesale revenues from sales to non-affiliates were $50 million compared to $80 million for the corresponding period in 2014 related to a $15 million decrease in energy revenues and a $15 million decrease in capacity revenues. For year-to-date 2015, wholesale revenues from sales to non-affiliates were $118 million compared to $189 million for the corresponding period in 2014 related to a $48 million decrease in energy revenues and a $23 million decrease in capacity revenues. The decreases in energy revenues were primarily due to the lower cost of natural gas and coal. The decreases in capacity revenues reflect the expiration of wholesale contracts in December 2014 and the retirements of Plant Branch Units 1, 3, and 4, Plant Yates Units 1 through 5, and Plant McManus Units 1 and 2.

Wholesale Revenues – Affiliates

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(6)		(60.0)		$(19)		(61.3)

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

In the second quarter 2015, wholesale revenues from sales to affiliates were $4 million compared to $10 million for the corresponding period in 2014. For year-to-date 2015, wholesale revenues from sales to affiliates were $12 million compared to $31 million for the corresponding period in 2014. The decreases were due to lower natural gas and coal prices.

Fuel and Purchased Power Expenses

		Second Quarter 2015 vs. Second Quarter 2014							Year-to-Date 2015 vs. Year-to-Date 2014
		(change in millions)				(% change)			(change in millions)				(% change)
Fuel		$	(116	)		(18.7	)		$	(342	)		(24.9	)
Purchased power – non-affiliates		15				23.8			(4		)		(2.8	)
Purchased power – affiliates		(51		)		(30.7	)		(87		)		(24.9	)
Total fuel and purchased power expenses		$	(152	)					$	(433	)

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

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For year-to-date 2015, total fuel and purchased power expenses were $1.43 billion compared to $1.86 billion in the corresponding period in 2014. The decrease in year-to-date 2015 was primarily due to a $396 million decrease in the average cost of fuel related to lower natural gas, coal, and nuclear fuel prices and a decrease in the average cost of purchased power due to lower natural gas prices and a $99 million decrease in the volume of KWHs generated due to less available generating capacity as a result of plant retirements in April 2015, partially offset by a $62 million increase in the volume of KWHs purchased due to 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 – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

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

		Second Quarter 2015		Second Quarter 2014		Year-to-Date 2015		Year-to-Date 2014
Total generation (billions of KWHs)		17		18		34		36
Total purchased power (billions of KWHs)		6		5		11		10
Sources of generation (percent) —
Coal		40		42		37		45
Nuclear		24		22		23		21
Gas		34		34		38		31
Hydro		2		2		2		3
Cost of fuel, generated (cents per net KWH) —
Coal		3.75		4.20		4.18		4.65
Nuclear		0.85		0.93		0.71		0.92
Gas		2.67		3.81		2.65		4.09
Average cost of fuel, generated (cents per net KWH)		2.66		3.32		2.76		3.66
Average cost of purchased power (cents per net KWH)(*)		4.56		5.55		4.47		5.66

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

Fuel

In the second quarter 2015, fuel expense was $503 million compared to $619 million in the corresponding period in 2014. The decrease was primarily due to a 19.9% decrease in the average cost of fuel per KWH generated and a 6.7% decrease in the volume of KWHs generated by coal.

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

Purchased Power – Non-Affiliates

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

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

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

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 second quarter 2015, purchased power expense from affiliates was $115 million compared to $166 million in the corresponding period in 2014. For year-to-date 2015, purchased power expense from affiliates was $263 million compared to $350 million in the corresponding period in 2014. The decreases were due to a 17.7% decrease in the second quarter 2015 and a 20.7% decrease for year-to-date 2015 in the average cost of KWH purchased, primarily resulting from lower natural gas prices.

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

Other Operations and Maintenance Expenses

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$16		3.5		$65		7.4

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

For year-to-date 2015, other operations and maintenance expenses were $943 million compared to $878 million in the corresponding period in 2014. The increase was primarily due to increases of $31 million in employee compensation and benefits including pension costs, $15 million in scheduled outage-related costs, and $13 million primarily related to customer incentive and demand-side management costs.

Depreciation and Amortization

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(7)		(3.3)		$1		0.2

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

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For year-to-date 2015, depreciation and amortization was $418 million compared to $417 million in the corresponding period in 2014. The increase was due to an increase in depreciation and amortization of $10 million as authorized by the Georgia PSC under the 2013 ARP, partially offset by a decrease in other cost of removal of $9 million.

Taxes Other Than Income Taxes

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(9)		(8.5)		$(14)		(6.7)

In the second quarter 2015, taxes other than income taxes were $97 million compared to $106 million in the corresponding period in 2014. For the year-to-date 2015, taxes other than income taxes were $195 million compared to $209 million in the corresponding period in 2014. The decreases were primarily due to decreases of $6 million and $11 million in municipal franchise fees related to lower retail revenues in the second quarter 2015 and year-to-date 2015, respectively, as well as decreases of $2 million in property taxes for each period.

Other Income (Expense), net

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(10)		(90.9)		$1		6.6

In the second quarter 2015, other income (expense), net was $1 million compared to $11 million in the corresponding period in 2014. For year-to-date 2015, other income (expense), net was $16 million compared to $15 million in the corresponding period in 2014. The changes primarily relate to AFUDC equity.

Income Taxes

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$3		1.7		$(23)		(6.7)

For year-to-date 2015, income taxes were $320 million compared to $343 million in the corresponding period in 2014. The decrease was primarily due to lower pre-tax earnings.

FUTURE EARNINGS POTENTIAL

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

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Environmental Matters

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

Environmental Statutes and Regulations

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

Air Quality

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

On June 12, 2015, the EPA published a final rule requiring affected states (including Georgia, Alabama, and Florida) 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 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 Georgia, Alabama, and Florida. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.

Water Quality

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

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of

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federal jurisdiction under the 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. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

Coal Combustion Residuals

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

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on Georgia Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Georgia Power recorded incremental asset retirement obligations (ARO) of approximately $82 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Georgia Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's AROs.

Global Climate Issues

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

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

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

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

Retail Regulatory Matters

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power 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" in Item 8 of the Form 10-K for additional information.

Renewables Development

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

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

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

Integrated Resource Plan

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

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. Georgia Power expects to file its next fuel case in September 2015. The ultimate outcome of this matter cannot be determined at this time.

Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on 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.

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Nuclear Construction

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

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

Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million in 2008 dollars (approximately $591 million in 2015 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of

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April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor subsequently asserted estimated minimum damages related to the amended counterclaim (based on Georgia Power's ownership interest) of approximately $113 million in 2014 dollars (approximately $118 million in 2015 dollars). In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Georgia Power's eighth VCM report filed in 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.

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

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

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

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

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

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

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

As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

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

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

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

Other Matters

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

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

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anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Asset Retirement Obligations

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

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

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

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

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Recently Issued Accounting Standards

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. Georgia Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. 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 June 30, 2015. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $774 million for the first six months of 2015 compared to $843 million for the corresponding period in 2014. The decrease was primarily due to lower operating revenues, partially offset by increased fuel cost recovery. Net cash used for investing activities totaled $891 million for the first six months of 2015 compared to $917 million for the corresponding period in 2014 primarily related to installation of equipment to comply with environmental standards and construction of transmission and distribution facilities. Net cash provided from financing activities totaled $117 million for the first six months of 2015 compared to $90 million in the corresponding period in 2014. The increase in cash provided from financing activities is primarily due to an increase in short-term debt borrowings. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2015 include increases of $468 million in property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases of $550 million and $231 million in short-term debt and long-term debt, respectively, to fund the continuous construction program and for general corporate purposes.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $1.7 billion will be required through June 30, 2016 to fund maturities and announced redemptions of long-term debt. See "Sources of Capital" herein for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the

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

Sources of Capital

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

In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which may be used to reimburse Georgia Power for Eligible 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. Eligible Project Costs incurred through June 30, 2015 would allow for borrowings of up to $2.2 billion under the FFB Credit Facility, of which Georgia Power has 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.

As of June 30, 2015, Georgia Power's current liabilities exceeded current assets by $1.3 billion primarily due to approximately $1.9 billion of long-term debt due within one year and notes payable. For the remainder of 2015, Georgia Power expects to utilize borrowings through the FFB as the primary source of long-term borrowed funds. Georgia Power also intends to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, and equity contributions from Southern Company to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

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

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

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

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

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

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

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

Details of short-term borrowings were as follows:

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

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

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

Credit Rating Risk

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

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

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

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

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

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

Financing Activities

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

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

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

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

In June 2015, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million. The interest rate applicable to the $600 million principal amount is 3.283% for an interest period that extends to 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 4. Georgia Power settled $350 million of interest rate swaps related to this borrowing for approximately $6 million, which will be amortized to interest expense over 10 years.

Subsequent to June 30, 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.

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

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CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2015				2014				2015				2014
	(in millions)								(in millions)
Operating Revenues:
Retail revenues	$	327			$	310			$	620			$	613
Wholesale revenues, non-affiliates	27				34				52				70
Wholesale revenues, affiliates	13				24				35				76
Other revenues	17				16				34				32
Total operating revenues	384				384				741				791
Operating Expenses:
Fuel	122				145				232				314
Purchased power, non-affiliates	25				14				50				30
Purchased power, affiliates	9				9				17				16
Other operations and maintenance	91				82				185				164
Depreciation and amortization	40				39				60				71
Taxes other than income taxes	28				26				56				53
Total operating expenses	315				315				600				648
Operating Income	69				69				141				143
Other Income and (Expense):
Allowance for equity funds used during construction	3				3				8				5
Interest expense, net of amounts capitalized	(12		)		(13		)		(26		)		(27		)
Other income (expense), net	(1		)		(1		)		(2		)		(1		)
Total other income and (expense)	(10		)		(11		)		(20		)		(23		)
Earnings Before Income Taxes	59				58				121				120
Income taxes	21				22				44				45
Net Income	38				36				77				75
Dividends on Preference Stock	3				2				5				4
Net Income After Dividends on Preference Stock	$	35			$	34			$	72			$	71

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

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

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

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

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

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

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

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

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

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2015 vs. SECOND QUARTER 2014

AND

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

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service 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, 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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$1		2.9		$1		1.4

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

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

Retail Revenues

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$17		5.5		$7		1.1

In the second quarter 2015, retail revenues were $327 million compared to $310 million for the corresponding period in 2014. For year-to-date 2015, retail revenues were $620 million compared to $613 million for the corresponding period in 2014.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

		Second Quarter 2015							Year-to-Date  2015
		(in millions)				(% change)			(in millions)				(% change)
Retail – prior year		$	310						$	613
Estimated change resulting from –
Rates and pricing		7				2.3			10				1.7
Sales growth		2				0.6			—				—
Weather		4				1.3			4				0.6
Fuel and other cost recovery		4				1.3			(7		)		(1.2	)
Retail – current year		$	327			5.5	%		$	620			1.1	%

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "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 second quarter and year-to-date 2015 when compared to the corresponding periods in 2014 primarily due to an increase in retail base rates effective in January 2015, as authorized in a settlement agreement for Gulf Power's 2013 base rate case, and higher revenues associated with an increase in the environmental and energy conservation cost recovery clause rates effective in January 2015.

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

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

Fuel and other cost recovery revenues increased in the second quarter 2015 when compared to the corresponding period in 2014 primarily due to higher revenues associated with increased recoverable purchased power capacity costs, partially offset by lower revenues associated with fuel costs as the result of decreased generation and lower purchased power energy costs. For year-to-date 2015, fuel and other cost recovery revenues decreased when compared to the corresponding period in 2014 primarily due to lower revenues associated with fuel costs as a result of decreased generation and lower purchased power energy costs, partially offset by higher revenues associated with purchased power capacity costs.

Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(7)		(20.6)		$(18)		(25.7)

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

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

For year-to-date 2015, wholesale revenues from sales to non-affiliates were $52 million compared to $70 million for the corresponding period in 2014. The decrease was primarily due to a 52.1% decrease in KWH sales resulting from lower sales under the Plant Scherer Unit 3 long-term sales agreements due to a planned outage and lower natural gas prices that led to increased customer-owned generation.

Wholesale Revenues – Affiliates

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(11)		(45.8)		$(41)		(53.9)

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

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

For year-to-date 2015, wholesale revenues from sales to affiliates were $35 million compared to $76 million for the corresponding period in 2014. The decrease was primarily due to a 37.2% decrease in KWH sales that resulted from planned outages for Gulf Power generation resources and a 26.1% decrease in the price of energy sold to affiliates due to lower power pool interchange rates resulting from lower natural gas prices.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

		Second Quarter 2015 vs. Second Quarter 2014							Year-to-Date 2015 vs. Year-to-Date 2014
		(change in millions)				(% change)			(change in millions)				(% change)
Fuel		$	(23	)		(15.9	)		$	(82	)		(26.1	)
Purchased power – non-affiliates		11				78.6			20				66.7
Purchased power – affiliates		—				—			1				6.3
Total fuel and purchased power expenses		$	(12	)					$	(61	)

In the second quarter 2015, total fuel and purchased power expenses were $156 million compared to $168 million for the corresponding period in 2014. The decrease was primarily the result of a $9 million decrease in the volume of KWHs generated and purchased due to planned outages for Gulf Power's generation and a resource contracted under a PPA and a $3 million net decrease due to the lower average cost of fuel and purchased power.

For year-to-date 2015, total fuel and purchased power expenses were $299 million compared to $360 million for the corresponding period in 2014. The decrease was primarily the result of a $50 million decrease in the volume of KWHs generated and purchased due to planned outages for Gulf Power's generation and a resource contracted under a PPA and an $11 million net decrease due to the lower average cost of fuel and purchased power.

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

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

		Second Quarter 2015		Second Quarter 2014		Year-to-Date 2015		Year-to-Date 2014
Total generation (millions of KWHs)		2,360		2,670		4,596		5,632
Total purchased power (millions of KWHs)		1,336		1,281		2,594		2,711
Sources of generation (percent) –
Coal		61		69		60		70
Gas		39		31		40		30
Cost of fuel, generated (cents per net KWH) –
Coal		4.05		4.09		4.02		4.21
Gas		4.38		3.99		4.17		3.82
Average cost of fuel, generated (cents per net KWH)		4.18		4.06		4.08		4.09
Average cost of purchased power (cents per net KWH)(*)		4.25		4.71		4.31		4.75

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

Fuel

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Purchased Power – Non-Affiliates

In the second quarter 2015, purchased power expense from non-affiliates was $25 million compared to $14 million for the corresponding period in 2014. The increase was primarily due to a $10 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA in mid-2014. The increase was partially offset by a 7.9% decrease in the volume of KWHs purchased due to a planned outage for a resource contracted under a PPA.

For year-to-date 2015, purchased power expense from non-affiliates was $50 million compared to $30 million for the corresponding period in 2014. The increase was primarily due to a $26 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA in mid-2014. The increase was partially offset by a 17.4% decrease in the volume of KWHs purchased due to a planned outage for a resource contracted under a PPA.

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

Purchased Power – Affiliates

In the second quarter 2015 and the corresponding period in 2014, purchased power expense from affiliates was $9 million. The volume of KWHs purchased increased 55.4% due to planned outages for Gulf Power's generation and a resource contracted under a PPA. The increase was offset by a 39.1% decrease in the average cost per KWH purchased due to lower power pool interchange rates.

For year-to-date 2015, purchased power expense from affiliates was $17 million compared to $16 million for the corresponding period in 2014. The increase was primarily due to a 68.5% increase in the volume of KWHs purchased due to planned outages for Gulf Power's generation and a resource contracted under a PPA, largely offset by a 36.0% decrease in the average cost per KWH purchased due to lower power pool interchange rates.

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

Other Operations and Maintenance Expenses

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$9		11.0		$21		12.8

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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Expenses from energy services did not have a significant impact on earnings since they were generally offset by associated revenues. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$1		2.6		$(11)		(15.5)

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

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

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

Taxes Other Than Income Taxes

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$2		7.7		$3		5.7

In the second quarter 2015, taxes other than income taxes were $28 million compared to $26 million for the corresponding period in 2014. For year-to-date 2015, taxes other than income taxes were $56 million compared to $53 million for the corresponding period in 2014. The increases were primarily due to increases in property taxes, franchise fees, and gross receipts taxes. Franchise fees and gross receipts taxes have no impact on net income.

Allowance for Equity Funds Used During Construction

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$—		—		$3		60.0

For year-to-date 2015, AFUDC equity was $8 million compared to $5 million for the corresponding period in 2014. The increase was primarily due to increased construction related to environmental control projects at generation facilities.

FUTURE EARNINGS POTENTIAL

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

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

Gulf Power's wholesale business consists of two types of agreements. The first type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's co-ownership of 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.

Environmental Matters

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

Environmental Statutes and Regulations

Air Quality

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

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 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

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

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

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

Water Quality

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

On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of federal jurisdiction under the CWA 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. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

Coal Combustion Residuals

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

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on Gulf Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Gulf Power recorded incremental asset retirement obligations (ARO) of approximately $75 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Gulf Power expects to periodically update these estimates.

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

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

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Global Climate Issues

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

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

FERC Matters

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

Retail Regulatory Matters

Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the 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.

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Retail Base Rate Case

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

Cost Recovery Clauses

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

Renewables

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.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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Asset Retirement Obligations

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

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

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

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

Recently Issued Accounting Standards

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. Gulf Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. 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 June 30, 2015. Gulf Power intends to continue to monitor its access to short-term and long-term

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capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $183 million for the first six months of 2015 compared to $177 million for the corresponding period in 2014. The $6 million increase in net cash was primarily due to increases in cash flows related to cost recovery clauses and an increase in deferred income taxes related to bonus depreciation, partially offset by decreases in the timing of fossil fuel stock purchases, accrued compensation, and accounts payable. Net cash used for investing activities totaled $174 million in the first six months of 2015 primarily due to property additions to utility plant. Net cash used for financing activities totaled $4 million for the first six months of 2015 primarily due to the payment of common stock dividends, partially offset by an increase in notes payable and the issuance of common stock to Southern Company. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2015 include increases of $166 million in net property, plant, and equipment, $86 million in other deferred credits and other liabilities primarily related to AROs associated with the CCR Rule, $52 million in accumulated deferred income tax liabilities primarily related to bonus depreciation, and $44 million in notes 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 $60 million will be required through June 30, 2016 to fund announced redemptions of long-term debt. See "Financing Activities" herein for additional information.

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

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, including its commercial paper program which is supported by bank credit facilities.

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

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

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

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

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross default provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness 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. In connection therewith, Gulf Power may extend the 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 June 30, 2015							Short-term Debt During the Period(*)
		Amount Outstanding				Weighted Average Interest Rate			Average Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
		(in millions)							(in millions)							(in millions)
Commercial paper		$	114			0.3	%		$	133			0.3	%		$	175
Short-term bank debt		40				1.3	%		10				1.3	%		40
Total		$	154			0.6	%		$	143			0.4	%

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

Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and operating cash flows.

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Credit Rating Risk

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

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

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

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

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

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

Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the second quarter and year-to-date 2015 has not changed materially compared to the December 31, 2014 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreements shift substantially all fuel cost responsibility to the purchaser. However, Gulf Power could become exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively pursuing replacement wholesale contracts 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 2015, Gulf Power issued 200,000 shares of common stock to Southern Company and realized proceeds of $20 million. The proceeds were used to repay a portion of Gulf Power's short-term debt and for other general corporate purposes, including Gulf Power's continuous construction program.

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

Subsequent to June 30, 2015, Gulf Power purchased and held $13 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Refunding Bonds (Gulf Power Company Project), Series 2012. Gulf Power reoffered these bonds on July 16, 2015.

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Subsequent to June 30, 2015, Gulf Power announced the redemption in September 2015 of $60 million aggregate principal amount of its Series L 5.65% Senior Notes due September 1, 2035.

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

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CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

 

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2015				2014				2015				2014
	(in millions)								(in millions)
Operating Revenues:
Retail revenues	$	189			$	211			$	357			$	418
Wholesale revenues, non-affiliates	63				75				141				172
Wholesale revenues, affiliates	18				20				45				43
Other revenues	5				5				9				9
Total operating revenues	275				311				552				642
Operating Expenses:
Fuel	115				143				229				290
Purchased power, non-affiliates	2				1				3				13
Purchased power, affiliates	2				6				4				15
Other operations and maintenance	68				61				144				125
Depreciation and amortization	30				24				57				47
Taxes other than income taxes	23				20				48				41
Estimated loss on Kemper IGCC	23				—				32				380
Total operating expenses	263				255				517				911
Operating Income (Loss)	12				56				35				(269		)
Other Income and (Expense):
Allowance for equity funds used during construction	25				37				53				75
Interest expense, net of amounts capitalized	30				(13		)		19				(25		)
Other income (expense), net	(1		)		(1		)		(2		)		(4		)
Total other income and (expense)	54				23				70				46
Earnings (Loss) Before Income Taxes	66				79				105				(223		)
Income taxes (benefit)	16				16				20				(114		)
Net Income (Loss)	50				63				85				(109		)
Dividends on Preferred Stock	1				1				1				1
Net Income (Loss) After Dividends on Preferred Stock	$	49			$	62			$	84			$	(110	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

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

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

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

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

Assets		At June 30, 2015				At December 31, 2014
		(in millions)
Current Assets:
Cash and cash equivalents		$	212			$	133
Receivables —
Customer accounts receivable		44				43
Unbilled revenues		37				35
Other accounts and notes receivable		11				11
Affiliated companies		43				51
Accumulated provision for uncollectible accounts		(1		)		(1		)
Fossil fuel stock, at average cost		95				100
Materials and supplies, at average cost		69				62
Other regulatory assets, current		69				73
Prepaid income taxes		193				191
Other current assets		7				6
Total current assets		779				704
Property, Plant, and Equipment:
In service		4,456				4,378
Less accumulated provision for depreciation		1,194				1,173
Plant in service, net of depreciation		3,262				3,205
Construction work in progress		2,543				2,161
Total property, plant, and equipment		5,805				5,366
Other Property and Investments		6				5
Deferred Charges and Other Assets:
Deferred charges related to income taxes		260				226
Other regulatory assets, deferred		482				385
Income taxes receivable, non-current		544				—
Other deferred charges and assets		71				71
Total deferred charges and other assets		1,357				682
Total Assets		$	7,947			$	6,757

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

Liabilities and Stockholder's Equity		At June 30, 2015				At December 31, 2014
		(in millions)
Current Liabilities:
Securities due within one year		$	429			$	778
Notes payable		505				—
Interest-bearing refundable deposits		—				275
Accounts payable —
Affiliated		88				86
Other		136				178
Accrued taxes —
Accrued income taxes		—				142
Other accrued taxes		47				84
Accrued interest		13				76
Accrued compensation		14				26
Over recovered regulatory clause liabilities		33				1
Mirror CWIP		353				271
Other current liabilities		59				61
Total current liabilities		1,677				1,978
Long-term Debt:
Long-term debt, affiliated		301				—
Long-term debt, non-affiliated		1,623				1,630
Total Long-term Debt		1,924				1,630
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		844				285
Accumulated deferred investment tax credits		282				283
Employee benefit obligations		146				148
Asset retirement obligations		148				48
Other cost of removal obligations		170				166
Other regulatory liabilities, deferred		65				64
Other deferred credits and liabilities		410				38
Total deferred credits and other liabilities		2,065				1,032
Total Liabilities		5,666				4,640
Redeemable Preferred Stock		33				33
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 1,130,000 shares
Outstanding — 1,121,000 shares		38				38
Paid-in capital		2,692				2,612
Accumulated deficit		(475		)		(559		)
Accumulated other comprehensive loss		(7		)		(7		)
Total common stockholder's equity		2,248				2,084
Total Liabilities and Stockholder's Equity		$	7,947			$	6,757

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

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SECOND QUARTER 2015 vs. SECOND QUARTER 2014

AND

YEAR-TO-DATE 2015 vs. YEAR-TO-DATE 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 that provides timely recovery of prudently-incurred costs. These costs include those related to the completion and operation of major construction projects, primarily the Kemper IGCC and the Plant Daniel scrubber project, projected long-term demand growth, reliability, fuel, and increasingly stringent environmental standards, as well as ongoing capital expenditures required for maintenance. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC established by the Mississippi PSC was $2.4 billion with a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE 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).

Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.23 billion, which includes approximately $4.96 billion of costs subject to the construction cost cap. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23 million ($14 million after tax) in the second quarter 2015 and $9 million ($6 million after tax) in the first quarter 2015. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.08 billion ($1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2015.

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

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

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

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

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

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

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

The return of approximately $301 million to SMEPA in June 2015 in connection with the termination of the APA, the required refund of the approximately $353 million of Mirror CWIP rate collections, including associated carrying costs, and the termination of the Mirror CWIP rates have adversely impacted Mississippi Power's ability to obtain financing needed for its business operations.

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

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

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

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costs through June 30, 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. In addition, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company that matures on December 2, 2016 in conjunction with the repayment of SMEPA's deposits with interest, following the termination of SMEPA's planned purchase of 15% of the Kemper IGCC project. Furthermore, Mississippi Power expects to fund the cash component of the Mirror CWIP refund with an intercompany loan from Southern Company. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.

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

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(13)		(21.0)		$194		N/M

N/M-Not meaningful

Mississippi Power's net income after dividends on preferred stock for the second quarter 2015 was $49 million compared to $62 million for the corresponding period in 2014. The decrease was primarily related to $23 million in pre-tax charges ($14 million after tax) in the second quarter 2015 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. The decrease in net income was also related to a decrease in AFUDC equity, increases in non-fuel operations and maintenance expenses, an increase in depreciation and amortization, and a decrease in retail revenues primarily resulting from the Court's decision, partially offset by a decrease in interest expense.

For year-to-date 2015, net income after dividends on preferred stock was $84 million compared to a net loss of $110 million for the corresponding period in 2014. The increase was primarily related to $32 million in pre-tax charges ($20 million after tax) in 2015 compared to $380 million in pre-tax charges ($235 million after tax) in 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 increase in net income was also related to a decrease in interest expense, partially offset by a decrease in AFUDC equity, increases in non-fuel operations and maintenance expenses, an increase in depreciation and amortization, and a decrease in retail revenues primarily resulting from the Court's decision.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined

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Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information. Also see "Interest Expense, Net of Amounts Capitalized" herein for additional information.

Retail Revenues

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(22)		(10.4)		$(61)		(14.6)

In the second quarter 2015, retail revenues were $189 million compared to $211 million for the corresponding period in 2014. For year-to-date 2015, retail revenues were $357 million compared to $418 million for the corresponding period in 2014.

Details of the changes in retail revenues were as follows:

		Second Quarter 2015							Year-to-Date  2015
		(in millions)				(% change)			(in millions)				(% change)
Retail – prior year		$	211						$	418
Estimated change resulting from –
Rates and pricing		(6		)		(2.7	)		(9		)		(2.2	)
Sales decline		(1		)		(0.6	)		(5		)		(1.2	)
Weather		2				0.9			1				0.2
Fuel and other cost recovery		(17		)		(8.0	)		(48		)		(11.4	)
Retail – current year		$	189			(10.4	)%		$	357			(14.6	)%

Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2015 when compared to the corresponding periods in 2014 primarily due to $7 million and $11 million, respectively, of revenues associated with the Kemper IGCC cost recovery recognized in 2014, which ceased in 2015 as a result of the Court's decision, partially offset by $1 million in the second quarter 2015 and $2 million year-to-date 2015 in net revenues for the new energy efficiency cost recovery rate, which began in the fourth quarter 2014.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Revenues attributable to changes in sales decreased in the second quarter 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH sales to residential customers decreased 0.5% in the second quarter 2015 due to lower customer usage, slightly offset by an increase in customers. Weather-adjusted KWH sales to commercial customers increased 2.6% in the second quarter 2015 due to higher customer usage and an increase in customers. KWH sales to industrial customers decreased 0.9% in the second quarter 2015 due to decreased usage by larger customers related to planned maintenance outages.

Revenues attributable to changes in sales decreased year-to-date 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH energy sales to residential customers decreased 1.2% due to lower customer usage, slightly offset by an increase in customers. Weather-adjusted KWH energy sales to commercial customers decreased 0.2% due to lower customer usage slightly offset by an increase in customers. KWH energy sales to industrial customers increased 1.2% primarily due to increased usage by larger customers.

In the first quarter 2015, Mississippi Power updated its methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled second quarter

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and year-to-date 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without these adjustments, second quarter 2015 weather-adjusted residential KWH sales increased 4.0%, weather-adjusted commercial KWH sales decreased 1.5%, and industrial KWH sales decreased 2.1% as compared to the corresponding period in 2014. Also, without these adjustments, year-to-date 2015 weather-adjusted residential KWH sales decreased 3.3%, weather-adjusted commercial KWH sales decreased 5.1%, and industrial KWH sales remained flat as compared to the corresponding period in 2014.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2015 when compared to the corresponding periods in 2014, primarily as a result of lower recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of 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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(12)		(16.0)		$(31)		(18.0)

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Mississippi Power serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K for additional information.

In the second quarter 2015, wholesale revenues from sales to non-affiliates were $63 million compared to $75 million for the corresponding period in 2014. For year-to-date 2015, wholesale revenues from sales to non-affiliates were $141 million compared to $172 million for the corresponding period in 2014. The decreases were primarily due to a decrease in energy revenues resulting from lower market prices and fuel cost.

Wholesale Revenues – Affiliates

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(2)		(10.0)		$2		4.7

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

In the second quarter 2015, wholesale revenues from sales to affiliates were $18 million compared to $20 million for the corresponding period in 2014. The decrease was due to a $6 million decrease associated with lower natural gas prices, partially offset by a $4 million increase in KWH sales due to higher gas generation partially as a result of the Kemper IGCC combined cycle being in service since August 2014.

For year-to-date 2015, wholesale revenues from sales to affiliates were $45 million compared to $43 million for the corresponding period in 2014. The increase was due to an $18 million increase in KWH sales due to higher gas

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generation partially as a result of the Kemper IGCC combined cycle being in service since August 2014, partially offset by a $16 million decrease associated with lower natural gas prices.

Fuel and Purchased Power Expenses

		Second Quarter 2015 vs. Second Quarter 2014						Year-to-Date 2015 vs. Year-to-Date 2014
		(change in millions)				(% change)		(change in millions)				(% change)
Fuel		$	(28	)		(19.6)		$	(61	)		(21.0	)
Purchased power – non-affiliates		1				100.0		(10		)		(76.9	)
Purchased power – affiliates		(4		)		(66.7)		(11		)		(73.3	)
Total fuel and purchased power expenses		$	(31	)				$	(82	)

In the second quarter 2015, total fuel and purchased power expenses were $119 million compared to $150 million for the corresponding period in 2014. The decrease was due to a $28 million decrease in the average cost of fuel and purchased power and a $3 million decrease in the volume of KWHs purchased.

For year-to-date 2015, total fuel and purchased power expenses were $236 million compared to $318 million for the corresponding period in 2014. The decrease was due to a $72 million decrease in the average cost of fuel and purchased power and a $14 million decrease in the volume of KWHs purchased, partially offset by a $4 million increase in the volume of KWHs generated.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.

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

		Second Quarter 2015		Second Quarter 2014		Year-to-Date 2015		Year-to-Date 2014
Total generation (millions of KWHs)(*)		4,109		3,932		8,455		7,974
Total purchased power (millions of KWHs)		114		208		227		466
Sources of generation (percent)(*) –
Coal		18		47		20		46
Gas		82		53		80		54
Cost of fuel, generated (cents per net KWH) –
Coal		4.14		4.18		3.64		4.21
Gas(*)		2.71		3.62		2.69		3.61
Average cost of fuel, generated (cents per net KWH)(*)		2.98		3.90		2.90		3.91
Average cost of purchased power (cents per net KWH)(*)		3.19		3.33		3.37		5.87

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

Fuel

In the second quarter 2015, fuel expense was $115 million compared to $143 million for the corresponding period in 2014. The decrease was primarily due to a 23.6% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower natural gas prices, partially offset by a 4.9% increase in the volume of KWHs generated resulting from the availability of lower cost Mississippi Power units. The 4.9% increase in volume included an increase in gas-fired generation of 70.2%, partially offset by a decrease in coal-fired generation of 60.2%.

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For year-to-date 2015, total fuel expense was $229 million compared to $290 million for the corresponding period in 2014. The decrease was primarily due to a 25.8% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower natural gas prices, partially offset by a 6.1% increase in the volume of KWHs generated resulting from the availability of lower cost Mississippi Power units. The 6.1% increase in volume included an increase in gas-fired generation of 65.2%, offset by a decrease in coal-fired generation of 53.7%.

Purchased Power - Non-Affiliates

In the second quarter 2015, purchased power expense from non-affiliates was $2 million compared to $1 million for the corresponding period in 2014. The increase was primarily the result of a 57.6% increase in the average cost per KWH, offset by a 2.8% decrease in the volume of KWHs purchased due to an increase in Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014.

For year-to-date 2015, purchased power expense from non-affiliates was $3 million compared to $13 million for the corresponding period in 2014. The decrease was primarily the result of a 54.1% decrease in the volume of KWHs purchased due to an increase in Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014 and a 42.3% decrease in the average cost per KWH purchased as a result of lower natural gas prices.

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

Purchased Power - Affiliates

In the second quarter 2015, purchased power expense from affiliates was $2 million compared to $6 million for the corresponding period in 2014. The decrease was primarily due to a 58.3% decrease in the volume of KWHs purchased due to increased Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014, and a 24.7% decrease in the average cost per KWH purchased as a result of lower natural gas prices.

For year-to-date 2015, purchased power expense from affiliates was $4 million compared to $15 million for the corresponding period in 2014. The decrease was primarily due to a 50.0% 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 41.5% decrease in the average cost per KWH purchased as a result of lower natural gas prices.

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

Other Operations and Maintenance Expenses

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$7		11.5		$19		15.2

In the second quarter 2015, other operations and maintenance expenses were $68 million compared to $61 million for the corresponding period in 2014. The increase was primarily due to a $7 million increase in generation maintenance expenses primarily related to scheduled outages.

For year-to-date 2015, other operations and maintenance expenses were $144 million compared to $125 million for the corresponding period in 2014. The increase was primarily due to a $6 million increase in generation

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maintenance expenses including scheduled outages, a $5 million increase in employee compensation and benefits including pension, and a $5 million increase related to uncollectible expenses and customer incentives.

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

Depreciation and Amortization

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$6		25.0		$10		21.3

In the second quarter 2015, depreciation and amortization was $30 million compared to $24 million for the corresponding period in 2014. The increase was primarily due to a $2 million increase in depreciation related to increases in generation and distribution plant in service, a $2 million increase related to regulatory deferrals associated with Plant Daniel Units 3 and 4 and the Kemper IGCC, and a $1 million increase in ECO Plan amortization.

For year-to-date 2015, depreciation and amortization was $57 million compared to $47 million for the corresponding period in 2014. The increase was primarily due to a $4 million increase in depreciation related to increases in generation, transmission and distribution plant in service, a $4 million increase related to regulatory deferrals associated with Plant Daniel Units 3 and 4 and the Kemper IGCC, and a $2 million increase in ECO Plan amortization.

See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. 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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$3		15.0		$7		17.1

In the second quarter 2015, taxes other than income taxes were $23 million compared to $20 million for the corresponding period in 2014. The increase was primarily due to a $3 million increase in ad valorem taxes, partially offset by a $1 million decrease in franchise tax.

For year-to-date 2015, taxes other than income taxes were $48 million compared to $41 million for the corresponding period in 2014. The increase was primarily due to a $9 million increase in ad valorem taxes, partially offset by a $2 million decrease in franchise taxes.

The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, therefore, does not affect net income.

Estimated Loss on Kemper IGCC

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$23		N/M		$(348)		(91.6)

N/M-Not meaningful

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In the second quarter 2015 an estimated probable loss on the Kemper IGCC of $23 million was recorded at Mississippi Power. For year-to-date 2015 and year-to-date 2014, estimated probable losses on the Kemper IGCC of $32 million and $380 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.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Allowance for Equity Funds Used During Construction

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(12)		(32.4)		$(22)		(29.3)

In the second quarter 2015, AFUDC equity was $25 million compared to $37 million for the corresponding period in 2014. For year-to-date 2015, AFUDC equity was $53 million compared to $75 million for the corresponding period in 2014. The decreases are driven by a reduction in the AFUDC rate and by placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and 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

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(43)		N/M		$(44)		N/M

N/M-Not meaningful

In the second quarter 2015, interest expense, net of amounts capitalized was ($30) million compared to $13 million for the corresponding period in 2014. For year-to-date 2015, interest expense, net of amounts capitalized was ($19) million compared to $25 million for the corresponding period in 2014. The decreases were primarily due to a $41 million decrease related to the termination of the APA between Mississippi Power and SMEPA which required the return of SMEPA's deposits at a lower rate of interest than accrued. Also contributing to the decrease was an increase in capitalized interest primarily resulting from carrying costs related to the Kemper IGCC. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Income Taxes (Benefit)

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$—		—		$134		N/M

N/M-Not meaningful

In the second quarter 2015 and 2014, income taxes were $16 million. For year-to-date 2015, income taxes (benefit) were $20 million compared to $(114) million for the corresponding period in 2014. The change primarily reflects a

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reduction in tax benefits related to the estimated probable losses on the construction of the Kemper IGCC recorded in 2014.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis 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 Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million excluding the reserve for cost of removal. As of June 30, 2015, Mississippi Power reclassified the net carrying value of these assets from accumulated provision for depreciation to other regulatory assets, deferred, in accordance with an accounting order from the Mississippi PSC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Sierra Club Settlement Agreement" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.

Mississippi Power expects to recover through its rates the remaining book value of the retired assets and certain costs, including unusable inventory, associated with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.

New Source Review Actions

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

On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case. If approved by the U.S. District Court for the Northern District of Alabama, Alabama

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Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

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

Environmental Statutes and Regulations

See Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.

Air Quality

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

On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama and Mississippi) 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 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. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.

Water Quality

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

On 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 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. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.

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Coal Combustion Residuals

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

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on Mississippi Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Mississippi Power recorded incremental asset retirement obligations (ARO) of approximately $95 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Mississippi Power's AROs.

Global Climate Issues

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

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

FERC Matters

Municipal and Rural Associations Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.

On March 31, 2015, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgo the Municipal and Rural Associations cost-based electric tariff increase reflected in

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the filing by, among other things, increasing the accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, which was accepted by the FERC on May 13, 2015, provides that the additional accrual of AFUDC was effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $11 million annually, of which $8 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.

Market-Based Rate Authority

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

Retail Regulatory Matters

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as the Kemper IGCC, fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through Mississippi Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

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, the projects are expected to be in service by the end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

On March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow it more time for review. The ultimate outcome of this matter cannot be determined at this time.

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Ad Valorem Tax Adjustment

On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates. On May 26, 2015, the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See 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 Overview

Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO₂ pipeline infrastructure for the planned transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the costs subject to the cost cap and the Cost Cap Exceptions remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court decision), and actual costs incurred as of June 30, 2015, as adjusted for the Court's decision, are as follows:

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Cost Category	2010 Project Estimate(f)				Current Estimate				Actual Costs at June 30, 2015
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40			$	4.96			$	4.51
Lignite Mine and Equipment	0.21				0.23				0.23
CO2 Pipeline Facilities	0.14				0.11				0.11
AFUDC(b)(c)	0.17				0.62				0.52
Combined Cycle and Related Assets Placed in   Service – Incremental(d)	—				0.02				—
General Exceptions	0.05				0.10				0.08
Deferred Costs(c)(e)	—				0.19				0.15
Total Kemper IGCC(a)(c)	$	2.97			$	6.23			$	5.60

(a)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.

(b)

Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(c)	Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

(d)	Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.

(e)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

(f)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.08 billion), $2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, $16 million in other deferred charges and assets, and $24 million in AROs in the balance sheet, with $1 million previously expensed.

Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23 million ($14 million after tax) in the second quarter 2015 and $9 million ($6 million after tax) in the first quarter 2015. These amounts are in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. The increases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to equipment rework, scope modifications, and the related additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion

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cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

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

Rate Recovery of Kemper IGCC Costs

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 2015 Rate Case and any alternative proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the

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estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC through the in-service date until directed to do otherwise by the Mississippi PSC.

In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.

In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Mississippi Power.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.

2015 Rate Case

As a result of the 2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On

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May 15, 2015, Mississippi Power filed the 2015 Rate Case with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.

On July 10, 2015, Mississippi Power filed a Supplemental Notice with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal, In-Service Asset Proposal, for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.

The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

If the Mississippi PSC does not act on the Supplemental Notice or the 2015 Rate Case within 120 days of the Supplemental Notice filing, Mississippi Power expects to put one of the three viable alternative rate proposals into effect as temporary rates under bond and subject to refund pursuant to Mississippi state law.

Mississippi Power also expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 2015 of $6.23 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for

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interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.

Regulatory Assets and Liabilities

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of June 30, 2015, the regulatory asset balance associated with the Kemper IGCC was $198 million. The projected balance at March 31, 2016 is estimated to total approximately $276 million. The amortization period for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

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

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

Lignite Mine and CO₂ Pipeline Facilities

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

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

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO₂ delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact

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on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

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

Termination of Proposed Sale of Undivided Interest to SMEPA

In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and SMEPA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.

Income Tax Matters

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

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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

During 2015, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.

As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of $2.08 billion ($1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2015.

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

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

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Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Asset Retirement Obligations

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

The liability for AROs primarily relates to facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Mississippi Power has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. Mississippi Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

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

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

Recently Issued Accounting Standards

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

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Mississippi Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its

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balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Mississippi Power's financial condition was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections, which as of June 30, 2015 was approximately $353 million including associated carrying costs, and the termination of the Mirror CWIP rate will further adversely impact Mississippi Power's financial condition and its ability to obtain financing needed for normal business operations and completion of the Kemper IGCC. Earnings for the six months ended June 30, 2015 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. Earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

In addition to funding normal business operations and projected capital expenditures, Mississippi Power's cash requirements primarily consist of $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs. In addition, Mississippi Power issued an 18-month promissory note to Southern Company in the aggregate principal amount of approximately $301 million related to the refund to SMEPA and expects to enter into a similar promissory note with Southern Company to fund the Mirror CWIP refund. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA," "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order," " – 2015 Mississippi Supreme Court Decision," and " – 2015 Rate Case" herein for additional information. For the three-year period from 2015 through 2017, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental equipment for existing generating units, including the Plant Daniel scrubber project, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. See "Sources of Capital" herein for additional information.

Through June 30, 2015, Mississippi Power has incurred non-recoverable cash expenditures of $1.62 billion and is expected to incur approximately $0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.

During the first six months of 2015, Mississippi Power received $75 million in equity contributions from Southern Company. In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. On June 3, 2015, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company as a result of Southern Company's refund of approximately $301 million in deposits and associated interest to SMEPA in connection with the termination of the APA. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled $309 million for the first six months of 2015, an increase of $131 million as compared to the corresponding period in 2014. The increase in cash provided from operating activities is primarily due to R&E tax deductions and bonus depreciation reducing tax payments, an increase in fuel recovery, and a decrease in receivables, partially offset by the timing of payments for accounts payable and fuel purchases. See Notes (B) and Note (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $460 million for the first six months of 2015 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $230 million for the first six months of 2015 primarily due to short-term bank loans, capital contributions from Southern Company, and short-term borrowings, partially offset by redemptions of long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2015 include a decrease in securities due within one year of $349 million, primarily due to refinancing or replacing maturing long-term debt with short-term loans. Additionally, long-term debt increased $301 million and interest-bearing refundable deposit decreased $275 million, due to an intercompany loan for repayment of the SMEPA deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased $439 million; other regulatory assets, deferred increased $97 million; and the Mirror CWIP regulatory liability increased $82 million primarily associated with construction, operation, and collections related to the Kemper IGCC. See – "Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current; accrued income taxes; accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and other deferred credits and liabilities increased primarily due to R&E tax deductions and the related reserve. Additional changes include increases in notes payable primarily due to new short-term bank loans and asset retirement obligations due to the CCR Rule. Total common stockholder's equity increased $164 million primarily due to the receipt of $75 million in capital contributions from Southern Company and due to net income during the second quarter 2015.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $900 million will be required through June 30, 2016 to fund maturities of bank term loans scheduled to mature on April 1, 2016 and $30 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs. See "Sources of Capital" herein for additional information.

The construction program of Mississippi Power is currently estimated to be $1.0 billion in 2015, $354 million in 2016, and $229 million for 2017, which includes expenditures related to the construction of the Kemper IGCC of $801 million in 2015 and $150 million in 2016.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (B) to the Condensed Financial Statements under "Integrated Coal

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.

Sources of Capital

Except as described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. Mississippi Power's financial condition was adversely affected by the issuance of an 18-month promissory note to Southern Company related to the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Mississippi Supreme Court Decision" of Mississippi Power in Item 7 of the Form 10-K and herein for additional information.

Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. As of June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $898 million primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs through June 30, 2015. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.

At June 30, 2015, Mississippi Power had approximately $212 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2015 were as follows:

Expires																Executable Term Loans								Due Within One Year
2015				2016				Total				Unused				One Year				Two Years				Term Out				No Term Out
(in millions)								(in millions)								(in millions)								(in millions)
$	40			$	255			$	295			$	265			$	30			$	40			$	70			$	225

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

A portion of the $265 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $40 million.

Most of these bank credit arrangements contain covenants that limit debt levels and typically contain cross default provisions to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specified threshold. Mississippi Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

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

To the extent available, Mississippi Power may seek to utilize a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power would be loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:

		Short-term Debt at June 30, 2015						Short-term Debt During the Period(*)
		Amount Outstanding				Weighted Average Interest Rate		Average Outstanding				Weighted Average Interest Rate		Maximum Amount Outstanding
		(in millions)						(in millions)						(in millions)
Short-term bank debt		$	505			1.4%		$	460			1.4%		$	505

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

Credit Rating Risk

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

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At June 30, 2015, the maximum potential collateral requirements under these contracts at a rating of BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $282 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade has impacted and may continue to impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In March 2015, Mississippi Power repaid at maturity a $75 million bank term loan.

In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

In June 2015, Mississippi Power issued an 18-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposit in connection with the termination of the APA. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

 

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2015				2014				2015				2014
	(in millions)								(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	250			$	260			$	481			$	538
Wholesale revenues, affiliates	85				68				199				140
Other revenues	2				1				4				2
Total operating revenues	337				329				684				680
Operating Expenses:
Fuel	105				118				243				243
Purchased power, non-affiliates	18				17				34				45
Purchased power, affiliates	4				16				14				46
Other operations and maintenance	69				69				121				122
Depreciation and amortization	60				52				118				103
Taxes other than income taxes	6				6				12				11
Total operating expenses	262				278				542				570
Operating Income	75				51				142				110
Other Income and (Expense):
Interest expense, net of amounts capitalized	(23		)		(22		)		(45		)		(44		)
Other income (expense), net	1				—				1				—
Total other income and (expense)	(22		)		(22		)		(44		)		(44		)
Earnings Before Income Taxes	53				29				98				66
Income taxes (benefit)	1				(3		)		13				—
Net Income	52				32				85				66
Less: Net income attributable to noncontrolling interests	6				1				6				2
Net Income Attributable to Southern Power Company	$	46			$	31			$	79			$	64

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2015				2014				2015				2014
	(in millions)								(in millions)
Net Income	$	52			$	32			$	85			$	66
Other comprehensive income (loss)	—				—				—				—
Less: Comprehensive income attributable to noncontrolling interests	6				1				6				2
Comprehensive Income Attributable to Southern Power Company	$	46			$	31			$	79			$	64

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

	For the Six Months Ended June 30,
	2015				2014
	(in millions)
Operating Activities:
Net income	$	85			$	66
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	121				105
Deferred income taxes	59				(3		)
Investment tax credits	153				26
Amortization of investment tax credits	(10		)		(5		)
Deferred revenues	(21		)		(24		)
Accrued income taxes, non-current	100				—
Other, net	10				7
Changes in certain current assets and liabilities —
-Receivables	(26		)		(34		)
-Fossil fuel stock	5				(1		)
-Prepaid income taxes	(102		)		21
-Other current assets	—				(1		)
-Accounts payable	(31		)		24
-Accrued taxes	(110		)		7
-Other current liabilities	18				5
Net cash provided from operating activities	251				193
Investing Activities:
Plant acquisitions	(408		)		(213		)
Property additions	(154		)		(11		)
Change in construction payables	38				(3		)
Payments pursuant to long-term service agreements	(45		)		(23		)
Other investing activities	(1		)		(11		)
Net cash used for investing activities	(570		)		(261		)
Financing Activities:
Increase (decrease) in notes payable, net	(195		)		73
Proceeds — Senior notes	650				—
Distributions to noncontrolling interests	(1		)		—
Contributions from noncontrolling interests	78				7
Payment of common stock dividends	(65		)		(66		)
Other financing activities	(3		)		9
Net cash provided from financing activities	464				23
Net Change in Cash and Cash Equivalents	145				(45		)
Cash and Cash Equivalents at Beginning of Period	75				69
Cash and Cash Equivalents at End of Period	$	220			$	24
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $1 and $- capitalized for 2015 and 2014, respectively)	$	35			$	43
Income taxes, net	(72		)		(59		)
Noncash transactions — Accrued property additions at end of period	38				5

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

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

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2015 vs. SECOND QUARTER 2014

AND

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

OVERVIEW

Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.

During the six months ended June 30, 2015, Southern Power acquired approximately 353 MWs of additional solar facilities including the five Georgia construction projects located in Taylor and Butler Counties, as well as the Lost Hills, Blackwell, and North Star projects located in California. Southern Power also entered into an agreement to acquire an approximately 299-MW wind facility, located in Oklahoma, contingent upon certain construction and project milestones. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

Southern Power continues to focus on several key performance indicators. These indicators include peak season equivalent forced outage rate, contract availability, and net income. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$15		48.4		$15		23.4

Net income attributable to Southern Power for the second quarter 2015 was $46 million compared to $31 million for the corresponding period in 2014. The increase was primarily due to increased revenue and lower fuel and purchased power expenses.

Net income attributable to Southern Power for year-to-date 2015 was $79 million compared to $64 million for the corresponding period in 2014. The increase was primarily due to a decrease in purchased power expenses, partially offset by increases in depreciation and income taxes.

Wholesale Revenues – Non-Affiliates

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$(10)		(3.8)		$(57)		(10.6)

Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues under PPAs that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale revenues from non-affiliates for the second quarter 2015 were $250 million compared to $260 million for the corresponding period in 2014. The decrease was due to a $5 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and new solar PPAs. The decrease in energy revenues reflects a 14% decrease in the average price of energy, partially offset by a 12% increase in KWH sales. In addition, capacity revenues decreased $5 million primarily due to PPA expirations.

Wholesale revenues from non-affiliates for year-to-date 2015 were $481 million compared to $538 million for the corresponding period in 2014. The decrease was due to a $44 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumes and new solar PPAs. The decrease in energy revenues reflects a 17% decrease in the average price of energy, partially offset by a 5% increase in KWH sales. In addition, capacity revenues decreased $13 million primarily due to PPA expirations.

Wholesale Revenues – Affiliates

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$17		25.0		$59		42.1

Wholesale revenues from sales to affiliate companies will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC.

Wholesale revenues from affiliates for the second quarter 2015 were $85 million compared to $68 million for the corresponding period in 2014. The increase was the result of a $10 million increase in energy revenues and a $7 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 61% increase in KWH sales, partially offset by a 21% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.

Wholesale revenues from affiliates for year-to-date 2015 were $199 million compared to $140 million for the corresponding period in 2014. The increase was the result of a $50 million increase in energy revenues and a $9 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 110% increase in KWH sales, partially offset by a 22% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.

Fuel and Purchased Power Expenses

		Second Quarter 2015 vs. Second Quarter 2014						Year-to-Date 2015 vs. Year-to-Date 2014
		(change in millions)				(% change)		(change in millions)				(% change)
Fuel		$	(13	)		(11.0)		$	—			—
Purchased power – non-affiliates		1				5.9		(11		)		(24.4	)
Purchased power – affiliates		(12		)		(75.0)		(32		)		(69.6	)
Total fuel and purchased power expenses		$	(24	)				$	(43	)

Southern Power's PPAs for natural gas-fired generation generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in such fuel cost is generally

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

accompanied by an increase or decrease in related fuel revenues under the PPAs and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.

Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power Company, affiliate companies, or external parties.

In the second quarter 2015, total fuel and purchased power expenses were $127 million compared to $151 million for the corresponding period in 2014. The decrease was the result of a $58 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $34 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.

For year-to-date 2015, total fuel and purchased power expenses were $291 million compared to $334 million for the corresponding period in 2014. The decrease was a result of a $154 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $111 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.

Fuel

In the second quarter 2015, fuel expense was $105 million compared to $118 million for the corresponding period in 2014. The decrease was due to a 36.1% decrease associated with the average cost of natural gas per KWH generated, partially offset by a 40.6% increase associated with the volume of KWHs generated, primarily as a result of increased demand resulting from lower natural gas prices.

For year-to-date 2015 and for the corresponding period in 2014, fuel expense was $243 million. While there was no overall change, a $152 million increase in the total cost of fuel attributable to the volume of KWHs generated was offset by a $152 million decrease in the average cost of natural gas per KWH generated.

Purchased Power – Non-Affiliates and Affiliates

In the second quarter 2015, purchased power expense was $22 million compared to $33 million for the corresponding period in 2014. For year-to-date 2015, purchased power expense was $48 million compared to $91 million for the corresponding period in 2014. The decreases were primarily the result of 37.4% and 45.6% decreases in the volume of KWHs purchased in the second quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices which resulted in higher use of Southern Power Company's generation resources.

Other Operations and Maintenance Expenses

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$—		—		$(1)		(0.8)

In the second quarter 2015 and for the corresponding period in 2014, other operations and maintenance expenses were $69 million. While there was no overall change, a decrease in outage expense of $10 million was offset by a $10 million increase in expenses associated with support services, transmission, and new plants placed in service in 2014 and 2015.

For year-to-date 2015, other operations and maintenance expenses were $121 million compared to $122 million for the corresponding period in 2014. The decrease was primarily due to a $17 million decrease in outage expense,

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largely offset by a $16 million increase in expenses associated with support services, new plants placed in service in 2014 and 2015, and transmission.

Depreciation and Amortization

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$8		15.4		$15		14.6

In the second quarter 2015, depreciation and amortization was $60 million compared to $52 million for the corresponding period in 2014. For year-to-date 2015, depreciation and amortization was $118 million compared to $103 million for the corresponding period in 2014. The increases were primarily related to solar facilities placed in service in 2014 and 2015.

Income Taxes (Benefit)

Second Quarter 2015 vs. Second Quarter 2014				Year-to-Date 2015 vs. Year-to-Date 2014
(change in millions)		(% change)		(change in millions)		(% change)
$4		133.3		$13		N/M

N/M – Not meaningful

In the second quarter 2015, income taxes were $1 million compared to an income tax benefit of $3 million for the corresponding period in 2014. For year-to-date 2015, income taxes were $13 million. The increases were primarily due to higher pre-tax earnings in 2015 and beneficial state income tax changes in 2014, partially offset by increased federal income tax benefits related to ITCs in 2015.

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

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy, including successfully expanding investments in renewable energy projects, and to construct generating facilities, including the impact of federal ITCs.

Other factors that could influence future earnings include weather, demand, cost of generating units within the power pool, and operational limitations. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

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Air Quality

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

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

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

Global Climate Issues

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

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

Acquisitions

During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy, which are included in Southern Power's capital program estimates for 2015.

Kay County Wind Facility

On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on

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performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

Lost Hills-Blackwell Solar Facilities

On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years.

North Star Solar Facility

On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately 61-MW North Star solar facility in Fresno County, California. The solar facility began commercial operation on June 20, 2015, and the entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company.

Construction Projects

In December 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of five separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this time.

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Southern Power Company's construction projects are detailed in the table below:

Solar Project

Seller

Nameplate Capacity

County Location in Georgia

Expected Commercial Operation Date

PPA Counterparty for Entire Plant Output

PPA Contract Period

Estimated Construction Cost

(MW)

(in millions)

Taylor County

N/A

146

Taylor

Fourth quarter 2016

Cobb, Flint, and Sawnee Electric Membership Corporations

25 years

$

260

-

$280

Decatur Parkway

TradeWind Energy, Inc.

84

Decatur

December 2015

Georgia Power(a)

25 years

$

170

-

$173

(b)

Decatur County

TradeWind Energy, Inc.

20

Decatur

December 2015

Georgia Power(a)

20 years

$

45

-

$47

(b)

Butler

CERSM, LLC and Community Energy, Inc.

103

Taylor

December 2016

Georgia Power(a)

30 years

$

220

-

$230

(b)

Pawpaw

Longview Solar, LLC

30

Taylor

December 2015

Georgia Power(a)

30 years

$

70

-

$80

(b)

Butler Solar Farm

Strata Solar Development, LLC

20

Taylor

December 2015

Georgia Power(a)

20 years

$

42

-

$48

(b)

(a) Subject to FERC approval.

(b) Includes the acquisition price of all outstanding membership interests.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

Power Sales Agreements

See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.

Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern Power's existing fleet, the coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of June 30, 2015 from the period ended December 31, 2014.

FERC Matters

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

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Other Matters

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.

Recently Issued Accounting Standards

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

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU has not yet been determined.

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

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FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at June 30, 2015. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.

Net cash provided from operating activities totaled $251 million for the first six months of 2015, compared to $193 million for the first six months of 2014. The increase in cash provided from operating activities was primarily due to lower purchased power costs and an increase in income tax benefits received. Net cash used for investing activities totaled $570 million for the first six months of 2015 primarily due to the Lost Hills, Blackwell, and North Star acquisitions and expenditures related to the construction of new solar facilities. Net cash provided from financing activities totaled $464 million for the first six months of 2015 primarily due to the issuance of additional senior notes in May 2015. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2015 include a $300 million increase in plant in service, net of depreciation primarily due to the Lost Hills, Blackwell, and North Star acquisitions and a $190 million increase in CWIP primarily due to the construction of new solar facilities. Other significant changes include an increase in long-term debt of $642 million primarily as a result of the issuance of senior notes in May 2015.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. Subsequent to June 30, 2015, $525 million of long-term debt was repaid at maturity. There are no other scheduled maturities of long-term debt through June 30, 2016.

The capital program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to be approximately $1.4 billion for 2015, which includes approximately $1.3 billion for acquisitions and/or construction of new generating facilities. See Note (I) to the Condensed Financial Statements herein for additional information. Actual capital costs may vary from these estimates because of changes in factors such as business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

Sources of Capital

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

Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. In 2015, Southern Power has utilized the capital markets to issue additional senior notes and expects to utilize the capital

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markets, bank term loans, and commercial paper markets, as the source of funds for the majority of its maturities and to meet short-term liquidity needs, including funding acquisition and construction costs.

To meet liquidity and capital resource requirements, Southern Power had at June 30, 2015 cash and cash equivalents of approximately $220 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $466 million is unused.

The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power Company is currently in compliance with all covenants in the Facility.

Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power Company's commercial paper program. Subject to applicable market conditions, Southern Power Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

Southern Power Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Subsequent to June 30, 2015, commercial paper was used to partially fund the maturity of long-term debt in July 2015.

Details of short-term borrowings were as follows:

		Commercial Paper at the End of the Period							Commercial Paper During the Period(*)
		Amount Outstanding				Weighted Average Interest Rate			Average Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
		(in millions)							(in millions)							(in millions)
June 30, 2015:		$	—			—	%		$	163			0.6	%		$	339

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

Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and operating cash flows.

Credit Rating Risk

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

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	320
Below BBB- and/or Baa3	1,081

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

In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.

Financing Activities

In May 2015, Southern Power Company issued $350 million aggregate principal amount of Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS

Note		Page Number
A	Introduction	150
B	Contingencies and Regulatory Matters	152
C	Fair Value Measurements	168
D	Stockholders' Equity	173
E	Financing	175
F	Retirement Benefits	177
G	Income Taxes	180
H	Derivatives	181
I	Acquisitions	190
J	Segment and Related Information	193

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.

Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I, J
Alabama Power	A, B, C, E, F, G, H
Georgia Power	A, B, C, E, F, G, H
Gulf Power	A, B, C, E, F, G, H
Mississippi Power	A, B, C, E, F, G, H
Southern Power	A, B, C, D, E, G, H, I

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(UNAUDITED)

(A)	INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2014 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2015 and 2014. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. In March 2015, in connection with this retirement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.

In June 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error, as well as the current period. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.

Recently Issued Accounting Standards

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.

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

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new asset retirement obligations (ARO) for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates.

As of June 30, 2015, details of the AROs, including those related to the CCR Rule, included in Southern Company's and the traditional operating companies' Condensed Balance Sheets herein were as follows:

	Southern Company						Alabama Power						Georgia Power						Gulf Power						Mississippi Power
	(in millions)
Balance at beginning of year	$	2,201					$	829					$	1,255					$	17					$	48
Liabilities incurred	612						401						—						71						97
Liabilities settled	(10				)		(1				)		(9				)		—						—
Accretion	53						23						28						—						1
Cash flow revisions	58						—						82						4						2
Balance at end of period	$	2,914					$	1,252					$	1,356					$	92					$	148

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

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

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(B)	CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

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

Environmental Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions sought penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) was partially settled in 2006 through a consent decree with the EPA, and additional claims remain pending in the U.S. District Court for the Northern District of Alabama. On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case against Alabama Power. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.

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

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of June 30, 2015 was $40 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act

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(CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.

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

In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In 2013, the U.S. District Court for the Eastern District of North Carolina Western Division ruled that Georgia Power has no liability in the private action and, on March 20, 2015, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court's ruling. Therefore, the private action is now concluded.

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

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $47 million as of June 30, 2015. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

In 2003, Mississippi Power and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers. The TCEQ approved the final site remediation plan in 2013 and, in March 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability was $0.3 million as of June 30, 2015 and is expected to be recovered through the ECO Plan.

The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

Nuclear Fuel Disposal Cost Litigation

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

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In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. The judgment amounts were paid on March 19, 2015. In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. The final outcome of this matter for Alabama Power cannot be determined at this time; however, no material impact on Southern Company's or Alabama Power's net income is expected as the damage amounts collected from the government are expected to be used for the benefit of customers.

In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of June 30, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

FERC Matters

Municipal and Rural Associations Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.

On March 31, 2015, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgo the Municipal and Rural Associations cost-based electric tariff increase reflected in the filing by, among other things, increasing the accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, which was accepted by the FERC on May 13, 2015, provides that the additional accrual of AFUDC was effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $11 million annually, of which $8 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.

Market-Based Rate Authority

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

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for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The recovery balance of each regulatory clause follows:

Regulatory Clause		Balance Sheet Line Item	June 30, 2015				December 31, 2014
			(in millions)
Rate CNP Compliance – Under*		Deferred under recovered regulatory clause revenues	$	25			$	2
		Under recovered regulatory clause revenues, current	29				47
Rate CNP PPA – Under		Deferred under recovered regulatory clause revenues	72				29
		Under recovered regulatory clause revenues, current	—				27
Retail Energy Cost Recovery – Over		Deferred over recovered regulatory clause revenues	72				47
Natural Disaster Reserve		Other regulatory liabilities, deferred	81				84

* Formerly Known As Rate CNP Environmental

Rate CNP

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

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

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

Environmental Accounting Order

In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Subject to the final approval of the New Source Review stipulation, Alabama Power will also

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retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See "Environmental Matters – New Source Review Actions" herein for additional information regarding the NSR actions.

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

Georgia Power

Integrated Resource Plan

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

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

Fuel Cost Recovery

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

As of June 30, 2015 and December 31, 2014, Georgia Power's under recovered fuel balance totaled $106 million and $199 million, respectively. For June 30, 2015 and December 31, 2014, the balance is included in current assets and current assets and other deferred charges and assets, respectively, on Southern Company's and Georgia Power's Condensed Balance Sheets herein. Georgia Power expects to file its next fuel case in September 2015. The ultimate outcome of this matter cannot be determined at this time.

Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, and pending litigation.

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to

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Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.

Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million in 2008 dollars (approximately $591 million in 2015 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor subsequently asserted estimated minimum damages related to the amended counterclaim (based on Georgia Power's ownership interest) of approximately $113 million in 2014 dollars (approximately $118 million in 2015 dollars). In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.

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Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Georgia Power's eighth VCM report filed in 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.

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

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

On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month Contractor delay, and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion.

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

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

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of

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such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

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

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

Gulf Power

Retail Base Rate Case

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

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

Cost Recovery Clauses

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The recovery balance of each regulatory clause follows:

Recovery Clause		Balance Sheet Location		June 30, 2015				December 31, 2014
				(in millions)
Fuel Cost Recovery – Under		Under recovered regulatory clause revenues		$	24			$	40
Purchased Power Capacity Recovery – Under		Under recovered regulatory clause revenues		2				—
Environmental Cost Recovery – Under		Under recovered regulatory clause revenues		7				10
Energy Conservation Cost Recovery – Under		Under recovered regulatory clause revenues		—				3

Mississippi Power

2015 Rate Case

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

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(UNAUDITED)

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

On March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow it more time for review. The ultimate outcome of this matter cannot be determined at this time.

System Restoration Rider

See Note 1 to the financial statements of Mississippi Power under "Provision for Property Damage" in Item 8 of the Form 10-K for additional information.

On February 2, 2015, Mississippi Power submitted its 2015 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2015 SRR rate remain level at zero and Mississippi Power be allowed to accrue $3 million to the property damage reserve in 2015. On March 3, 2015, the Mississippi PSC suspended the filing to allow it more time for review. The ultimate outcome of this matter cannot be determined at this time.

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" and "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC and information on Plant Watson Units 4 and 5.

In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which are scheduled to be placed in service in September and November 2015, respectively. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of June 30, 2015, total project expenditures were $604 million, of which Mississippi Power's portion was $308 million, excluding AFUDC of $27 million.

On February 25, 2015, Mississippi Power submitted its annual ECO filing for 2015, which indicated an annual increase in revenues of approximately $8 million. On February 27, 2015, the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.

On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million excluding the reserve for cost of removal and has been reclassified to other regulatory assets, deferred, on Mississippi Power's Condensed Balance Sheet herein in accordance with an accounting order from the Mississippi PSC. Mississippi Power expects to recover through its rates the remaining book value of the retired assets and certain costs, including unusable inventory, associated with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.

Fuel Cost Recovery

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

At June 30, 2015, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $24 million compared to under-recovered retail fuel costs of $2 million at December 31, 2014.

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Ad Valorem Tax Adjustment

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information.

On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates. On May 26, 2015 the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO₂ pipeline infrastructure for the planned transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the Kemper IGCC costs subject to the cost cap and the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of June 30, 2015, as adjusted for the Court's decision, are as follows:

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Cost Category	2010 Project Estimate(f)				Current Estimate				Actual Costs at June 30, 2015
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40			$	4.96			$	4.51
Lignite Mine and Equipment	0.21				0.23				0.23
CO2 Pipeline Facilities	0.14				0.11				0.11
AFUDC(b)(c)	0.17				0.62				0.52
Combined Cycle and Related Assets Placed in Service – Incremental(d)	—				0.02				—
General Exceptions	0.05				0.10				0.08
Deferred Costs(c)(e)	—				0.19				0.15
Total Kemper IGCC(a)(c)	$	2.97			$	6.23			$	5.60

(a)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. The Current Estimate and Actual Costs include the 15% undivided interest in the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the asset purchase agreement (APA) and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.

(b)

Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(c)	Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

(d)	Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.

(e)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

(f)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2015, $3.42 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.08 billion), $2 million in other property and investments, $58 million in fossil fuel stock, $41 million in materials and supplies, $198 million in other regulatory assets, $16 million in other deferred charges and assets, and $24 million in AROs in the balance sheet, with $1 million previously expensed.

Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23 million ($14 million after tax) in the second quarter 2015 and $9 million ($6 million after tax) in the first quarter 2015. These amounts are in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $868 million ($536 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively. The increases to the cost estimate in the first and second quarters of 2015 primarily reflected costs for increased efforts related to equipment rework, scope modifications, and the related additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up

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and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month.

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

Rate Recovery of Kemper IGCC Costs

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 2015 Rate Case and any alternative proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power's

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intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC through the in-service date until directed to do otherwise by the Mississippi PSC.

In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.

In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Southern Company and Mississippi Power.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.

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2015 Rate Case

As a result of the 2015 Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On May 15, 2015, Mississippi Power sought alternate rate recovery and filed a rate case (2015 Rate Case) with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.

On July 10, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (the Supplemental Notice) with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presents an additional alternative rate proposal (In-Service Asset Proposal) for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and is designed to collect approximately $159 million annually. The Supplemental Notice requests that the In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time as the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.

The revenue requirements set forth in the alternative rate proposals exclude the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

If the Mississippi PSC does not act on the Supplemental Notice or the 2015 Rate Case within 120 days of the Supplemental Notice filing, Mississippi Power expects to put one of the three viable alternative rate proposals into effect as temporary rates under bond and subject to refund pursuant to Mississippi state law.

Mississippi Power also expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 2015 of $6.23 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental

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Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expects the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not required for interim rate relief to be granted. See "2015 Mississippi Supreme Court Decision" and "2015 Rate Case" herein for additional information.

Regulatory Assets and Liabilities

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of June 30, 2015, the regulatory asset balance associated with the Kemper IGCC was $198 million. The projected balance at March 31, 2016 is estimated to total approximately $276 million. The amortization period for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

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

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

Lignite Mine and CO₂ Pipeline Facilities

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

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

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO₂ delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not

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affect pricing or minimum purchase quantities. Any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

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

Termination of Proposed Sale of Undivided Interest to SMEPA

In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and SMEPA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.

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 June 30, 2015, Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $242 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. The ultimate outcome of this matter cannot be determined at this time.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. 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 and Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Southern Company and Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Note (G) herein under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

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(C)	FAIR VALUE MEASUREMENTS

As of June 30, 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, were as follows:

		Fair Value Measurements Using
As of June 30, 2015:		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
		(in millions)
Southern Company
Assets:
Energy-related derivatives		$	—			$	5			$	—			$	5
Interest rate derivatives		—				11				—				11
Nuclear decommissioning trusts(a)		677				887				7				1,571
Cash equivalents		533				—				—				533
Other investments		9				—				1				10
Total		$	1,219			$	903			$	8			$	2,130
Liabilities:
Energy-related derivatives		$	—			$	180			$	—			$	180
Interest rate derivatives		—				14				—				14
Total		$	—			$	194			$	—			$	194
Alabama Power
Assets:
Energy-related derivatives		$	—			$	2			$	—			$	2
Nuclear decommissioning trusts(b)
Domestic equity		381				78				—				459
Foreign equity		51				50				—				101
U.S. Treasury and government agency securities		—				36				—				36
Corporate bonds		10				121				—				131
Mortgage and asset backed securities		—				17				—				17
Other		—				6				7				13
Cash equivalents		81				—				—				81
Total		$	523			$	310			$	7			$	840
Liabilities:
Energy-related derivatives		$	—			$	48			$	—			$	48
Interest rate derivatives		—				7				—				7
Total		$	—			$	55			$	—			$	55

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		Fair Value Measurements Using
As of June 30, 2015:		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
		(in millions)
Georgia Power
Assets:
Energy-related derivatives		$	—			$	3			$	—			$	3
Interest rate derivatives		—				5				—				5
Nuclear decommissioning trusts(b) (c)
Domestic equity		182				1				—				183
Foreign equity		—				125				—				125
U.S. Treasury and government agency securities		—				95				—				95
Municipal bonds		—				78				—				78
Corporate bonds		—				169				—				169
Mortgage and asset backed securities		—				108				—				108
Other		53				3				—				56
Total		$	235			$	587			$	—			$	822
Liabilities:
Energy-related derivatives		$	—			$	17			$	—			$	17
Interest rate derivatives		—				4				—				4
Total		$	—			$	21			$	—			$	21
Gulf Power
Assets:
Cash equivalents		$	18			$	—			$	—			$	18
Liabilities:
Energy-related derivatives		—				74				—				74
Mississippi Power
Assets:
Cash equivalents		$	182			$	—			$	—			$	182
Liabilities:
Energy-related derivatives		—				41				—				41
Southern Power
Assets:
Cash equivalents		$	206			$	—			$	—			$	206

(a)	For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(b)	Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(c)	Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2015, approximately $39 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

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Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter financial products 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. 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, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgment, are also obtained when available.

Investments in private equity and real estate within Alabama Power's nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

"Other investments" include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

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As of June 30, 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 June 30, 2015:		Fair Value				Unfunded Commitments		Redemption Frequency		Redemption Notice Period
		(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds		$	125			None		Monthly		5 days
Equity - commingled funds		50				None		Daily		Daily
Debt - commingled funds		16				None		Daily		5 days
Other - commingled funds		3				None		Daily		Not applicable
Other - money market funds		53				None		Daily		Not applicable
Trust-owned life insurance		117				None		Daily		15 days
Cash equivalents:
Money market funds		533				None		Daily		Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds		$	50			None		Daily		Daily
Debt - commingled funds		16				None		Daily		5 days
Trust-owned life insurance		117				None		Daily		15 days
Cash equivalents:
Money market funds		81				None		Daily		Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds		$	125			None		Monthly		5 days
Other - commingled funds		3				None		Daily		Not applicable
Other - money market funds		53				None		Daily		Not applicable
Gulf Power
Cash equivalents:
Money market funds		$	18			None		Daily		Not applicable
Mississippi Power
Cash equivalents:
Money market funds		$	182			None		Daily		Not applicable
Southern Power
Cash equivalents:
Money market funds		$	206			None		Daily		Not applicable

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts (including American depositary receipts, European depositary receipts, and global depositary receipts), and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to

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

The other-commingled funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio of high-quality, short-term, liquid debt securities. The funds represent cash collateral received under the Funds' managers' securities lending program and/or excess cash held within each separate investment account. The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or less. Redemptions are available on a same day basis up to the full amount of the investment in the fund. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Alabama Power's nuclear decommissioning trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not 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. These commingled funds, along with other equity and debt commingled funds held in Alabama Power's nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three and six months ended June 30, 2015, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $44 million and $109 million, respectively, at Southern Company. For the three and six months ended June 30, 2015, Alabama Power recorded an increase in fair value of $50 million and $97 million, respectively, as an increase in regulatory liabilities. For the three and six months ended June 30, 2015, Georgia Power recorded a decrease in fair value of $6 million and an increase of $12 million, respectively, as a reduction of its regulatory asset related to its ARO.

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.

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As of June 30, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

		Carrying Amount				Fair Value
		(in millions)
Long-term debt, including securities due within one year:
Southern Company		$	26,156			$	26,973
Alabama Power		$	7,295			$	7,621
Georgia Power		$	10,379			$	10,767
Gulf Power		$	1,370			$	1,438
Mississippi Power		$	2,275			$	2,246
Southern Power		$	2,262			$	2,302

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the registrants.

(D)	STOCKHOLDERS' EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

		Three Months Ended June 30, 2015			Three Months Ended June 30, 2014			Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
		(in millions)
As reported shares		909			895			910			892
Effect of options and performance share award units		3			4			4			4
Diluted shares		912			899			914			896

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 15 million and 1 million for the three and six months ended June 30, 2015, respectively, and were 8 million and 17 million for the three and six months ended June 30, 2014, respectively.

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Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:

	Number of Common Shares						Common Stockholders' Equity				Preferred and Preference Stock of Subsidiaries								Total Stockholders' Equity
	Issued			Treasury											Noncontrolling Interest(*)
	(in thousands)						(in millions)
Balance at December 31, 2014	908,502			(725	)		$	19,949			$	756			$	221			$	20,926
Net income after dividends on preferred and preference stock	—			—			1,138				—				—				1,138
Other comprehensive income (loss)	—			—			7				—				—				7
Stock issued	3,222			—			117				—				—				117
Stock-based compensation	—			—			66				—				—				66
Stock repurchased, at cost	—			(2,599	)		(115		)		—				—				(115		)
Cash dividends on common stock	—			—			(972		)		—				—				(972		)
Preference stock redemption	—			—			—				(150		)		—				(150		)
Contributions from noncontrolling interest	—			—			—				—				135				135
Distributions to noncontrolling interest	—			—			—				—				(5		)		(5		)
Net income attributable to noncontrolling interest	—			—			—				—				4				4
Other	—			25			(8		)		3				—				(5		)
Balance at June 30, 2015	911,724			(3,299	)		$	20,182			$	609			$	355			$	21,146
Balance at December 31, 2013	892,733			(5,647	)		$	19,008			$	756			$	—			$	19,764
Net income after dividends on preferred and preference stock	—			—			962				—				—				962
Other comprehensive income (loss)	—			—			4				—				—				4
Treasury stock re-issued	—			4,739			216				—				—				216
Stock issued	3,898			—			161				—				—				161
Stock repurchased, at cost	—			—			(5		)		—				—				(5		)
Cash dividends on common stock	—			—			(920		)		—				—				(920		)
Other	—			(27	)		—				—				—				—
Balance at June 30, 2014	896,631			(935	)		$	19,426			$	756			$	—			$	20,182

(*) Primarily related to Southern Power Company.

Stock Repurchased

On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through June 30, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market

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purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.

(E)	FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $1.9 billion (comprised of approximately $810 million at Alabama Power, $970 million at Georgia Power, $69 million at Gulf Power, and $40 million at Mississippi Power). In addition, at June 30, 2015, the traditional operating companies had approximately $368 million (comprised of approximately $200 million at Alabama Power, $122 million at Georgia Power, and $46 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information. See "Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of June 30, 2015:

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

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

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Financing Activities

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

Company(a)	Senior Note Issuances				Senior Note Redemptions				Revenue Bond Issuances and Reofferings of Purchased Bonds(b)				Revenue Bond Maturities and Repurchases				Other Long-Term Debt Issuances				Other Long-Term Debt Redemptions and Maturities(c)
	(in millions)
Southern Company	$	600			$	—			$	—			$	—			$	—			$	—
Alabama Power	975				250				80				134				—				—
Georgia Power	—				125				170				65				600				5
Mississippi Power	—				—				—				—				—				351
Southern Power	650				—				—				—				—				—
Other	—				—				—				—				—				9
Total	$	2,225			$	375			$	250			$	199			$	600			$	365

(a)	Gulf Power did not issue or redeem any long-term debt during the first six months of 2015.

(b)	Includes reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds previously purchased and held by Alabama Power since April 2015 and reofferings by Georgia Power of $104.6 million and $65 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2013 and April 2015, respectively.

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

Southern Company

In June 2015, Southern Company issued $600 million aggregate principal amount of Series 2015A 2.750% Senior Notes due June 15, 2020. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.

Alabama Power

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

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

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

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Georgia Power

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

In June 2015, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million. The interest rate applicable to the $600 million principal amount is 3.283% for an interest period that extends to 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 4. Georgia Power settled $350 million of interest rate swaps related to this borrowing for approximately $6 million, which will be amortized to interest expense over 10 years.

Mississippi Power

In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

In June 2015, Mississippi Power issued an 18-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposit in connection with the termination of the APA. See Note (B) 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 repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including Southern Power's growth strategy and continuous construction program, and for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.

(F)	RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

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Components of the net periodic benefit costs for the three and six months ended June 30, 2015 and 2014 were as follows:

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

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

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(G)	INCOME TAXES

Current and Deferred Income Taxes

State of Georgia Tax Benefits

During the second quarter 2015, an agreement was reached with the Georgia Department of Revenue that will allow Southern Company to utilize a net operating loss carryforward over a four-year period beginning in 2017. Consequently, Southern Company reversed the related valuation allowance and recognized approximately $24 million in net tax benefits as of June 30, 2015. See Note 5 to the financial statements of Southern Company under "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.

Southern Power ITC Carryforwards

Southern Power had federal ITC carryforwards which are expected to result in $428 million of federal income tax benefits as of June 30, 2015, compared to $305 million as of December 31, 2014. The carryforwards as of June 30, 2015 expire between 2031 and 2035 and are expected to be utilized by the end of 2016.

Effective Tax Rate

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Mississippi Power

Mississippi Power's effective tax rate was 19.0% for the six months ended June 30, 2015 compared to (51.1)% for the corresponding period in 2014. The increase was primarily due to higher net income, partially offset by a decrease in non-taxable AFUDC equity related to the construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was 13.7% for the six months ended June 30, 2015 compared to 0.3% for the corresponding period in 2014. The increase was primarily due to beneficial changes that impacted 2014 state income taxes, which were partially offset by increased federal income tax benefits related to ITCs in the current year.

Unrecognized Tax Benefits

See Note 5 to the financial statements of Southern Company under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.

Changes during 2015 for unrecognized tax benefits were as follows:

	Mississippi Power				Southern Power				Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2014	$	165			$	5			$	170
Tax positions from current periods	—				2				2
Tax positions from prior periods	230				—				231
Reductions due to settlements	(5		)		—				(5		)
Balance as of June 30, 2015	$	390			$	7			$	398

The tax positions from prior periods relate primarily to 2008 through 2013 amended federal income tax returns that were filed to include deductions for Kemper IGCC-related R&E expenditures. See "Section 174 Research and Experimental Deduction" herein for additional information.

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The impact on the effective tax rate, if recognized, was as follows:

	As of June 30, 2015												As of December 31, 2014
	Mississippi Power				Southern Power				Southern Company				Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	—			$	7			$	8			$	10
Tax positions not impacting the effective tax rate	390				—				390				160
Balance of unrecognized tax benefits	$	390			$	7			$	398			$	170

The tax positions impacting the effective tax rate primarily relate to federal income tax benefits related to ITCs. The tax positions not impacting the effective tax rate relate to deductions for Kemper IGCC-related R&E expenditures. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Section 174 Research and Experimental Deduction

Southern Company reduced tax payments for 2014, and included in its 2013 consolidated federal income tax return deductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures.

The Kemper IGCC is based on first-of-a-kind technology, and Mississippi Power and Southern Company believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position, Mississippi Power and Southern Company had related unrecognized tax benefits associated with these R&E deductions of approximately $390 million and associated interest of $5 million as of June 30, 2015.

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

(H)	DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note (C) herein for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel

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prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for under one of three methods:

•

Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

•	Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges which 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.

At June 30, 2015, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

		Net Purchased mmBtu		Longest Hedge Date		Longest Non-Hedge Date
		(in millions)
Southern Company		220		2020		2017
Alabama Power		49		2018		—
Georgia Power		47		2017		—
Gulf Power		80		2020		—
Mississippi Power		43		2018		—
Southern Power		1		2015		2017

In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 5 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 3 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 June 30, 2016 are immaterial for all registrants.

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Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.

At June 30, 2015, the following interest rate derivatives were outstanding:

		Notional Amount				Interest Rate Received		Weighted Average Interest Rate Paid		Hedge Maturity Date		Fair Value Gain (Loss) at June 30, 2015
		(in millions)										(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power		$	200			3-month LIBOR		2.93%		October 2025		$	(7	)
Georgia Power		350				3-month LIBOR		2.57%		November 2025		(1		)
Cash Flow Hedges of Existing Debt
Georgia Power		250				3-month LIBOR + 0.32%		0.75%		March 2016		—
Georgia Power		200				3-month LIBOR + 0.40%		1.01%		August 2016		—
Fair Value Hedges on Existing Debt
Southern Company		250				1.30%		3-month LIBOR + 0.17%		August 2017		2
Southern Company		300				2.75%		3-month LIBOR + 0.92%		June 2020		1
Georgia Power		250				5.40%		3-month LIBOR + 4.02%		June 2018		1
Georgia Power		200				4.25%		3-month LIBOR + 2.46%		December 2019		1
Total		$	2,000									$	(3	)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 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.

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Derivative Financial Statement Presentation and Amounts

At June 30, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 2015
		Fair Value
Derivative Category and Balance Sheet Location		Southern Company				Alabama Power				Georgia Power				Gulf Power				Mississippi Power				Southern Power
		(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets		$	5			$	2			$	3			$	—			$	—			N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets		$	11			$	—			$	5			$	—			$	—			$	—
Total asset derivatives		$	16			$	2			$	8			$	—			$	—			$	—

Liability Derivatives at June 30, 2015
		Fair Value
Derivative Category and Balance Sheet Location		Southern Company				Alabama Power				Georgia Power				Gulf Power				Mississippi Power				Southern Power
		(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current liabilities(*)		$	99			$	31			$	15			$	32			$	21
Other deferred credits and liabilities		81				17				2				42				20
Total derivatives designated as hedging instruments for regulatory purposes		$	180			$	48			$	17			$	74			$	41			N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities(*)		$	8			$	7			$	1			$	—			$	—			$	—
Other deferred credits and liabilities		6				—				3				—				—				—
Total derivatives designed as hedging instruments in cash flow and fair value hedges		$	14			$	7			$	4			$	—			$	—			$	—
Total liability derivatives		$	194			$	55			$	21			$	74			$	41			$	—

(*) Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

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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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Liability Derivatives at December 31, 2014
		Fair Value
Derivative Category and Balance Sheet Location		Southern Company				Alabama Power				Georgia Power				Gulf Power				Mississippi Power				Southern Power
		(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current liabilities(*)		$	118			$	32			$	23			$	37			$	26
Other deferred credits and liabilities		79				21				4				35				19
Total derivatives designated as hedging instruments for regulatory purposes		$	197			$	53			$	27			$	72			$	45			N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities(*)		$	17			$	8			$	9			$	—			$	—			$	—
Other deferred credits and liabilities		7				—				5				—				—				—
Total derivatives designated as hedging instruments in cash flow and fair value hedges		$	24			$	8			$	14			$	—			$	—			$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities		$	4			$	—			$	—			$	—			$	—			$	4
Total liability derivatives		$	225			$	61			$	41			$	72			$	45			$	4

(*) Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

The derivative contracts of Southern Company, the traditional operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and are reported gross on each registrant's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at June 30, 2015 and December 31, 2014 are presented in the following tables.

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Derivative Contracts at June 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)		$	5			$	2			$	3			$	—			$	—			$	—
Gross amounts not offset in the Balance Sheet (b)		(5		)		(2		)		(3		)		—				—				—
Net energy-related derivative assets		$	—			$	—			$	—			$	—			$	—			$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)		$	11			$	—			$	5			$	—			$	—			$	—
Gross amounts not offset in the Balance Sheet (b)		(8		)		—				(3		)		—				—				—
Net interest rate derivative assets		$	3			$	—			$	2			$	—			$	—			$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)		$	180			$	48			$	17			$	74			$	41			$	—
Gross amounts not offset in the Balance Sheet (b)		(5		)		(2		)		(3		)		—				—				—
Net energy-related derivative liabilities		$	175			$	46			$	14			$	74			$	41			$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)		$	14			$	7			$	4			$	—			$	—			$	—
Gross amounts not offset in the Balance Sheet (b)		(8		)		—				(3		)		—				—				—
Net interest rate derivative liabilities		$	6			$	7			$	1			$	—			$	—			$	—

(a) None of the registrants 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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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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At June 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 June 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		$	(99	)		$	(31	)		$	(15	)		$	(32	)		$	(21	)
Other regulatory assets, deferred		(81		)		(17		)		(2		)		(42		)		(20		)
Other regulatory liabilities, current (a)		5				2				3				—				—
Other regulatory liabilities, deferred (b)		—				—				—				—				—
Total energy-related derivative gains (losses)		$	(175	)		$	(46	)		$	(14	)		$	(74	)		$	(41	)

(a) Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2014
Derivative Category and Balance Sheet Location		Southern Company				Alabama Power				Georgia Power				Gulf Power				Mississippi Power
		(in millions)
Energy-related derivatives:
Other regulatory assets, current		$	(118	)		$	(32	)		$	(23	)		$	(37	)		$	(26	)
Other regulatory assets, deferred		(79		)		(21		)		(4		)		(35		)		(19		)
Other regulatory liabilities, current (a)		7				1				6				—				—
Other regulatory liabilities, deferred (b)		—				—				1				—				—
Total energy-related derivative gains (losses)		$	(190	)		$	(52	)		$	(20	)		$	(72	)		$	(45	)

(a) Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

For the three months ended June 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

Derivatives in Cash Flow Hedging Relationships		Gain (Loss) Recognized in OCI on Derivative (Effective Portion)								Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
										Statements of Income Location		Amount
		2015				2014						2015				2014
		(in millions)										(in millions)
Southern Company
Interest rate derivatives		$	31			$	—			Interest expense, net of amounts capitalized		$	(2	)		$	(2	)
Alabama Power
Interest rate derivatives		$	7			$	—			Interest expense, net of amounts capitalized		$	(1	)		$	—
Georgia Power
Interest rate derivatives		$	24			$	—			Interest expense, net of amounts capitalized		$	(1	)		$	—
Mississippi Power
Interest rate derivatives		$	—			$	—			Interest expense, net of amounts capitalized		$	—			$	(1	)
Southern Power
Interest rate derivatives		$	—			$	—			Interest expense, net of amounts capitalized		$	—			$	(1	)

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For the six months ended June 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

For the three and six months ended June 30, 2015 and 2014, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

For the three and six months ended June 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three and six months ended June 30, 2015 and 2014, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all registrants.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2015, the registrants' collateral posted with their derivative counterparties was immaterial.

At June 30, 2015, the fair value of derivative liabilities with contingent features was $49 million for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $49 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

(I)	ACQUISITIONS

See Note 2 to the financial statements of Southern Power under "2014 – SG2 Imperial 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.

During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy. Acquisition-related costs were expensed as incurred and were not material.

Kay County Wind Facility

On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time.

Lost Hills-Blackwell Solar Facilities

On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years. As of June 30, 2015, the fair values of the assets acquired 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 been finalized. The acquisition did not include any contingent consideration.

North Star Solar Facility

On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately 61-MW North Star solar facility in Fresno County, California. The solar facility began commercial operation on June 20, 2015, and the entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company. As of June 30, 2015, the fair values of the assets acquired were recorded as follows: $266 million as property, plant, and equipment, $24 million as an intangible asset, and $21 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration.

Construction Projects

In December 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of five separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power Company's construction projects are detailed in the table below:

Solar Project

Seller

Nameplate Capacity

County Location in Georgia

Expected Commercial Operation Date

PPA Counterparty for Entire Plant Output

PPA Contract Period

Estimated Construction Cost

(MW)

(in millions)

Taylor County

N/A

146

Taylor

Fourth quarter 2016

Cobb, Flint, and Sawnee Electric Membership Corporations

25 years

$

260

-

$280

Decatur Parkway

TradeWind Energy, Inc.

84

Decatur

December 2015

Georgia Power(a)

25 years

$

170

-

$173

(b)

Decatur County

TradeWind Energy, Inc.

20

Decatur

December 2015

Georgia Power(a)

20 years

$

45

-

$47

(b)

Butler

CERSM, LLC and Community Energy, Inc.

103

Taylor

December 2016

Georgia Power(a)

30 years

$

220

-

$230

(b)

Pawpaw

Longview Solar, LLC

30

Taylor

December 2015

Georgia Power(a)

30 years

$

70

-

$80

(b)

Butler Solar Farm

Strata Solar Development, LLC

20

Taylor

December 2015

Georgia Power(a)

20 years

$

42

-

$48

(b)

(a) Subject to FERC approval.

(b) 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 $85 million and $199 million for the three and six months ended June 30, 2015, respectively, and $68 million and $140 million for the three and six months ended June 30, 2014, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the three and six months ended June 30, 2015 and 2014 was as follows:

	Electric Utilities
	Traditional Operating Companies				Southern Power				Eliminations				Total				All Other				Eliminations				Consolidated
	(in millions)
Three Months Ended June 30, 2015:
Operating revenues	$	4,077			$	337			$	(90	)		$	4,324			$	43			$	(30	)		$	4,337
Segment net income (loss)(a)(b)	561				46				—				607				18				4				629
Six Months Ended June 30, 2015:
Operating revenues	$	8,025			$	684			$	(213	)		$	8,496			$	83			$	(59	)		$	8,520
Segment net income (loss)(a)(c)	1,038				79				—				1,117				21				—				1,138
Total assets at June 30, 2015	$	67,362			$	6,226			$	(277	)		$	73,311			$	1,360			$	(490	)		$	74,181
Three Months Ended June 30, 2014:
Operating revenues	$	4,209			$	329			$	(84	)		$	4,454			$	39			$	(26	)		$	4,467
Segment net income (loss)(a)	580				31				—				611				2				(2		)		611
Six Months Ended June 30, 2014:
Operating revenues	$	8,587			$	680			$	(186	)		$	9,081			$	80			$	(50	)		$	9,111
Segment net income (loss)(a)(c)	899				64				—				963				2				(3		)		962
Total assets at December 31, 2014	$	64,644			$	5,550			$	(131	)		$	70,063			$	1,156			$	(296	)		$	70,923

(a) After dividends on preferred and preference stock of subsidiaries.

(b) Segment net income (loss) for the traditional operating companies for the three months ended June 30, 2015 includes a $23 million pre-tax charge ($14 million after tax) 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 six months ended June 30, 2015 and June 30, 2014 includes a $32 million pre-tax charge ($20 million after tax) and a $380 million pre-tax charge ($235 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services

		Electric Utilities' Revenues
Period		Retail				Wholesale				Other				Total
		(in millions)
Three Months Ended June 30, 2015		$	3,714			$	448			$	162			$	4,324
Three Months Ended June 30, 2014		3,770				515				169				4,454
Six Months Ended June 30, 2015		$	7,256			$	915			$	325			$	8,496
Six Months Ended June 30, 2014		7,628				1,119				334				9,081

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(c) Issuer Purchases of Equity Securities

2015		Total Number of Shares Purchased (*)			Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (*)		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (*)
April 1 – April 30		—			N/A		N/A		N/A
May 1 – May 31		—			N/A		N/A		N/A
June 1 – June 30		—			N/A		N/A		N/A
Total		—			N/A		N/A		17,400,634

(*)

On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. There were no repurchases under this program in the second quarter 2015. As of June 30, 2015, Southern Company had repurchased a total of 2,599,366 shares under this program.

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Item 6.    Exhibits.

The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.

		(3) Articles of Incorporation and By-Laws
		(a)1	-	By-laws of Southern Company as amended effective May 27, 2015, and as presently in effect. (Designated in Form 8-K dated May 27, 2015, File No. 1-3526, as Exhibit 3.1.)
		(4) Instruments Describing Rights of Security Holders, Including Indentures
		Southern Company
		(a)1	-	Eleventh Supplemental Indenture to Senior Note Indenture dated as of June 12, 2015, providing for the issuance of the Series 2015A 2.750% Senior Notes due June 15, 2020. (Designated in Form 8-K dated June 9, 2015, File No. 1-3526, as Exhibit 4.2.)
		Southern Power
		(f)1	-	Sixth Supplemental Indenture to Senior Note Indenture dated as of May 20, 2015, providing for the issuance of the Series 2015A 1.500% Senior Notes due June 1, 2018. (Designated in Form 8-K dated May 14, 2015, File No. 333-98553, as Exhibit 4.4(a).)
		(f)2	-	Seventh Supplemental Indenture to Senior Note Indenture dated as of May 20, 2015, providing for the issuance of the Series 2015B 2.375% Senior Notes due June 1, 2020. (Designated in Form 8-K dated May 14, 2015, File No. 333-98553, as Exhibit 4.4(b).)
		(10) Material Contracts
		Southern Company
#		(a)1	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)
#	*	(a)2	-	First Amendment to the Deferred Compensation Plan for Outside Directors of The Southern Company, effective April 1, 2015.
		Alabama Power
#	*	(b)1	-	First Amendment to the Deferred Compensation Plan for Outside Directors of Alabama Power Company, effective June 1, 2015.
#		(b)2	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)
		Georgia Power
	*	(c)1	-	Amendment No. 1 to Loan Guarantee Agreement between Georgia Power and the DOE, dated as of June 4, 2015.
#		(c)2	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)
		Gulf Power

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#	*	(d)1	-	First Amendment to the Deferred Compensation Plan for Outside Directors of Gulf Power Company, effective April 1, 2015.
#		(d)2	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)
		Mississippi Power
#	*	(e)1	-	First Amendment to the Deferred Compensation Plan for Outside Directors of Mississippi Power Company, effective April 1, 2015.
#		(e)2	-	Outside Directors Stock Plan for The Southern Company and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)
		(24) Power of Attorney and Resolutions
		Southern Company
		(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014, File No. 1-3526 as Exhibit 24(a).)
		Alabama Power
		(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014, File No. 1-3164 as Exhibit 24(b).)
		Georgia Power
		(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014, File No. 1-6468 as Exhibit 24(c).)
		Gulf Power
		(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014, File No. 001-31737 as Exhibit 24(d).)
	*	(d)2	-	Power of Attorney for Xia Liu.
		Mississippi Power
		(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014, File No. 001-11229 as Exhibit 24(e).)
		Southern Power
		(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014, File No. 333-98553 as Exhibit 24(f).)
		(31) Section 302 Certifications
		Southern Company
	*	(a)1	-	Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(a)2	-	Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Alabama Power
	*	(b)1	-	Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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	*	(b)2	-	Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Georgia Power
	*	(c)1	-	Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(c)2	-	Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Gulf Power
	*	(d)1	-	Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(d)2	-	Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Mississippi Power
	*	(e)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(e)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Southern Power
	*	(f)1	-	Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(f)2	-	Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		(32) Section 906 Certifications
		Southern Company
	*	(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Alabama Power
	*	(b)	-	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Georgia Power
	*	(c)	-	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Gulf Power
	*	(d)	-	Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Mississippi Power
	*	(e)	-	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

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

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THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		THE SOUTHERN COMPANY
By		Thomas A. Fanning
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		Art P. Beattie
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 5, 2015

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ALABAMA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		ALABAMA POWER COMPANY
By		Mark A. Crosswhite
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		Philip C. Raymond
		Executive Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 5, 2015

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GEORGIA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		GEORGIA POWER COMPANY
By		W. Paul Bowers
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		W. Ron Hinson
		Executive Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 5, 2015

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GULF POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		GULF POWER COMPANY
By		S. W. Connally, Jr.
		President and Chief Executive Officer
		(Principal Executive Officer)
By		Xia Liu
		Vice President and Chief Financial Officer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 5, 2015

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MISSISSIPPI POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		MISSISSIPPI POWER COMPANY
By		G. Edison Holland, Jr.
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		Moses H. Feagin
		Vice President, Treasurer, and Chief Financial Officer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 5, 2015

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SOUTHERN POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		SOUTHERN POWER COMPANY
By		Oscar C. Harper IV
		President and Chief Executive Officer
		(Principal Executive Officer)
By		William C. Grantham
		Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 5, 2015

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