SO_10Q_6.30.2013

Second Quarter 2013 vs. Second Quarter 2012

Year-to-Date 2013 vs. Year-to-Date 2012

(change in millions)

(% change)

(change in millions)

(% change)

10-Q 1 so_10qx6302013.htm 10-Q SO_10Q_6.30.2013

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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, 2013

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to



Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-3526	The Southern Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000	58-0690070

1-3164	Alabama Power Company (An Alabama Corporation) 600 North 18^th Street Birmingham, Alabama 35203 (205) 257-1000	63-0004250

1-6468	Georgia Power Company (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526	58-0257110

001-31737	Gulf Power Company (A Florida Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111	59-0276810

001-11229	Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Boulevard Gulfport, Mississippi 39501 (228) 864-1211	64-0205820

333-98553	Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000	58-2598670

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

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

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



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

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



Registrant	Description of Common Stock	Shares Outstanding at June 30, 2013
The Southern Company	Par Value $5 Per Share	873,903,083
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	4,942,717
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000

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

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2013



		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	42
	Condensed Statements of Comprehensive Income	42
	Condensed Statements of Cash Flows	43
	Condensed Balance Sheets	44
	Management's Discussion and Analysis of Financial Condition and Results of Operations	46
	Georgia Power Company
	Condensed Statements of Income	63
	Condensed Statements of Comprehensive Income	63
	Condensed Statements of Cash Flows	64
	Condensed Balance Sheets	65
	Management's Discussion and Analysis of Financial Condition and Results of Operations	67
	Gulf Power Company
	Condensed Statements of Income	85
	Condensed Statements of Comprehensive Income	85
	Condensed Statements of Cash Flows	86
	Condensed Balance Sheets	87
	Management's Discussion and Analysis of Financial Condition and Results of Operations	89
	Mississippi Power Company
	Condensed Statements of Operations	105
	Condensed Statements of Comprehensive Income (Loss)	105
	Condensed Statements of Cash Flows	106
	Condensed Balance Sheets	107
	Management's Discussion and Analysis of Financial Condition and Results of Operations	109
	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	150
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	39

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2013



		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	192
Item 1A.	Risk Factors	192
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	192
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	193
	Signatures	197

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DEFINITIONS



Term	Meaning

2010 ARP	Alternate Rate Plan approved by the Georgia PSC for Georgia Power, which became effective January 1, 2011 and will continue through December 31, 2013
2011 IRP	Georgia Power's 2011 Integrated Resource Plan update filed with the Georgia PSC
2013 IRP	Georgia Power's triennial Integrated Resource Plan filed with the Georgia PSC on January 31, 2013
AFUDC	Allowance for Funds Used During Construction
Alabama Power	Alabama Power Company
AOCI	Accumulated Other Comprehensive Income
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
Clean Air Act	Clean Air Act Amendments of 1990
Contractor	Westinghouse and Stone & Webster, Inc.
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
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
Form 10-K	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power for the year ended December 31, 2012
Form 10-K/A	Annual Report on Form 10-K of Mississippi Power for the year ended December 31, 2012, as amended by Amendment No. 1
GAAP	Generally Accepted Accounting Principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IIC	Intercompany Interchange Contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
Kemper IGCC	Integrated coal gasification combined cycle facility under construction in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
MATS rule	Mercury and Air Toxics Standards Rule
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
MWH	Megawatt-hour
NCCR	Georgia Power's Nuclear Construction Cost Recovery
NDR	Alabama Power's Natural Disaster Reserve
NRC	Nuclear Regulatory Commission
NSR	New Source Review
OCI	Other Comprehensive Income

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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
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 are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power Purchase Agreement
PSC	Public Service Commission
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
ROE	Return on Equity
SEC	Securities and Exchange Commission
SEGCO	Southern Electric Generating Company
SMEPA	South Mississippi Electric Power Association
SO₂	Sulfur dioxide
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
S&P	Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Westinghouse	Westinghouse Electric Company LLC
wholesale revenues	revenues generated from sales for resale

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, the strategic goals for the wholesale business, customer growth, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, start and completion dates of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 and the American Taxpayer Relief Act of 2012, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other capital expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•

the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, 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 the 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 recent recession, population and business growth (and declines), the effects of energy conservation measures, and any potential economic impacts resulting from federal fiscal decisions;


•	available sources and costs of fuels;


•	effects of inflation;

•

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


•	ability to construct facilities in accordance with the requirements of permits and licenses and to satisfy any operational and environmental performance standards, including the requirements of tax credits and other incentives;


•	investment performance of Southern Company's employee 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;


•	regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals, NRC actions, and potential DOE loan guarantees;

•

regulatory approvals and actions related to cost recovery for the Kemper IGCC, including Mississippi PSC review of Mississippi Power's proposed rate recovery plan and the prudence of Kemper IGCC costs, and actions relating to proposed securitization; the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA as contemplated by Mississippi Power's proposed rate recovery plan; satisfaction of requirements to utilize investment tax

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credits and grants; and the outcome of any legal or regulatory proceedings regarding the Mississippi PSC's issuance of the CPCN for the Kemper IGCC, the settlement agreement between Mississippi Power and the Mississippi PSC, or the Baseload Act;


•	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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;


•	interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company's and its subsidiaries' credit ratings;


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


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


•	catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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 and the Form 10-K/A) 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,
	2013			2012			2013			2012
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	3,620		$	3,597		$	6,918		$	6,689
Wholesale revenues	454			415			886			764
Other electric revenues	156			154			311			302
Other revenues	16			15			28			30
Total operating revenues	4,246			4,181			8,143			7,785
Operating Expenses:
Fuel	1,374			1,290			2,636			2,354
Purchased power	127			150			222			291
Other operations and maintenance	947			944			1,921			1,911
MC Asset Recovery insurance settlement	—			(19		)	—			(19		)
Depreciation and amortization	476			445			942			886
Taxes other than income taxes	232			228			467			453
Estimated loss on Kemper IGCC	450			—			990			—
Total operating expenses	3,606			3,038			7,178			5,876
Operating Income	640			1,143			965			1,909
Other Income and (Expense):
Allowance for equity funds used during construction	45			32			86			63
Leveraged lease income (loss)	5			5			(16		)	11
Interest expense, net of amounts capitalized	(215		)	(220		)	(426		)	(431		)
Other income (expense), net	(4		)	8			(10		)	—
Total other income and (expense)	(169		)	(175		)	(366		)	(357		)
Earnings Before Income Taxes	471			968			599			1,552
Income taxes	158			329			189			529
Consolidated Net Income	313			639			410			1,023
Dividends on Preferred and Preference Stock of Subsidiaries	16			16			32			32
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	297		$	623		$	378		$	991
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.34		$	0.71		$	0.43		$	1.14
Diluted EPS	$	0.34		$	0.71		$	0.43		$	1.13
Average number of shares of common stock outstanding (in millions)
Basic	874			872			872			870
Diluted	879			880			877			879
Cash dividends paid per share of common stock	$	0.5075		$	0.4900		$	0.9975		$	0.9625

The accompanying notes as they relate to Southern Company are an integral part of these condensed 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,
	2013			2012			2013			2012
	(in millions)						(in millions)
Consolidated Net Income	$	313		$	639		$	410		$	1,023
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(8), $- and $(5), respectively	—			(10		)	—			(7		)
Reclassification adjustment for amounts included in net income, net of tax of $2, $2, $4 and $3, respectively	3			2			6			4
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	2			1			3			2
Total other comprehensive income (loss)	5			(7		)	9			(1		)
Dividends on preferred and preference stock of subsidiaries	(16		)	(16		)	(32		)	(32		)
Comprehensive Income	$	302		$	616		$	387		$	990

The accompanying notes as they relate to Southern Company are an integral part of these condensed 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,
	2013			2012
	(in millions)
Operating Activities:
Consolidated net income	$	410		$	1,023
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,140			1,064
Deferred income taxes	(141		)	327
Investment tax credits	83			16
Allowance for equity funds used during construction	(86		)	(63		)
Leveraged lease income (loss)	16			(11		)
Pension, postretirement, and other employee benefits	41			13
Stock based compensation expense	37			35
Retail fuel cost recovery — long-term	(123		)	44
Estimated loss on Kemper IGCC	990			—
Other, net	31			(22		)
Changes in certain current assets and liabilities —
-Receivables	(325		)	(55		)
-Fossil fuel stock	185			(305		)
-Materials and supplies	52			(17		)
-Other current assets	(55		)	(36		)
-Accounts payable	(52		)	(167		)
-Accrued taxes	6			45
-Accrued compensation	(257		)	(216		)
-Retail fuel cost recovery — short-term	(22		)	101
-Other current liabilities	17			(19		)
Net cash provided from operating activities	1,947			1,757
Investing Activities:
Property additions	(2,597		)	(2,356		)
Investment in restricted cash	(98		)	(230		)
Distribution of restricted cash	23			49
Nuclear decommissioning trust fund purchases	(548		)	(576		)
Nuclear decommissioning trust fund sales	546			574
Cost of removal, net of salvage	(56		)	(58		)
Change in construction payables, net	114			(115		)
Other investing activities	(13		)	(79		)
Net cash used for investing activities	(2,629		)	(2,791		)
Financing Activities:
Increase (decrease) in notes payable, net	767			(406		)
Proceeds —
Long-term debt issuances	1,197			2,487
Interest-bearing refundable deposit related to asset sale	—			150
Preference stock	50			—
Common stock issuances	161			316
Redemptions —
Long-term debt	(792		)	(1,319		)
Common stock repurchased	(18		)	—
Payment of common stock dividends	(870		)	(837		)
Payment of dividends on preferred and preference stock of subsidiaries	(32		)	(32		)
Other financing activities	15			19
Net cash provided from financing activities	478			378
Net Change in Cash and Cash Equivalents	(204		)	(656		)
Cash and Cash Equivalents at Beginning of Period	628			1,315
Cash and Cash Equivalents at End of Period	$	424		$	659
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $37 and $41 capitalized for 2013 and 2012, respectively)	$	384		$	391
Income taxes, net	142			(34		)
Noncash transactions — accrued property additions at end of period	637			488

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2013			At December 31, 2012
	(in millions)
Current Assets:
Cash and cash equivalents	$	424		$	628
Restricted cash and cash equivalents	7			7
Receivables —
Customer accounts receivable	1,164			961
Unbilled revenues	522			441
Under recovered regulatory clause revenues	45			29
Other accounts and notes receivable	251			235
Accumulated provision for uncollectible accounts	(16		)	(17		)
Fossil fuel stock, at average cost	1,634			1,819
Materials and supplies, at average cost	939			1,000
Vacation pay	166			165
Prepaid expenses	700			657
Other regulatory assets, current	130			163
Other current assets	35			74
Total current assets	6,001			6,162
Property, Plant, and Equipment:
In service	64,150			63,251
Less accumulated depreciation	22,533			21,964
Plant in service, net of depreciation	41,617			41,287
Other utility plant, net	261			263
Nuclear fuel, at amortized cost	846			851
Construction work in progress	6,593			5,989
Total property, plant, and equipment	49,317			48,390
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,352			1,303
Leveraged leases	653			670
Miscellaneous property and investments	219			216
Total other property and investments	2,224			2,189
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,393			1,385
Unamortized debt issuance expense	141			133
Unamortized loss on reacquired debt	297			309
Other regulatory assets, deferred	4,041			4,032
Other deferred charges and assets	547			549
Total deferred charges and other assets	6,419			6,408
Total Assets	$	63,961		$	63,149

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholders' Equity	At June 30, 2013			At December 31, 2012
	(in millions)
Current Liabilities:
Securities due within one year	$	2,085		$	2,335
Interest-bearing refundable deposit related to asset sale	150			150
Notes payable	1,587			825
Accounts payable	1,467			1,387
Customer deposits	378			370
Accrued taxes —
Accrued income taxes	91			10
Other accrued taxes	351			391
Accrued interest	251			237
Accrued vacation pay	212			212
Accrued compensation	188			433
Liabilities from risk management activities	55			75
Other regulatory liabilities, current	66			107
Other current liabilities	465			482
Total current liabilities	7,346			7,014
Long-term Debt	19,943			19,274
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	9,944			9,938
Deferred credits related to income taxes	206			211
Accumulated deferred investment tax credits	936			894
Employee benefit obligations	2,504			2,540
Asset retirement obligations	1,840			1,748
Other cost of removal obligations	1,243			1,194
Other regulatory liabilities, deferred	320			289
Other deferred credits and liabilities	508			668
Total deferred credits and other liabilities	17,501			17,482
Total Liabilities	44,790			43,770
Redeemable Preferred Stock of Subsidiaries	375			375
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued —June 30, 2013: 884 million shares
— December 31, 2012: 878 million shares
Treasury — June 30, 2013: 10.0 million shares
— December 31, 2012: 10.0 million shares
Par value	4,417			4,389
Paid-in capital	5,053			4,855
Treasury, at cost	(451		)	(450		)
Retained earnings	9,135			9,626
Accumulated other comprehensive loss	(114		)	(123		)
Total Common Stockholders' Equity	18,040			18,297
Preferred and Preference Stock of Subsidiaries	756			707
Total Stockholders' Equity	18,796			19,004
Total Liabilities and Stockholders' Equity	$	63,961		$	63,149

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2013 vs. SECOND QUARTER 2012

AND

YEAR-TO-DATE 2013 vs. YEAR-TO-DATE 2012

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – and Southern Power and 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, subsidiaries of Southern Company are constructing Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in two units, each with approximately 1,100 MWs) and the Kemper IGCC with 582 MWs. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "PSC Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

In accordance with the 2010 ARP, Georgia Power filed a base rate case with the Georgia PSC on June 28, 2013, requesting a base rate increase effective January 1, 2014. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Rate Plans" herein for additional information.

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7 of the Form 10-K. See FUTURE EARNINGS POTENTIAL – "Other Matters" herein for information regarding an explosion at Plant Bowen in April 2013 that is expected to negatively impact the Southern Company system's actual performance on its peak season equivalent forced outage rate, one of its key performance indicators, for 2013, as compared to the target. See also Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding the revisions to the cost estimate for the Kemper IGCC that negatively impact Southern Company's earnings per share, one of its key performance indicators, for 2013, as compared to the target.

RESULTS OF OPERATIONS

Net Income

Southern Company's second quarter 2013 net income after dividends on preferred and preference stock of subsidiaries was $297 million ($0.34 per share) compared to $623 million ($0.71 per share) for the second quarter 2012. The decrease was primarily related to a revision 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

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of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and the cost of the lignite mine and equipment, the cost of the carbon dioxide 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). Also contributing to the decrease were a decrease in weather-related revenues due to less favorable weather in the second quarter 2013 as compared to the corresponding period in 2012, an increase in depreciation related to new generating plants in service, an insurance recovery received in 2012 related to the litigation settlement with MC Asset Recovery, LLC, and state income tax credits recognized in 2012. The decrease was partially offset by an increase in retail base revenues at Georgia Power.

Southern Company's year-to-date 2013 net income after dividends on preferred and preference stock of subsidiaries was $378 million ($0.43 per share) compared to $991 million ($1.14 per share) for year-to-date 2012. The decrease was primarily related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recorded in the first and second quarters of 2013. Also contributing to the decrease were an increase in depreciation related to new generating plants in service, decreased customer usage, an insurance recovery received in 2012 related to the litigation settlement with MC Asset Recovery, LLC, a reduction in leveraged lease income resulting from a lease restructuring, and state income tax credits recognized in 2012. The decrease was partially offset by an increase in retail base revenues at Georgia Power and an increase in AFUDC equity. See Note 3 to the financial statements of Southern Company under "Insurance Recovery" in Item 8 of the Form 10-K for additional information on the insurance recovery received in 2012 related to the litigation settlement with MC Asset Recovery, LLC. Also see Note (J) to the Condensed Financial Statements herein for additional information on the lease restructuring.

Retail Revenues

In the second quarter 2013 and 2012, retail revenues were $3.6 billion. For year-to-date 2013, retail revenues were $6.9 billion compared to $6.7 billion for the corresponding period in 2012.

Details of the changes in retail revenues were as follows:



	Second Quarter 2013					Year-to-Date 2013
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	3,597				$	6,689
Estimated change in –
Rates and pricing	58			1.6		105			1.6
Sales growth (decline)	(10		)	(0.3	)	(25		)	(0.4	)
Weather	(56		)	(1.6	)	10			0.1
Fuel and other cost recovery	31			0.9		139			2.1
Retail – current year	$	3,620		0.6	%	$	6,918		3.4	%

Revenues associated with changes in rates and pricing increased in the second quarter 2013 and year-to-date 2013 when compared to the corresponding periods in 2012 primarily due to base tariff increases at Georgia Power effective April 2012 and January 1, 2013, as approved by the Georgia PSC, related to placing new generating units at Plant McDonough-Atkinson in service, the financing costs related to the construction of Plant Vogtle Units 3 and 4, higher contributions from market-driven rates from commercial and industrial customers, and the pricing effect of decreased customer usage.

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Revenues attributable to changes in sales decreased in the second quarter 2013 when compared to the corresponding period in 2012. The decrease was due to a 1.6% decrease in weather-adjusted commercial KWH sales and a 0.5% decrease in weather-adjusted residential KWH sales, partially offset by a 0.6% increase in industrial KWH sales. The decreases in weather-adjusted residential and commercial KWH sales for the second quarter 2013 were primarily due to decreased customer usage, partially offset by customer growth. The increase in industrial KWH sales for the second quarter 2013 was primarily due to increases in the primary metals, non-manufacturing, paper, and stone, clay, and glass sectors, partially offset by a decrease in the chemicals sector.

Revenues attributable to changes in sales decreased for year-to-date 2013 when compared to the corresponding period in 2012. The decrease was due to a 0.7% decrease in weather-adjusted residential KWH sales, a 0.7% decrease in weather-adjusted commercial KWH sales, and a 0.7% decrease in industrial KWH sales. The decreases in weather-adjusted residential and commercial KWH sales for year-to-date 2013 were primarily due to decreased customer usage, partially offset by customer growth. The decrease in industrial KWH sales for year-to-date 2013 was primarily due to decreases in the chemicals sector, partially offset by an increase in the primary metals, non-manufacturing, and stone, clay, and glass sectors. In addition, an extra day of sales as a result of the leap year in 2012 negatively impacted KWH sales in all customer classes in 2013.

In the first quarter 2012, Georgia Power began using new actual advanced meter data to compute unbilled revenues. The year-to-date weather-adjusted KWH sales variances shown above reflect an adjustment to the estimated allocation of Georgia Power's unbilled January 2012 KWH sales among customer classes that is consistent with the actual allocation in 2013. Without this adjustment, year-to-date 2013 weather-adjusted residential KWH sales decreased 1.2% as compared to the corresponding period in 2012 and weather-adjusted commercial KWH sales decreased 0.2% as compared to the corresponding period in 2012.

Fuel and other cost recovery revenues increased $31 million and $139 million in the second quarter and year-to-date 2013, respectively, when compared to the corresponding periods in 2012 primarily due to higher fuel costs. 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, storm damage, new plants, and PPAs.

Wholesale Revenues

Wholesale revenues consist of PPAs with investor-owned utilities and electric cooperatives, unit power sales contracts, and short-term opportunity sales. Wholesale revenues from PPAs and unit power sales contracts 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. 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 2013, wholesale revenues were $454 million compared to $415 million for the corresponding period in 2012, reflecting a $22 million increase in capacity revenues and a $17 million increase in energy revenues. The increase in capacity revenues was primarily due to the commencement of a new PPA at Southern Power for Plant Nacogdoches placed in service in the second half of 2012. The increase in energy revenues was primarily related to an increase in the average cost of natural gas, partially offset by a decrease in volume related to less favorable weather in the second quarter 2013 as compared to the corresponding period in 2012.

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For year-to-date 2013, wholesale revenues were $886 million compared to $764 million for the corresponding period in 2012, reflecting a $77 million increase in energy revenues and a $45 million increase in capacity revenues. The increase in energy revenues was primarily related to an increase in the average cost of natural gas. The increase in capacity revenues was primarily due to the commencement of a new PPA at Southern Power for Plant Nacogdoches placed in service in the second half of 2012.

Fuel and Purchased Power Expenses



	Second Quarter 2013 vs. Second Quarter 2012					Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	84		6.5		$	282		12.0
Purchased power	(23		)	(15.3	)	(69		)	(23.7	)
Total fuel and purchased power expenses	$	61				$	213

In the second quarter 2013, total fuel and purchased power expenses were $1.5 billion compared to $1.4 billion for the corresponding period in 2012. The increase was primarily the result of a $176 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $64 million decrease in the volume of KWHs purchased and a $51 million decrease in the volume of KWHs generated.

For year-to-date 2013, total fuel and purchased power expenses were $2.9 billion compared to $2.6 billion for the corresponding period in 2012. The increase was primarily the result of a $276 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices and a $60 million increase in the volume of KWHs generated, partially offset by a $123 million decrease in the volume of KWHs purchased.

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

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



	Second Quarter 2013	Second Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (billions of KWHs)	44	44	86	83
Total purchased power (billions of KWHs)	3	5	6	9
Sources of generation (percent) —
Coal	41	41	37	38
Nuclear	17	17	17	18
Gas	37	41	41	41
Hydro	5	1	5	3
Cost of fuel, generated (cents per net KWH) —
Coal	4.06	4.18	4.10	4.14
Nuclear	0.88	0.83	0.86	0.81
Gas	3.56	2.56	3.32	2.66
Average cost of fuel, generated (cents per net KWH)	3.30	2.94	3.19	2.90
Average cost of purchased power (cents per net KWH)^(a)	5.32	4.09	4.98	3.98

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

Fuel

In the second quarter 2013, fuel expense was $1.4 billion compared to $1.3 billion for the corresponding period in 2012. The increase was primarily due to a 39.1% increase in the average cost of natural gas per KWH generated, partially offset by an 11.4% decrease in KWHs generated by natural gas and a 413.5% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

For year-to-date 2013, fuel expense was $2.6 billion compared to $2.4 billion for the corresponding period in 2013. The increase was primarily due to a 24.8% increase in the average cost of natural gas per KWH generated, partially offset by a 109.6% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

Purchased Power

In the second quarter 2013, purchased power expense was $127 million compared to $150 million for the corresponding period in 2012. The decrease was primarily due to a 33.5% decrease in the volume of KWHs purchased as the marginal cost of generation available was lower than the market cost of available energy, partially offset by a 30.1% increase in the average cost per KWH purchased.

For year-to-date 2013, purchased power expense was $222 million compared to $291 million for the corresponding period in 2012. The decrease was primarily due to a 33.6% decrease in the volume of KWHs purchased as the marginal cost of generation available was lower than the market cost of available energy, partially offset by a 25.1% increase in the average cost per KWH purchased.

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

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Other Operations and Maintenance Expenses

In the second quarter 2013, other operations and maintenance expenses were $947 million compared to $944 million for the corresponding period in 2012. The increase was not material.

For year-to-date 2013, other operations and maintenance expenses were $1.92 billion compared to $1.91 billion for the corresponding period in 2012. The increase was primarily the result of a $24 million increase in pension costs and a $10 million increase in amortization of Alabama Power's nuclear outage expenses. The increases were partially offset by a $9 million decrease in fossil and hydro expenses related to scheduled outage and maintenance costs, an $8 million decrease in commodity and labor costs, a $4 million decrease in salaries and wages, and a $3 million decrease in transmission and distribution costs. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Nuclear Outage Accounting Order" of Southern Company in Item 7 of the Form 10-K for additional information on the amortization of Alabama Power's nuclear outage expenses.

Depreciation and Amortization

In the second quarter 2013, depreciation and amortization was $476 million compared to $445 million for the corresponding period in 2012. The increase was primarily the result of certain unit retirement decisions (with respect to the portion of such units dedicated to wholesale service) at Georgia Power, additional plant in service due to the completion of Georgia Power's Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively, additional plant in service at Southern Power, as well as additional transmission and distribution projects.

For year-to-date 2013, depreciation and amortization was $942 million compared to $886 million for the corresponding period in 2012. The increase was primarily the result of certain unit retirement decisions (with respect to the portion of such units dedicated to wholesale service) at Georgia Power, additional plant in service due to the completion of Georgia Power's Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively, additional plant in service at Southern Power, as well as additional transmission and distribution projects. These increases were partially offset by amortization of the regulatory liability previously established for state income tax credits at Georgia Power, as authorized by the Georgia PSC.

Taxes Other Than Income Taxes

In the second quarter 2013, taxes other than income taxes were $232 million compared to $228 million for the corresponding period in 2012. The increase was not material.

For year-to-date 2013, taxes other than income taxes were $467 million compared to $453 million for the corresponding period in 2012. The increase was primarily the result of increases in property taxes and municipal franchise fees.

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Estimated Loss on Kemper IGCC

N/M – Not meaningful

In the second quarter 2013 and year-to-date 2013, estimated probable losses on the Kemper IGCC of $450 million and $990 million, respectively, were recorded at Southern Company to 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 the DOE Grants and the Cost Cap Exceptions. See FUTURE EARNINGS POTENTIAL – "Construction Program" 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

In the second quarter 2013, AFUDC equity was $45 million compared to $32 million for the corresponding period in 2012. For year-to-date 2013, AFUDC equity was $86 million compared to $63 million for the corresponding period in 2012. The increases were primarily due to an increase in CWIP related to Mississippi Power's Kemper IGCC, partially offset by the completion of Georgia Power's Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

Leveraged Lease Income (Loss)

For-year-to-date 2013, leveraged lease income (loss) was $(16) million compared to $11 million for the corresponding period in 2012. The decrease was primarily due to the restructuring of a leveraged lease investment. See Note (J) to the Condensed Financial Statements herein for additional information.

Income Taxes

In the second quarter 2013, income taxes were $158 million compared to $329 million for the corresponding period in 2012. For year-to-date 2013, income taxes were $189 million compared to $529 million for the corresponding period in 2012. The decreases were primarily due to lower pre-tax earnings, partially offset by state income tax credits recognized in 2012 primarily at Georgia Power.

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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 successful completion of ongoing construction projects, including construction of generating facilities. Another major factor is the profitability of the competitive wholesale supply business. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced 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 supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, 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. 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.

Climate Change Litigation

Kivalina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

Hurricane Katrina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On May 14, 2013, the U.S. Court of Appeals for the Fifth Circuit upheld the U.S. District Court for the Southern District of Mississippi's dismissal of the case. The decision is subject to appeal; therefore, the ultimate outcome of this matter cannot be determined at this time.

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Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding Alabama's State Implementation Plan requirements related to opacity, the EPA's MATS rule, the 2007 State of Georgia Multi-Pollutant Rule, the Cross State Air Pollution Rule, and the EPA's SO₂ rule.

On March 6, 2013, the U.S. Court of Appeals for the Eleventh Circuit upheld the EPA's 2008 approval of Alabama's opacity requirements and vacated the EPA's 2011 attempt to rescind its approval, thereby resolving Alabama Power's appeal in Alabama Power's favor.

On April 24, 2013, the EPA published a final reconsideration rule addressing new source standards within the MATS rule. Although the EPA had considered revisions to the startup and shutdown provisions of the MATS rule, a final decision on these provisions was deferred. The ultimate impact of this rulemaking will depend on the outcome of any additional rulemaking and/or legal challenges and, therefore, cannot be determined at this time.

On April 30, 2013, the State of Georgia finalized revisions to the 2007 State of Georgia Multi-Pollutant Rule and a companion rule requiring a 95% reduction in SO₂ emissions from certain coal-fired generating units. The revisions modify the compliance dates under those two rules for units yet to be controlled to synchronize them with the MATS rule compliance deadline. The revisions also allow natural gas to be used as a compliance alternative at Plant Yates. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" herein for additional information regarding the conversion of Plant Yates Units 6 and 7.

On June 24, 2013, the U.S. Supreme Court issued an order granting petitions by the EPA and other parties requesting review of the U.S. Court of Appeals for the District of Columbia Circuit's decision to vacate and remand the Cross State Air Pollution Rule to the EPA. The ultimate outcome of this matter cannot be determined at this time.

On July 25, 2013, the EPA issued initial nonattainment area designations under the one-hour National Ambient Air Quality Standard for SO₂ based on ambient air quality monitoring data. No areas within the Southern Company system's service territory were designated as nonattainment under this rule. The EPA has deferred designation of attainment and unclassifiable areas and may designate additional areas as nonattainment in the future, which could include areas within the Southern Company system's service territory. The ultimate outcome of this matter 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 proposed revision of the current steam electric effluent guidelines and rule for cooling water intake structures.

On June 7, 2013, the EPA published a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of the facilities of the traditional operating companies and Southern Power, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

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On June 27, 2013, the EPA entered into an amended settlement agreement to extend the deadline for issuing a final rule for cooling water intake structures until November 4, 2013. The ultimate outcome of this matter cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information regarding the proposed regulation of greenhouse gas emissions through establishment of new source performance standards.

On June 25, 2013, a Presidential Memorandum directed the EPA to issue a revised proposal addressing new fossil fuel-fired steam electric generating units by September 20, 2013 and to propose standards, regulations, or guidelines for addressing modified, reconstructed, and existing steam electric generating units by June 1, 2014. The ultimate impact of these proposed regulations and guidelines will depend on the scope and specific requirements of the proposed and final rules and the outcome of any legal challenges.

Although the outcome of the proposed regulations and guidelines cannot be determined at this time, additional restrictions on the Southern Company system's greenhouse gas emissions at the federal or state level could result in significant additional compliance costs, including capital expenditures. These costs could affect future unit retirement and replacement decisions. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

PSC Matters

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. The traditional operating companies have experienced lower pricing for natural gas in recent years resulting in an increase in natural gas generation and a decrease in coal generation, which is currently more costly. Although natural gas prices have doubled from their lowest point in 2012, natural gas units still supply a large portion of the traditional operating companies' generation. As a result, the total over recovered fuel balance at Alabama Power, Georgia Power, and Mississippi Power included on Southern Company's Condensed Balance Sheets herein was approximately $158 million at June 30, 2013 compared to the total over recovered fuel balance at Georgia Power, Gulf Power, and Mississippi Power as of December 31, 2012 of approximately $303 million. At June 30, 2013, Gulf Power had under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $16 million. At December 31, 2012, Alabama Power had under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $4 million.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any 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.

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

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Alabama Power

Rate RSE

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate RSE" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information regarding Alabama Power's Rate Stabilization and Equalization (Rate RSE). In May, June, and July 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. The ultimate outcome of these proceedings cannot be determined at this time.

Rate CNP

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate CNP" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through Rate Certificated New Plant Environmental (Rate CNP Environmental).

On August 1, 2013, Alabama Power filed a petition with the Alabama PSC requesting a revision to Rate CNP Environmental that would allow recovery of costs related to pre-2005 environmental assets currently being recovered through Rate RSE. The revenue impact as a result of this proposed revision is estimated to be $50 million in 2014; however, this petition is being made in accordance with Alabama Power's agreement with the Alabama PSC to develop a plan to keep Rate RSE and Rate CNP Environmental factors unchanged in 2014. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate RSE" in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information. Any unrecovered amounts associated with 2014 environmental compliance costs will be reflected in the 2015 Rate CNP Environmental filing. This petition is subject to the Alabama PSC's approval. The ultimate outcome of this matter cannot be determined at this time.

Natural Disaster Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Natural Disaster Reserve" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve" in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2013, the NDR had an accumulated balance of $95 million as compared to $103 million at December 31, 2012, which is included on Southern Company's Condensed Balance Sheet herein under other regulatory liabilities, deferred. The decrease in the NDR is a result of storm activity. The related accruals are reflected as operations and maintenance expenses on Southern Company's Condensed Statement of Income herein.

Non-Nuclear Outage Accounting Order

On August 1, 2013, Alabama Power filed a petition with the Alabama PSC requesting authorization to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures proposed to be deferred and amortized are estimated to total approximately $70 million. This petition is being made in accordance with Alabama Power's agreement with the Alabama PSC to develop a plan to keep Rate RSE factors unchanged in 2014. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate RSE" in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information. This petition is subject to the Alabama PSC's approval. The ultimate outcome of this matter cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Georgia Power

Rate Plans

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

In accordance with the 2010 ARP, Georgia Power filed a base rate case with the Georgia PSC on June 28, 2013 (2013 Rate Case). The filing includes a requested rate increase totaling $482 million, or 6.1% of retail revenues, to be effective January 1, 2014 based on a proposed retail ROE of 11.50%. The requested increase will be recovered through Georgia Power's existing base rate tariffs as follows: $334 million through the traditional base rate tariffs, $132 million through the Environmental Compliance Cost Recovery (ECCR) tariff, $5 million through the Demand Side Management tariffs, and $11 million through the Municipal Franchise Fee tariff. The filing reflects revenue requirements that have been levelized over the three-year period ending December 31, 2016 to provide stable rates to customers during a period of rising costs. The request is being made to allow Georgia Power to recover the costs of recent and future investments in infrastructure including environmental controls, transmission and distribution, generation, and smart grid technologies in order to maintain high levels of reliability and superior customer service.

The primary points of the 2013 Rate Case are:


•	Continuation of the traditional base rate tariffs through December 31, 2016 based on a test year ending July 31, 2014 with a modification for an appropriate three-year levelization adjustment.


•	Continuation of the ECCR tariff through December 31, 2016 with a modification for an appropriate three-year levelization adjustment.


•	Continuation of an allowed retail ROE range of 10.25% to 12.25%.


•	Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range will be shared with Georgia Power's customers and the remaining one-third will be retained by Georgia Power.


•	Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

The Georgia PSC is scheduled to issue a final order in this matter during December 2013. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality," "– Water Quality," and "– Coal Combustion Byproducts" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Rate Plans" and "– Integrated Resource Plans" in Item 8 of the Form 10-K for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, proposed cooling water intake structure rules, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia's Multi-Pollutant Rule; Georgia Power's analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations; the 2010 ARP; the 2011 IRP; and the 2013 IRP.

On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (32 MWs), which was retired on April 25, 2013.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

31, 2013 as specified in the final order in the 2011 IRP to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (316 MWs) was also approved and will be effective by April 16, 2016, assuming a one-year extension of the MATS rule compliance date is approved by the State of Georgia Environmental Protection Division to allow for necessary transmission system reliability improvements.

Additionally, the Georgia PSC approved Georgia Power's proposed MATS rule compliance plan for emissions controls necessary for the continued operation of Plants Bowen Units 1 through 4, Wansley Units 1 and 2, Scherer Units 1 through 3, and Hammond Units 1 through 4, the switch to natural gas as the primary fuel at Plants Yates Units 6 and 7 and SEGCO's Plant Gaston Units 1 through 4, as well as the fuel switch at Plant McIntosh Unit 1 to operate on Powder River Basin coal.

The Georgia PSC also deferred decisions regarding the appropriate recovery periods for the net book values of Plant Branch Units 3 and 4 and Plant Boulevard Units 2 and 3, deferred environmental construction work in progress for Plant Branch Units 3 and 4 and Plant Yates Units 6 and 7, costs associated with unusable material and supplies, and any over or under recovered cost of removal balances remaining at the unit retirement dates for each retirement unit until the 2013 Rate Case. The Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases.

The Georgia PSC also approved an additional 525 MWs of solar generation to be purchased by Georgia Power. The 525 MWs will be subdivided into 425 MWs of utility scale projects and 100 MWs of distributed generation. The 425 MWs of the utility scale projects will be purchased through a competitive request for proposal process which will be open to all qualified market participants, including Georgia Power and its affiliates. The purchases resulting from both programs will be for energy only and recovered through Georgia Power's fuel cost recovery mechanism.

The decertification of these units, fuel conversions, and procurement of additional solar generation are not expected to have a material impact on Southern Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's order in the 2013 Rate Case and future fuel cases and cannot be determined at this time.

On April 22, 2013, Georgia Power executed two PPAs to purchase energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will commence in 2016 and end in 2035. On April 29, 2013 and May 13, 2013, Georgia Power executed two PPAs to purchase 50 MWs and 56 MWs, respectively, of biomass capacity and energy from two facilities that will commence in 2015 and end in 2035. On May 21, 2013, the Georgia PSC approved the biomass capacity and energy PPAs. These four PPAs result in additional contractual obligations of approximately $13 million in 2015, $47 million in 2016, $49 million in 2017, and $1.29 billion thereafter.

Income Tax Matters

Bonus Depreciation

In 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term production-period projects placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term production-period projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Southern Company through 2013.

On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property to be placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014). The extension of 50% bonus depreciation will have a positive impact on the future cash flows of Southern Company through 2014.

Consequently, Southern Company's positive cash flow benefit is estimated to be between $565 million and $630 million in 2013.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Construction Program

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, including the ongoing construction of Plant Vogtle Units 3 and 4 at Georgia Power, the Kemper IGCC at Mississippi Power, and solar units at Southern Power, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals 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 two units, each with approximately 1,100 MWs) and the construction of Mississippi Power's Kemper IGCC (582 MWs). See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for the cost estimate of the Southern Company system's construction program, which includes the current construction cost estimate to complete the Kemper IGCC. Also see Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined 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.

Investments in Leveraged Leases

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Investments in Leveraged Leases" of Southern Company in Item 7 and Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information.

On March 1, 2013, Southern Company completed the restructuring of the nonrecourse debt and the related rental payments associated with its leveraged lease investment in a 440-MW generation facility located in Choctaw County, Mississippi. In connection with the restructuring, Southern Company has committed, as owner/lessor, to invest approximately $60 million in capital over the next three years to improve the operational performance of the facility and upgrade environmental controls. As part of the restructuring, the interest rate on the nonrecourse debt was significantly reduced, resulting in lower debt payments for Southern Company and lower rental payments for the lessee over the remaining 19-year term of the nonrecourse debt and the lease. As a consequence of the restructuring, Southern Company recalculated its net investment in the lease to reflect changes in the future cash flows to Southern Company as owner/lessor. As a result of the recalculation, Southern Company recorded an after-tax charge to income during the first quarter 2013 of approximately $16 million. This noncash charge reflects a reallocation of previously recognized lease income that will be reflected in income over the remaining term of the lease.

Other Matters

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

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

See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011. On March 19, 2013, the NRC issued an order relating to hardened vents for certain classes of containment structures, including the one in use at Plant Hatch. On June 6, 2013, the NRC issued a new order superseding the March 19, 2013 order regarding enhanced safety for hardened vents. Southern Company is continuing to analyze the impact of this order. The ultimate outcome of this matter cannot be determined at this time; however, management does not currently anticipate that the compliance costs associated with this order would have a material impact on Southern Company's financial statements.

On April 4, 2013, an explosion occurred at Plant Bowen Unit 2 that resulted in substantial damage to the Plant Bowen Unit 2 generator, Plant Bowen's Units 1 and 2 control room and surrounding areas, as well as Plant Bowen's switchyard. Plant Bowen Unit 1 (approximately 700 MWs) was returned to service on August 3, 2013. Plant Bowen Unit 2 (approximately 700 MWs) remains offline, pending completion of repairs. Georgia Power expects that any material repair costs related to the damage will be covered by property insurance. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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

Mississippi Power has revised its cost estimate to complete construction of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and the Cost Cap Exceptions. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, excluding the Cost Cap Exceptions and net of the DOE Grants. As a result of the revisions to the cost estimate, Southern Company recorded pretax charges of $540 million and $450 million in the first and second quarters of 2013, respectively. 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 will be reflected in Southern Company's statements of income and these changes could be material. Southern Company's analysis will be ongoing throughout the construction period. Mississippi Power could experience further construction cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, or contractor or supplier delay or non-performance under construction or other agreements. Furthermore, Mississippi Power could also experience schedule delays associated with start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems, which would result in further cost increases or require repayment of a portion of investment tax credits received.

Given the significant judgment involved in estimating the future costs to complete construction, 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 FUTURE EARNINGS POTENTIAL – "Construction Program" of Southern Company in Item 7 of the Form 10-K, 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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Although earnings were negatively affected by the estimated probable losses relating to the Kemper IGCC, Southern Company's financial condition remained stable at June 30, 2013. These non-cash charges for the six months ended June 30, 2013 are expected to result in future cash expenditures with no return or recovery. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $1.9 billion for the first six months of 2013, an increase of $190 million from the corresponding period in 2012. The increase in net cash provided from operating activities was primarily due to a reduction in fossil fuel stock. Net cash used for investing activities totaled $2.6 billion for the first six months of 2013 primarily due to property additions to utility plant. Net cash provided from financing activities totaled $478 million for the first six months of 2013. This was primarily due to long-term debt issuances. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2013 include an increase of $927 million in total property, plant, and equipment for construction of generation, transmission, and distribution facilities. Other significant changes include a $669 million increase in long-term debt (excluding amounts due within a year) to repay maturing debt and to fund the Southern Company subsidiaries' continuous construction programs, a $762 million increase in notes payable primarily due to an increase in commercial paper, and a $491 million decrease in retained earnings resulting from the estimated probable loss on the Kemper IGCC.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The market price of Southern Company's common stock at the end of the second quarter 2013 was $44.13 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $20.64 per share, representing a market-to-book ratio of 214%, compared to $42.81, $21.09, and 203%, respectively, at the end of 2012. The dividend for the second quarter 2013 was $0.5075 per share compared to $0.49 per share in the second quarter 2012.

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, and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $2.1 billion will be required through June 30, 2014 to fund maturities of long-term debt. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information.

The Southern Company system's construction program is estimated to be $6.2 billion for 2013, $6.1 billion for 2014, and $5.2 billion for 2015. Included in these estimated amounts are expenditures related to the construction of the Kemper IGCC of $1.3 billion and $456 million in 2013 and 2014, respectively, which include the current construction cost estimate to complete the Kemper IGCC and are net of SMEPA's 15% proposed ownership share of the Kemper IGCC, which reflects costs of approximately $550 million in 2014. The estimated share for SMEPA reflects estimated construction costs relating to SMEPA's proposed ownership interest (including construction costs for all prior years relating to its proposed ownership interest).

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 the expected environmental compliance program; 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 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 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 "PSC Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2013, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and 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 sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, 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 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 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.46 billion and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. In the event that the DOE does not issue a loan guarantee or Georgia Power determines that the final terms and conditions of the loan guarantee by the DOE are not in the best interest of its customers, Georgia Power expects to finance the construction of Plant Vogtle Units 3 and 4 through traditional capital markets financings. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. The conditional commitment will expire on September 30, 2013, unless further extended by the DOE. See 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 has received DOE Grants of $245 million that have been used for the construction of the Kemper IGCC. An additional $25 million in DOE Grants is expected to be received for the initial operation of the Kemper IGCC. 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.

Southern Company'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 of the Southern Company system. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs which are backed by bank credit facilities.

At June 30, 2013, Southern Company and its subsidiaries had approximately $424 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2013 were as follows:



	Expires^(a)												Executable Term Loans				Due Within One Year
Company	2013		2014		2016		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	77		225		—		1,000		1,302		1,301		53		—		53		99
Georgia Power	—		—		150		1,600		1,750		1,740		—		—		—		—
Gulf Power	20		90		165		—		275		275		45		—		45		65
Mississippi Power	40		95		165		—		300		300		25		40		65		70
Southern Power	—		—		—		500		500		486		—		—		—		—
Other	25		75		—		—		100		100		25		—		25		75
Total	$	162	$	485	$	480	$	4,100	$	5,227	$	5,202	$	148	$	40	$	188	$	309


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

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, 2013 was approximately $1.8 billion.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As reflected in the table above, during the first six months of 2013, Southern Company and certain of its subsidiaries entered into, amended, or renewed certain of their credit arrangements. In February 2013, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended their multi-year credit arrangements, which extended the maturity dates from 2016 to 2018. In March 2013, Gulf Power and Mississippi Power each amended certain of their credit arrangements, which extended the maturity dates from 2014 to 2016 and, in the case of Mississippi Power, also revised the definition of debt to exclude securitized debt relating to the Kemper IGCC for purposes of calculating the debt covenant under these credit arrangements. 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.

Subsequent to June 30, 2013, Alabama Power amended a $10 million credit arrangement, which extended the maturity date from 2013 to 2014. In addition, subsequent to June 30, 2013, Alabama Power amended a $35 million credit arrangement, which extended the maturity date from 2013 to 2015.

Subsequent to June 30, 2013, SEGCO amended a $25 million credit arrangement, which extended the maturity date from 2013 to 2015.

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

Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants.

The traditional operating companies 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 each of the traditional operating companies.

Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 2013				Short-term Debt During the Period^(a)(b)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	1,462	0.2	%	$	1,167	0.3	%	$	1,616
Short-term bank debt	125		1.2	%	152		1.0	%	300
Total	$	1,587	0.3	%	$	1,319	0.3	%

(a) Excludes notes payable related to other energy service contracts of $2 million.

(b) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2013.

Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

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, emissions allowances, energy price risk management, and construction of new generation.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at June 30, 2013 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	592
Below BBB- and/or Baa3	2,606

In March 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 9.967% per annum for 2012 and 9.962% per annum at June 30, 2013, and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. On July 18, 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposit.

On May 24, 2013, S&P revised the ratings outlook for Southern Company and the traditional operating companies from stable to negative.

On May 30, 2013, Moody's placed the ratings of Mississippi Power on review for possible downgrade.

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.

Market Price Risk

The Southern Company system is exposed to market risks, primarily commodity price risk and interest rate risk. The Southern Company system may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the applicable company's policies in areas such as counterparty exposure and risk management practices. The Southern Company system'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.

Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. Southern Company had no material change in market risk exposure for the second quarter 2013 when compared to the December 31, 2012 reporting period.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and six months ended June 30, 2013 were as follows:



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(13	)	$	(85	)
Contracts realized or settled	4			29
Current period changes^(a)	(64		)	(17		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(73	)	$	(73	)


(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2013 were as follows:



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$	(45	)	$	13
Natural gas options	(15		)	(1		)
Total changes	$	(60	)	$	12

The net hedge volumes of energy-related derivative contracts were as follows:



	June 30, 2013	March 31, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	194	170	171
Commodity – Natural gas options	76	89	105
Total hedge volume	270	259	276

The weighted average swap contract cost above market prices was approximately $0.28 per mmBtu as of June 30, 2013, $0.05 per mmBtu as of March 31, 2013, and $0.39 per mmBtu as of December 31, 2012. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the natural gas hedge gains and losses are recovered through the traditional operating companies' fuel cost recovery clauses.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:



Asset (Liability) Derivatives	June 30, 2013			December 31, 2012
	(in millions)
Regulatory hedges	$	(74	)	$	(86	)
Cash flow hedges	—			—
Not designated	1			1
Total fair value	$	(73	)	$	(85	)

Energy-related derivative contracts which are designated as regulatory hedges relate 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 they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. 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.

Total net unrealized pre-tax gains (losses) recognized in the statements of income for the three and six months ended June 30, 2013 and 2012 were not material.

Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at June 30, 2013 were as follows:



	June 30, 2013 Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2	(73		)	(48		)	(26		)	1
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(73	)	$	(48	)	$	(26	)	$	1

For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company in Item 7 and Note 1 under "Financial Instruments" and Note 11 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

During the first six months of 2013, Southern Company issued approximately 6.1 million shares of common stock for approximately $182 million through the employee and director stock plans, of which 0.7 million shares related to Southern Company's performance share plan. Since mid-2011, Southern Company has issued additional equity only through its employee and director stock plans. In July 2012, Southern Company announced a program to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. As of December 31, 2012, Southern Company had repurchased a total of approximately 9 million shares at a total cost of approximately $430 million under this program. In January 2013, Southern Company announced that it planned to continue this program through 2015. There were no repurchases under this program in the first six months of 2013 and no further repurchases under the program are anticipated.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In addition, 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 the independent plan administrators. Southern Company expects to begin issuing new shares directly under these plans in August 2013.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2013:



Company^(a)	Senior Note Issuances		Senior Note Redemptions and Maturities		Revenue Bond Issuances		Revenue Bond Redemptions		Other Long-Term Debt Issuances
					(in millions)
Georgia Power	$	650	$	650	$	18	$	18	$	—
Gulf Power	90		—		—		—		—
Mississippi Power	—		—		16		—		350
Southern Power	—		—		—		—		10
Other	—		50		—		—		—
Total	$	740	$	700	$	34	$	18	$	360

(a) Southern Company and Alabama Power did not issue or redeem any long-term debt during the first six months of 2013.

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

In March 2013, Georgia Power entered into three 60-day floating rate bank loans bearing interest based on one-month LIBOR. Each of these short-term loans was for $100 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Georgia Power's continuous construction program. These bank loans were repaid at maturity.

In June 2013, Gulf Power entered into a three-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $125 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Gulf Power’s continuous construction program. This bank loan was repaid in July 2013.

Gulf Power purchased and held $42 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Company Plant Scherer Project), First Series 2002 (First Series 2002 Bonds) and $21 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Company Plant Scherer Project), First Series 2010 (First Series 2010 Bonds) in May 2013 and June 2013, respectively. In June 2013, Gulf Power reoffered the First Series 2002 Bonds and the First Series 2010 Bonds to the public.

In June 2013, Gulf Power issued 500,000 shares of Series 2013A 5.60% Preference Stock and realized proceeds of $50 million. The proceeds from the sale of the Preference Stock, together with the proceeds from the issuance of the $90 million aggregate principal amount of Gulf Power's Series 2013A 5.00% Senior Notes reflected in the table above, were used to repay at maturity $60 million aggregate principal amount of Gulf Power's Series G 4.35% Senior Notes due July 15, 2013, to repay a portion of a three-month floating rate bank loan in an aggregate principal amount outstanding of $125 million, for a portion of the redemption in July 2013 of $30 million aggregate principal amount outstanding of Gulf Power’s Series H 5.25% Senior Notes due July 15, 2033, and for general corporate purposes, including Gulf Power’s continuous construction program.

Subsequent to June 30, 2013, Southern Power issued $300 million aggregate principal amount of Series 2013A 5.25% Senior Notes due July 15, 2043. The net proceeds from the sale of the Series 2013A Senior Notes were used to repay a portion of its outstanding short-term indebtedness and for other general corporate purposes, including Southern Power’s continuous construction program.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to June 30, 2013, Mississippi Business Finance Corporation (MBFC) issued $15.3 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A. The proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. See Note 6 to the financial statements of Southern Company under "Other Revenue Bonds" in Item 8 of the Form 10-K for additional information.

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.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein for each registrant 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.

Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power

As of the end of the period covered by this quarterly report, Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power 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.

Mississippi Power

As described further in Notes 3 and 12 to the financial statements of Mississippi Power in Item 8 and Management's Report on Internal Control Over Financial Reporting in Item 9A of the Form 10-K/A, Mississippi Power restated and corrected its previously issued financial statements for the year ended December 31, 2012 to recognize a pretax charge for an estimated probable loss relating to the Kemper IGCC.

Mississippi Power reported in Item 4(a) of its Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 that management determined that Mississippi Power's failure to maintain sufficient evidence supporting certain estimated amounts included in the Kemper IGCC cost estimate and to fully communicate the related effects in the development of the Kemper IGCC cost estimate constituted a material weakness in internal control over financial reporting under the standards adopted by the Public Company Accounting Oversight Board. Mississippi Power's management implemented the following actions in the second quarter 2013 to remediate the material weakness in internal control over financial reporting:


•	established a new governance team focused on accounting, legal, and regulatory affairs that meets

regularly with the Kemper IGCC project and construction teams and provides further oversight around disclosures of the Kemper IGCC cost estimation process and schedule;


•	refined and enhanced project cost estimation methodologies and related documentation;


•	re-emphasized and enhanced communication across functional areas and departments; and


•	applied appropriate performance management actions.

While these actions were implemented during the quarter ended June 30, 2013, Mississippi Power's management's assessment as to their effectiveness will not be completed until the end of the third quarter 2013.

Therefore, as of the end of the period covered by this quarterly report, Mississippi Power conducted an evaluation under the supervision and with the participation of 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 this evaluation, which considered the material weakness described above, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures for this period were not effective.


(b)	Changes in internal controls.

Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, or Southern Power'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 2013 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, or Southern Power's internal control over financial reporting.

Mississippi Power

Other than implementation of the remedial actions described above under Item 4(a), there have been no changes in Mississippi Power'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 2013 that have materially affected or are reasonably likely to materially affect Mississippi Power'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,
	2013			2012			2013			2012
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,221		$	1,254		$	2,362		$	2,346
Wholesale revenues, non-affiliates	61			70			120			131
Wholesale revenues, affiliates	60			6			116			20
Other revenues	50			47			102			96
Total operating revenues	1,392			1,377			2,700			2,593
Operating Expenses:
Fuel	401			343			773			649
Purchased power, non-affiliates	28			17			48			32
Purchased power, affiliates	41			66			72			106
Other operations and maintenance	319			316			649			637
Depreciation and amortization	159			160			317			317
Taxes other than income taxes	87			85			177			171
Total operating expenses	1,035			987			2,036			1,912
Operating Income	357			390			664			681
Other Income and (Expense):
Allowance for equity funds used during construction	8			4			16			9
Interest expense, net of amounts capitalized	(65		)	(73		)	(131		)	(146		)
Other income (expense), net	2			—			1			(3		)
Total other income and (expense)	(55		)	(69		)	(114		)	(140		)
Earnings Before Income Taxes	302			321			550			541
Income taxes	119			126			216			210
Net Income	183			195			334			331
Dividends on Preferred and Preference Stock	10			10			20			20
Net Income After Dividends on Preferred and Preference Stock	$	173		$	185		$	314		$	311

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2013		2012			2013		2012
	(in millions)					(in millions)
Net Income	$	183	$	195		$	334	$	331
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(7), $- and $(4), respectively	—		(11		)	—		(7		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	1		—			1		—
Total other comprehensive income (loss)	1		(11		)	1		(7		)
Comprehensive Income	$	184	$	184		$	335	$	324

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,
	2013			2012
	(in millions)
Operating Activities:
Net income	$	334		$	331
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	403			380
Deferred income taxes	53			85
Allowance for equity funds used during construction	(16		)	(9		)
Stock based compensation expense	6			6
Other, net	(18		)	(33		)
Changes in certain current assets and liabilities —
-Receivables	(65		)	(46		)
-Fossil fuel stock	76			(125		)
-Materials and supplies	22			(6		)
-Other current assets	(45		)	(31		)
-Accounts payable	(93		)	(145		)
-Accrued taxes	60			128
-Accrued compensation	(54		)	(45		)
-Retail fuel cost over recovery	12			2
-Other current liabilities	4			(11		)
Net cash provided from operating activities	679			481
Investing Activities:
Property additions	(518		)	(436		)
Nuclear decommissioning trust fund purchases	(120		)	(88		)
Nuclear decommissioning trust fund sales	120			88
Cost of removal, net of salvage	(19		)	(7		)
Change in construction payables	(21		)	(12		)
Other investing activities	30			(9		)
Net cash used for investing activities	(528		)	(464		)
Financing Activities:
Increase in notes payable, net	46			—
Proceeds —
Capital contributions from parent company	10			11
Senior notes issuances	—			250
Redemptions —
Pollution control revenue bonds	—			(1		)
Senior notes	—			(250		)
Payment of preferred and preference stock dividends	(20		)	(20		)
Payment of common stock dividends	(265		)	(270		)
Other financing activities	—			(3		)
Net cash used for financing activities	(229		)	(283		)
Net Change in Cash and Cash Equivalents	(78		)	(266		)
Cash and Cash Equivalents at Beginning of Period	137			344
Cash and Cash Equivalents at End of Period	$	59		$	78
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $6 and $3 capitalized for 2013 and 2012, respectively)	$	119		$	136
Income taxes, net	146			31
Noncash transactions—accrued property additions at end of period	10			7

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, 2013			At December 31, 2012
	(in millions)
Current Assets:
Cash and cash equivalents	$	59		$	137
Receivables —
Customer accounts receivable	380			321
Unbilled revenues	160			138
Under recovered regulatory clause revenues	8			23
Other accounts and notes receivable	55			42
Affiliated companies	36			55
Accumulated provision for uncollectible accounts	(9		)	(8		)
Fossil fuel stock, at average cost	399			475
Materials and supplies, at average cost	364			395
Vacation pay	61			61
Prepaid expenses	97			81
Other regulatory assets, current	16			24
Other current assets	3			13
Total current assets	1,629			1,757
Property, Plant, and Equipment:
In service	21,674			21,407
Less accumulated provision for depreciation	7,916			7,761
Plant in service, net of depreciation	13,758			13,646
Nuclear fuel, at amortized cost	366			354
Construction work in progress	555			438
Total property, plant, and equipment	14,679			14,438
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	55			53
Nuclear decommissioning trusts, at fair value	644			605
Miscellaneous property and investments	77			78
Total other property and investments	776			736
Deferred Charges and Other Assets:
Deferred charges related to income taxes	523			525
Deferred under recovered regulatory clause revenues	22			11
Other regulatory assets, deferred	1,075			1,083
Other deferred charges and assets	134			162
Total deferred charges and other assets	1,754			1,781
Total Assets	$	18,838		$	18,712

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, 2013			At December 31, 2012
	(in millions)
Current Liabilities:
Securities due within one year	$	250		$	250
Notes payable	46			—
Accounts payable —
Affiliated	175			191
Other	228			318
Customer deposits	86			85
Accrued taxes —
Accrued income taxes	49			5
Other accrued taxes	82			33
Accrued interest	65			62
Accrued vacation pay	50			50
Accrued compensation	42			94
Liabilities from risk management activities	10			14
Other regulatory liabilities, current	16			3
Other current liabilities	37			38
Total current liabilities	1,136			1,143
Long-term Debt	5,934			5,929
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,443			3,404
Deferred credits related to income taxes	77			79
Accumulated deferred investment tax credits	137			141
Employee benefit obligations	310			321
Asset retirement obligations	609			589
Other cost of removal obligations	786			759
Other regulatory liabilities, deferred	192			183
Other deferred credits and liabilities	63			81
Total deferred credits and other liabilities	5,617			5,557
Total Liabilities	12,687			12,629
Redeemable Preferred Stock	342			342
Preference Stock	343			343
Common Stockholder's Equity:
Common stock, par value $40 per share —
Authorized - 40,000,000 shares
Outstanding - 30,537,500 shares	1,222			1,222
Paid-in capital	2,245			2,227
Retained earnings	2,026			1,976
Accumulated other comprehensive loss	(27		)	(27		)
Total common stockholder's equity	5,466			5,398
Total Liabilities and Stockholder's Equity	$	18,838		$	18,712

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2013 vs. SECOND QUARTER 2012

AND

YEAR-TO-DATE 2013 vs. YEAR-TO-DATE 2012

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located within the State of Alabama in addition to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Alabama Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, 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

Alabama Power's net income after dividends on preferred and preference stock for the second quarter 2013 was $173 million compared to $185 million for the corresponding period in 2012. The decrease in net income was related to less favorable weather in the second quarter 2013 as compared to the corresponding period in 2012 and a decrease in revenues related to Rate Certificated New Plant Environmental (Rate CNP Environmental), partially offset by an increase in sales growth due to an increase in industrial KWH sales and a decrease in interest expense. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate CNP" herein for additional information.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2013 was $314 million compared to $311 million for the corresponding period in 2012. The increase in net income was related to more favorable weather for year-to-date 2013 as compared to the corresponding period in 2012 and a decrease in interest expense, partially offset by a decrease in revenues related to Rate CNP Environmental and increases in other operations and maintenance expenses.

Retail Revenues

In the second quarter 2013, retail revenues were $1.22 billion compared to $1.25 billion for the corresponding period in 2012. For year-to-date 2013, retail revenues were $2.36 billion compared to $2.35 billion for the corresponding period in 2012.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:



	Second Quarter 2013					Year-to-Date 2013
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,254				$	2,346
Estimated change in –
Rates and pricing	(11		)	(0.9	)	(12		)	(0.5	)
Sales growth (decline)	10			0.8		1			—
Weather	(26		)	(2.0	)	13			0.6
Fuel and other cost recovery	(6		)	(0.5	)	14			0.6
Retail – current year	$	1,221		(2.6	)%	$	2,362		0.7	%

Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2013 when compared to the corresponding periods in 2012 due to decreased revenues associated with Rate CNP Environmental as a result of a decrease in the net investment associated with projects related to environmental mandates.

Revenues attributable to changes in sales increased in the second quarter and year-to-date 2013 when compared to the corresponding periods in 2012. Industrial KWH energy sales increased 3.5% in the second quarter 2013 and 2.0% for year-to-date 2013 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, forest products, and stone, clay, and glass sectors, partially offset by decreases in pipelines and military sectors. Weather-adjusted residential KWH energy sales increased 0.2% in the second quarter 2013 as a result of customer growth and decreased 1.1% for year-to-date 2013 as a result of decreased customer usage. Weather-adjusted commercial KWH energy sales increased 0.3% in the second quarter 2013 as a result of increased customer usage. Weather-adjusted commercial KWH energy sales remained flat for year-to-date 2013. In addition, an extra day of sales as a result of the leap year in 2012 negatively impacted KWH sales in all customer classes in 2013.

Revenues resulting from changes in weather decreased in the second quarter 2013 due to less favorable weather experienced in Alabama Power's service territory compared to the corresponding period in 2012. For the second quarter 2013, the resulting decreases were 3.2% and 2.4% for residential and commercial sales revenue, respectively.

Revenues resulting from changes in weather increased year-to-date 2013 due to more favorable weather experienced in Alabama Power's service territory in the first quarter 2013 compared to the corresponding period in 2012. For year-to-date 2013, residential sales revenue increased 2.2% and commercial sales revenue decreased 1.2%.

Fuel and other cost recovery revenues decreased in the second quarter 2013 when compared to the corresponding period in 2012 primarily due to lower fuel costs resulting from an increase in hydro generation. Fuel and other cost recovery revenues increased year-to-date 2013 when compared to the corresponding period in 2012 primarily due to an increase in fuel costs associated with an increase in KWHs generated. 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 NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Wholesale revenues from sales to non-affiliates will vary depending on the market prices of available wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

In the second quarter 2013, wholesale revenues from non-affiliates were $61 million compared to $70 million for the corresponding period in 2012. The decrease was primarily due to a 14.2% decrease in KWH sales offset by a 2.0% increase in the price of energy. For year-to-date 2013, wholesale revenues from non-affiliates were $120 million compared to $131 million for the corresponding period in 2012. The decrease was primarily due to an 8.1% decrease in KWH sales.

Wholesale Revenues – Affiliates

N/M – Not meaningful

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 2013, wholesale revenues from affiliates were $60 million compared to $6 million for the corresponding period in 2012. The increase was primarily due to a 799.0% increase in KWH sales and a 13.0% increase in the price of energy.

For year-to-date 2013, wholesale revenues from affiliates were $116 million compared to $20 million for the corresponding period in 2012. The increase was due to a 411.3% increase in KWH sales and a 12.8% increase in the price of energy.

Fuel and Purchased Power Expenses



	Second Quarter 2013 vs. Second Quarter 2012					Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	58		16.9		$	124		19.1
Purchased power – non-affiliates	11			64.7		16			50.0
Purchased power – affiliates	(25		)	(37.9	)	(34		)	(32.1	)
Total fuel and purchased power expenses	$	44				$	106

In the second quarter 2013, total fuel and purchased power expenses were $470 million compared to $426 million for the corresponding period in 2012. The increase was primarily due to a $34 million increase associated with an increase in the volume of KWHs generated, a $25 million increase in the average cost of fuel, and a $16 million

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

For year-to-date 2013, total fuel and purchased power expenses were $893 million compared to $787 million for the corresponding period in 2012. The increase was primarily due to a $94 million increase associated with an increase in the volume of KWHs generated, a $31 million increase in the average cost of fuel, and a $20 million increase in the average cost of purchased power, partially offset by a $40 million decrease related to the volume of KWHs purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clauses. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billings rates are required. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Energy Cost Recovery" herein for additional information.

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



	Second Quarter 2013	Second Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (billions of KWHs)	16	13	32	27
Total purchased power (billions of KWHs)	1	2	2	3
Sources of generation (percent) —
Coal	54	53	51	48
Nuclear	20	24	22	26
Gas	16	21	16	20
Hydro	10	2	11	6
Cost of fuel, generated (cents per net KWH) —
Coal	3.34	3.29	3.35	3.35
Nuclear	0.83	0.82	0.82	0.78
Gas	3.59	2.76	3.44	2.88
Average cost of fuel, generated (cents per net KWH)^(a)	2.83	2.57	2.74	2.54
Average cost of purchased power (cents per net KWH)^(b)	5.01	3.89	4.99	4.14


(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 2013, fuel expense was $401 million compared to $343 million for the corresponding period in 2012. The $58 million increase was primarily due to an 18.2% increase in KWHs generated by coal and a 30.1% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements. This increase was partially offset by a 420.2% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall and a 10.8% decrease in KWHs generated by natural gas.

For year-to-date 2013, fuel expense was $773 million compared to $649 million for the corresponding period in 2012. The $124 million increase was due to a 24.1% increase in KWHs generated by coal and a 19.4% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements. This increase was offset by a 98.5% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Non-Affiliates

In the second quarter 2013, purchased power expense from non-affiliates was $28 million compared to $17 million for the corresponding period in 2012. The increase was related to a 114.8% increase in the amount of energy purchased, partially offset by a 31.1% decrease in the average cost per KWH.

For year-to-date 2013, purchased power expense from non-affiliates was $48 million compared to $32 million for the corresponding period in 2012. The increase was related to a 93.2% increase in the amount of energy purchased, partially offset by a 26.9% decrease in the average cost per KWH.

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 2013, purchased power expense from affiliates was $41 million compared to $66 million for the corresponding period in 2012. The decrease was related to a 61.2% decrease in the amount of energy purchased, partially offset by a 61.4% increase in the average cost per KWH.

For year-to-date 2013, purchased power expense from affiliates was $72 million compared to $106 million for the corresponding period in 2012. The decrease was related to a 57.0% decrease in the amount of energy purchased, partially offset by a 58.1% increase in the average cost per KWH.

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

In the second quarter 2013, other operations and maintenance expenses were $319 million compared to $316 million for the corresponding period in 2012. The increase was not material.

For year-to-date 2013, other operations and maintenance expenses were $649 million compared to $637 million for the corresponding period in 2012. Nuclear production expenses increased $9 million primarily due to the amortization of nuclear outage expenses. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Nuclear Outage Accounting Order" of Alabama Power in Item 7 of the Form 10-K for additional information. Distribution and transmission expenses increased $6 million due to increases in materials and labor expenses. Steam heat decreased $3 million due to steam heat operations being discontinued in the second quarter 2013.

Depreciation and Amortization

In the second quarter 2013, depreciation and amortization was $159 million compared to $160 million for the corresponding period in 2012. The decrease was not material.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2013 and for the corresponding period in 2012, depreciation and amortization was $317 million. While depreciation and amortization expense was flat compared to the corresponding period in 2012, there were increases of $9 million primarily due to additions to property, plant, and equipment related to distribution and transmission, as well as the amortization of software. These increases were offset by a decrease related to the deferral of certain expenses under an accounting order. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Compliance and Cost Accounting Order" of Alabama Power in Item 7 and Note 3 to the financial statements under "Compliance and Cost Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's deferral of costs under this accounting order.

Allowance for Equity Funds Used During Construction

In the second quarter 2013, AFUDC equity was $8 million compared to $4 million for the corresponding period in 2012. The increase was primarily due to an increase in capital expenditures for steam generating and environmental and nuclear generating facilities.

For year-to-date 2013, AFUDC equity was $16 million compared to $9 million for the corresponding period in 2012. The increase was primarily due to an increase in capital expenditures for steam generating and environmental, transmission, and nuclear generating facilities.

Interest Expense, Net of Amounts Capitalized

In the second quarter 2013, interest expense, net of amounts capitalized was $65 million compared to $73 million for the corresponding period in 2012. For year-to-date 2013, interest expense, net of amounts capitalized was $131 million compared to $146 million for the corresponding period in 2012. These decreases were primarily due to a decrease in interest rates and the timing of issuances and redemptions of long term-debt.

Income Taxes

In the second quarter 2013, income taxes were $119 million compared to $126 million for the corresponding period in 2012. The decrease was primarily due to lower pre-tax earnings.

For year-to-date 2013, income taxes were $216 million compared to $210 million for the corresponding period in 2012. The increase was primarily due to higher pre-tax earnings and the recognition in 2012 of previously unrecognized tax benefits as a result of a settlement with the IRS related to the production activities deduction. See Note 5 to the financial statements of Alabama Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information on the settlement with the IRS.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of 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 energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced 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.

Climate Change Litigation

Kivalina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

Hurricane Katrina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On May 14, 2013, the U.S. Court of Appeals for the Fifth Circuit upheld the U.S. District Court for the Southern District of Mississippi's dismissal of the case. The decision is subject to appeal; therefore, the ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding Alabama's State Implementation Plan requirements related to opacity, the EPA's MATS rule, the Cross State Air Pollution Rule, and the EPA's SO₂ rule.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On July 25, 2013, the EPA issued initial nonattainment area designations under the one-hour National Ambient Air Quality Standard for SO₂ based on ambient air quality monitoring data. No areas within Alabama Power's service territory were designated as nonattainment under this rule. The EPA has deferred designation of attainment and unclassifiable areas and may designate additional areas as nonattainment in the future, which could include areas within Alabama Power's service territory. The ultimate outcome of this matter 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 proposed revision of the current steam electric effluent guidelines and rule for cooling water intake structures.

On June 7, 2013, the EPA published a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Alabama Power's facilities, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the proposed regulation of greenhouse gas emissions through establishment of new source performance standards.

Although the outcome of the proposed regulations and guidelines cannot be determined at this time, additional restrictions on Alabama Power's greenhouse gas emissions at the federal or state level could result in significant additional compliance costs, including capital expenditures. These costs could affect future unit retirement and replacement decisions. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

PPAs. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's Warrior River hydroelectric license, Coosa River hydroelectric license, and Martin Dam Project license.

On March 18, 2013, the Smith Lake Improvement and Stakeholders' Association filed an appeal to the U.S. Court of Appeals for the District of Columbia Circuit regarding the FERC's orders related to the Warrior River relicensing proceedings.

On June 18, 2013, the FERC issued an annual license to Alabama Power for the Martin Dam Project, pending FERC action on the license application.

On June 20, 2013, the FERC entered an order granting Alabama Power's application for relicensing of Alabama Power's seven hydroelectric developments on the Coosa River for 30 years. On July 22, 2013, Alabama Power filed a petition requesting rehearing of the FERC order granting the relicense seeking revisions to several conditions of the license. The Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission have also filed petitions for rehearing of the FERC order.

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

PSC Matters

Rate RSE

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate RSE" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information regarding Alabama Power's Rate Stabilization and Equalization (Rate RSE). In May, June, and July 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. The ultimate outcome of these proceedings cannot be determined at this time.

Rate CNP

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Rate Adjustments – Rate CNP" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP PPA) and Rate CNP Environmental. Alabama Power's under recovered Rate CNP PPA balance at June 30, 2013 and December 31, 2012 was $9 million. This under recovered balance at June 30, 2013 is included in deferred under recovered regulatory clause revenues on Alabama Power's Condensed Balance Sheet herein. For Rate CNP PPA, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs. Alabama Power's under recovered Rate CNP Environmental balance at June 30, 2013 and December 31, 2012 was $21 million. This under recovered balance at June 30, 2013 consists of $8 million in under recovered regulatory clause revenues and $13 million in deferred under recovered regulatory clause revenues on Alabama Power's Condensed Balance Sheet herein. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On August 1, 2013, Alabama Power filed a petition with the Alabama PSC requesting a revision to Rate CNP Environmental that would allow recovery of costs related to pre-2005 environmental assets currently being recovered through Rate RSE. The revenue impact as a result of this proposed revision is estimated to be $50 million in 2014; however, this petition is being made in accordance with Alabama Power's agreement with the Alabama PSC to develop a plan to keep Rate RSE and Rate CNP Environmental factors unchanged in 2014. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate RSE" in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information. Any unrecovered amounts associated with 2014 environmental compliance costs will be reflected in the 2015 Rate CNP Environmental filing. This petition is subject to the Alabama PSC's approval. The ultimate outcome of this matter cannot be determined at this time.

Retail Energy Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Energy Cost Recovery" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Energy Cost Recovery" in Item 8 of the Form 10-K for information regarding Alabama Power's energy cost recovery. Alabama Power's over recovered fuel costs at June 30, 2013 totaled $13 million as compared to an under recovered balance of $4 million at December 31, 2012. The over recovered fuel costs at June 30, 2013 are included in other regulatory liabilities, current and the under recovered fuel costs at December 31, 2012 are included in deferred under recovered regulatory clause revenues on Alabama Power's Condensed Balance Sheet herein. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs.

Natural Disaster Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Natural Disaster Reserve" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Natural Disaster Reserve" in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2013, the NDR had an accumulated balance of $95 million as compared to $103 million at December 31, 2012, which is included on Alabama Power's Condensed Balance Sheet herein under other regulatory liabilities, deferred. The decrease in the NDR is a result of storm activity. The related accruals are reflected as operations and maintenance expenses on Alabama Power's Condensed Statement of Income herein.

Non-Nuclear Outage Accounting Order

On August 1, 2013, Alabama Power filed a petition with the Alabama PSC requesting authorization to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures proposed to be deferred and amortized are estimated to total approximately $70 million. This petition is being made in accordance with Alabama Power's agreement with the Alabama PSC to develop a plan to keep Rate RSE factors unchanged in 2014. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate RSE" in Item 7 and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information. This petition is subject to the Alabama PSC's approval. 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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.

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.

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.

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, 2013. 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 "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

Net cash provided from operating activities totaled $679 million for the first six months of 2013, an increase of $198 million as compared to the first six months of 2012. The increase in net cash provided from operating activities was primarily due to a decrease in fossil fuel stock, an increase in accounts payable as compared to the first six months of 2012, and the timing of income tax payments and refunds. Net cash used for investing activities totaled $528 million for the first six months of 2013 primarily due to gross property additions related to distribution, steam generation, and transmission equipment. Net cash used for financing activities totaled $229 million for the first six months of 2013 primarily due to the payment of common stock dividends, partially offset by an increase in notes payable. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant balance sheet changes for the first six months of 2013 include an increase of $241 million in property, plant, and equipment, primarily due to additions to distribution, steam, and transmission facilities and decreases of $90 million in other accounts payable associated with the timing of property tax payments, $78 million in cash and cash equivalents primarily due to an effort to reduce bank balances, and $76 million in fossil fuel stock, at average cost, as a result of an increase in KWHs generated by coal.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. Approximately $250 million will be required through June 30, 2014 to fund maturities of long-term debt.

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 regulatory approval, prevailing market conditions, 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, 2013, Alabama Power had approximately $59 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2013 were as follows:



Expires^(a)										Executable Term Loans				Due Within One Year
2013		2014		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	77	$	225	$	1,000	$	1,302	$	1,301	$	53	$	—	$	53	$	99


(a)	No credit arrangements expire in 2015, 2016, or 2017.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

These credit arrangements provide liquidity support to Alabama Power's commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2013 was approximately $793 million. 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.

As reflected in the table above, during the first six months of 2013, Alabama Power amended or renewed certain of its credit arrangements. In February 2013, Alabama Power amended an $800 million multi-year credit arrangement, which extended the maturity date from 2016 to 2018. In addition, in March 2013, Alabama Power amended a $200 million credit arrangement, which extended the maturity date from 2014 to 2018. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration.

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.

Most of these arrangements contain covenants that limit debt levels and contain cross default provisions that are restricted only to the indebtedness (including guarantee obligations) of Alabama Power. Alabama Power is currently in compliance with all such covenants.

Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 2013		Short-term Debt During the Period^(a)
	Amount Outstanding	Weighted Average Interest Rate	Average Outstanding	Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)		(in millions)		(in millions)
Commercial paper	$46	0.2%	$25	0.2%	$90


(a)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2013.

Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At June 30, 2013, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $292 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

On May 24, 2013, S&P revised the ratings outlook for Southern Company and the traditional operating companies, including Alabama Power, from stable to negative.

Market Price Risk

Alabama Power's market risk exposure relative to interest rate changes for the second quarter 2013 has not changed materially compared to the December 31, 2012 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As a result, Alabama Power had no material change in market risk exposure for the second quarter 2013 when compared with the December 31, 2012 reporting period.

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and six months ended June 30, 2013 were as follows:



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	5		$	(13	)
Contracts realized or settled	—			6
Current period changes^(a)	(16		)	(4		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(11	)	$	(11	)

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$	(13	)	$	3
Natural gas options	(3		)	(1		)
Total changes	$	(16	)	$	2

The net hedge volumes of energy-related derivative contracts were as follows:



	June 30, 2013	March 31, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	60	47	45
Commodity – Natural gas options	8	10	12
Total hedge volume	68	57	57

The weighted average swap contract cost above market prices was approximately $0.18 per mmBtu as of June 30, 2013 and approximately $0.30 per mmBtu as of December 31, 2012. The weighted average swap contract cost below market prices was approximately $0.04 per mmBtu as of March 31, 2013. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the natural gas hedge gains and losses are recovered through Alabama Power's retail fuel cost recovery clause.

Regulatory hedges relate to Alabama Power's fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Alabama Power's energy recovery clause.

Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2013 and 2012 for energy-related derivative contracts that are not hedges were not material.

Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at June 30, 2013 were as follows:



	June 30, 2013 Fair Value Measurements
	Total Fair Value			Maturity
	Total Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2	(11		)	(8		)	(3		)	—
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(11	)	$	(8	)	$	(3	)	$	—

For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Alabama Power in Item 7 and Note 1 under "Financial Instruments"

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

and Note 11 to the financial statements of Alabama Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

Alabama Power did not issue or redeem any securities during the six months ended June 30, 2013.

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

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GEORGIA POWER COMPANY

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,879		$	1,857		$	3,608		$	3,451
Wholesale revenues, non-affiliates	73			75			135			141
Wholesale revenues, affiliates	5			6			11			9
Other revenues	85			82			170			164
Total operating revenues	2,042			2,020			3,924			3,765
Operating Expenses:
Fuel	557			572			1,076			1,012
Purchased power, non-affiliates	61			94			111			187
Purchased power, affiliates	176			129			351			288
Other operations and maintenance	397			411			828			845
Depreciation and amortization	204			185			404			373
Taxes other than income taxes	95			94			190			181
Total operating expenses	1,490			1,485			2,960			2,886
Operating Income	552			535			964			879
Other Income and (Expense):
Allowance for equity funds used during construction	7			13			13			26
Interest expense, net of amounts capitalized	(96		)	(90		)	(187		)	(181		)
Other income (expense), net	1			(6		)	(1		)	(9		)
Total other income and (expense)	(88		)	(83		)	(175		)	(164		)
Earnings Before Income Taxes	464			452			789			715
Income taxes	177			152			301			244
Net Income	287			300			488			471
Dividends on Preferred and Preference Stock	5			5			9			9
Net Income After Dividends on Preferred and Preference Stock	$	282		$	295		$	479		$	462

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
	(in millions)				(in millions)
Net Income	$	287	$	300	$	488	$	471
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $1 and $1, respectively	—		—		1		1
Total other comprehensive income (loss)	—		—		1		1
Comprehensive Income	$	287	$	300	$	489	$	472

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2013			2012
	(in millions)
Operating Activities:
Net income	$	488		$	471
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	487			458
Deferred income taxes	126			128
Allowance for equity funds used during construction	(13		)	(26		)
Retail fuel cost over recovery—long-term	(123		)	44
Deferred expenses	31			26
Other, net	(8		)	(3		)
Changes in certain current assets and liabilities —
-Receivables	(123		)	19
-Fossil fuel stock	56			(147		)
-Prepaid income taxes	5			13
-Other current assets	34			8
-Accounts payable	43			(37		)
-Accrued taxes	(14		)	(77		)
-Accrued compensation	(66		)	(60		)
-Retail fuel cost over recovery—short-term	1			55
-Other current liabilities	7			43
Net cash provided from operating activities	931			915
Investing Activities:
Property additions	(765		)	(812		)
Investment of restricted cash	(18		)	(234		)
Distribution of restricted cash	18			49
Nuclear decommissioning trust fund purchases	(427		)	(488		)
Nuclear decommissioning trust fund sales	426			486
Cost of removal, net of salvage	(27		)	(34		)
Change in construction payables, net of joint owner portion	(2		)	(161		)
Other investing activities	(12		)	(14		)
Net cash used for investing activities	(807		)	(1,208		)
Financing Activities:
Increase (decrease) in notes payable, net	314			(513		)
Proceeds —
Capital contributions from parent company	21			18
Pollution control revenue bonds issuances	18			234
Senior notes issuances	650			1,500
Redemptions —
Pollution control revenue bonds	(18		)	(49		)
Senior notes	(650		)	—
Other long-term debt	—			(250		)
Payment of preferred and preference stock dividends	(9		)	(9		)
Payment of common stock dividends	(454		)	(454		)
Other financing activities	(12		)	(9		)
Net cash (used for) provided from financing activities	(140		)	468
Net Change in Cash and Cash Equivalents	(16		)	175
Cash and Cash Equivalents at Beginning of Period	45			13
Cash and Cash Equivalents at End of Period	$	29		$	188
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $6 and $11 capitalized for 2013 and 2012, respectively)	$	169		$	156
Income taxes, net	100			44
Noncash transactions—accrued property additions at end of period	238			234

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

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2013			At December 31, 2012
	(in millions)
Current Assets:
Cash and cash equivalents	$	29		$	45
Receivables —
Customer accounts receivable	574			484
Unbilled revenues	251			217
Joint owner accounts receivable	58			51
Other accounts and notes receivable	69			68
Affiliated companies	21			23
Accumulated provision for uncollectible accounts	(6		)	(6		)
Fossil fuel stock, at average cost	936			992
Materials and supplies, at average cost	411			452
Vacation pay	85			85
Prepaid income taxes	133			164
Other regulatory assets, current	46			72
Other current assets	48			104
Total current assets	2,655			2,751
Property, Plant, and Equipment:
In service	29,672			29,244
Less accumulated provision for depreciation	10,737			10,431
Plant in service, net of depreciation	18,935			18,813
Other utility plant, net	261			263
Nuclear fuel, at amortized cost	481			497
Construction work in progress	3,206			2,893
Total property, plant, and equipment	22,883			22,466
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	47			45
Nuclear decommissioning trusts, at fair value	708			698
Miscellaneous property and investments	43			44
Total other property and investments	798			787
Deferred Charges and Other Assets:
Deferred charges related to income taxes	719			733
Other regulatory assets, deferred	1,801			1,798
Other deferred charges and assets	271			268
Total deferred charges and other assets	2,791			2,799
Total Assets	$	29,127		$	28,803

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

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2013			At December 31, 2012
	(in millions)
Current Liabilities:
Securities due within one year	$	1,030		$	1,680
Notes payable	314			2
Accounts payable —
Affiliated	407			417
Other	498			436
Customer deposits	243			237
Accrued taxes —
Accrued income taxes	85			6
Other accrued taxes	185			260
Accrued interest	105			100
Accrued vacation pay	60			61
Accrued compensation	51			113
Liabilities from risk management activities	21			30
Other regulatory liabilities, current	35			73
Over recovered regulatory clause revenues, current	108			107
Other current liabilities	140			146
Total current liabilities	3,282			3,668
Long-term Debt	8,640			7,994
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,956			4,861
Deferred credits related to income taxes	114			115
Accumulated deferred investment tax credits	208			208
Employee benefit obligations	941			950
Asset retirement obligations	1,170			1,097
Other cost of removal obligations	67			63
Other deferred credits and liabilities	155			308
Total deferred credits and other liabilities	7,611			7,602
Total Liabilities	19,533			19,264
Preferred Stock	45			45
Preference Stock	221			221
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares	398			398
Paid-in capital	5,615			5,585
Retained earnings	3,321			3,297
Accumulated other comprehensive loss	(6		)	(7		)
Total common stockholder's equity	9,328			9,273
Total Liabilities and Stockholder's Equity	$	29,127		$	28,803

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2013 vs. SECOND QUARTER 2012

AND

YEAR-TO-DATE 2013 vs. YEAR-TO-DATE 2012

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, and fuel. In addition, Georgia Power is currently constructing Plant Vogtle Units 3 and 4 to increase its generation diversity. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future. In accordance with the 2010 ARP, Georgia Power filed a base rate case with the Georgia PSC on June 28, 2013, requesting a base rate increase effective January 1, 2014. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate Plans" herein for additional information.

Georgia 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 Georgia Power in Item 7 of the Form 10-K. See FUTURE EARNINGS POTENTIAL – "Other Matters" herein for information regarding an explosion at Plant Bowen in April 2013 that is expected to negatively impact Georgia Power's actual performance on its peak season equivalent forced outage rate, one of its key performance indicators, for 2013, as compared to the target.

RESULTS OF OPERATIONS

Net Income

Georgia Power's net income after dividends on preferred and preference stock for the second quarter 2013 was $282 million compared to $295 million for the corresponding period in 2012. The decrease was primarily due to higher income taxes and an increase in depreciation and amortization, partially offset by an increase in retail base revenues and lower non-fuel operations and maintenance expenses.

Georgia Power's net income after dividends on preferred and preference stock for year-to-date 2013 was $479 million compared to $462 million for the corresponding period in 2012. The increase was primarily due to an increase in retail base revenues and lower non-fuel operations and maintenance expenses, partially offset by higher income taxes and an increase in depreciation and amortization.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

In the second quarter 2013, retail revenues were $1.88 billion compared to $1.86 billion for the corresponding period in 2012. For year-to-date 2013, retail revenues were $3.61 billion compared to $3.45 billion for the corresponding period in 2012.

Details of the changes in retail revenues were as follows:



	Second Quarter 2013					Year-to-Date 2013
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,857				$	3,451
Estimated change in –
Rates and pricing	61			3.3		106			3.1
Sales growth (decline)	(26		)	(1.4	)	(24		)	(0.7	)
Weather	(23		)	(1.2	)	(3		)	(0.1	)
Fuel cost recovery	10			0.5		78			2.2
Retail – current year	$	1,879		1.2	%	$	3,608		4.5	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2013 when compared to the corresponding periods in 2012 primarily due to base tariff increases effective April 2012 and January 1, 2013, as approved by the Georgia PSC, related to placing new generating units at Plant McDonough-Atkinson in service, the financing costs related to the construction of Plant Vogtle Units 3 and 4, higher contributions from market-driven rates from commercial and industrial customers, and the pricing effect of decreased customer usage.

Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2013 when compared to the corresponding periods in 2012. Weather-adjusted residential KWH sales decreased 1.6%, weather-adjusted commercial KWH sales decreased 3.0%, and weather-adjusted industrial KWH sales decreased 0.5% in the second quarter 2013 when compared to the corresponding period in 2012. For year-to-date 2013, weather-adjusted residential KWH sales decreased 0.5%, weather-adjusted commercial KWH sales decreased 1.1%, and weather-adjusted industrial KWH sales decreased 1.7% when compared to the corresponding period in 2012. Residential and commercial usage continues to be impacted by economic uncertainty, modest consumer spending, and energy efficiency efforts. Decreased demand in the chemicals, paper, and primary metals sectors was the main contributor to the decrease in year-to-date 2013 weather-adjusted industrial KWH sales. In addition, an extra day of sales as a result of the leap year in 2012 negatively impacted KWH sales in all customer classes in 2013.

In the first quarter 2012, Georgia Power began using new actual advanced meter data to compute unbilled revenues. The year-to-date weather-adjusted KWH sales variances shown above reflect an adjustment to the estimated allocation of Georgia Power's unbilled January 2012 KWH sales among customer classes that is consistent with the actual allocation in 2013. Without this adjustment, year-to-date 2013 weather-adjusted residential KWH sales decreased 1.5%, weather-adjusted commercial KWH sales decreased 0.2%, and weather-adjusted industrial KWH sales decreased 1.8% when compared to the corresponding period in 2012.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $10 million and $78 million in the second quarter and year-to-date 2013, respectively, when compared to the corresponding periods in 2012 due to higher fuel costs, partially offset by lower energy sales.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.

Fuel and Purchased Power Expenses



	Second Quarter 2013 vs. Second Quarter 2012					Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(15	)	(2.6	)	$	64		6.3
Purchased power – non-affiliates	(33		)	(35.1	)	(76		)	(40.6	)
Purchased power – affiliates	47			36.4		63			21.9
Total fuel and purchased power expenses	$	(1	)			$	51

In the second quarter 2013, total fuel and purchased power expenses were $794 million compared to $795 million in the corresponding period in 2012. The decrease in the second quarter 2013 was primarily due to a $93 million decrease in the volume of KWHs generated and purchased as a result of lower customer demand, partially offset by a $92 million increase in the average cost of fuel and purchased power, primarily due to higher natural gas prices.

For year-to-date 2013, total fuel and purchased power expenses were $1.54 billion compared to $1.49 billion for the corresponding period in 2012. The increase in year-to-date 2013 was primarily due to a $161 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $110 million decrease primarily in the volume of KWHs purchased due to lower customer demand.

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

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



	Second Quarter 2013	Second Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (billions of KWHs)	16	16	31	29
Total purchased power (billions of KWHs)	6	7	12	15
Sources of generation (percent) —
Coal	33	44	31	43
Nuclear	26	26	24	28
Gas	38	29	42	28
Hydro	3	1	3	1
Cost of fuel, generated (cents per net KWH) —
Coal	4.90	5.00	5.07	4.86
Nuclear	0.91	0.84	0.91	0.85
Gas	3.56	2.71	3.34	2.90
Average cost of fuel, generated (cents per net KWH)	3.32	3.25	3.30	3.18
Average cost of purchased power (cents per net KWH)^(a)	5.02	4.24	4.72	4.03


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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel

In the second quarter 2013, fuel expense was $557 million compared to $572 million in the corresponding period in 2012. The decrease was primarily due to a 2.3% decrease in the volume of KWHs generated as a result of lower KWH demand, partially offset by increases in the average cost of fuel per KWH generated, primarily due to higher natural gas and nuclear fuel prices.

For year-to-date 2013, fuel expense was $1.08 billion compared to $1.01 billion in the corresponding period in 2012. The increase was primarily due to a 6.2% increase in the volume of KWHs generated as a result of higher prices for purchased power and an increase in the average cost of fuel for all types of generation.

Purchased Power – Non-Affiliates

In the second quarter 2013, purchased power expense from non-affiliates was $61 million compared to $94 million in the corresponding period in 2012. The decrease was due to a 57.3% decrease in the volume of KWHs purchased as the cost of Georgia Power-owned generation was lower than the market cost of available energy, partially offset by an increase of 46.2% in the average cost per KWH purchased, primarily due to higher fuel prices.

For year-to-date 2013, purchased power expense from non-affiliates was $111 million compared to $187 million in the corresponding period in 2012. The decrease was due to a 62.4% decrease in the volume of KWHs purchased as the cost of Georgia-Power owned generation was lower than the market cost of available energy, partially offset by an increase of 55.2% in the average cost per KWH purchased due to higher fuel prices.

Purchased Power – Affiliates

In the second quarter 2013, purchased power expense from affiliates was $176 million compared to $129 million in the corresponding period in 2012. The increase was due to a 2.6% increase in the volume of KWHs purchased and a 19.6% increase in the average cost per KWH purchased, reflecting higher fuel prices.

For year-to-date 2013, purchased power expense from affiliates was $351 million compared to $288 million in the corresponding period in 2012. The increase was due to a 18.7% increase in the average cost per KWH purchased, reflecting higher fuel prices, partially offset by a 5.9% decrease in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources.

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

Other Operations and Maintenance Expenses

In the second quarter 2013, other operations and maintenance expenses were $397 million compared to $411 million in the corresponding period in 2012. The decrease was primarily due to decreases of $9 million in fossil generating expenses and $7 million in transmission and distribution line maintenance due to cost containment efforts to offset the effect of economic conditions and less favorable weather in the second quarter 2013.

For year-to-date 2013, other operations and maintenance expenses were $828 million compared to $845 million in the corresponding period in 2012. The decrease was primarily due to decreases of $18 million in fossil generating expenses due to cost containment and outage timing to offset the effect of economic conditions and less favorable

Table of Contents

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

weather in the second quarter 2013 and $6 million in transmission and distribution line maintenance, partially offset by an increase of $10 million in pension and other employee benefit related expenses. See Note (F) to the Condensed Financial Statements herein for additional information on pension expense.

Depreciation and Amortization

In the second quarter 2013, depreciation and amortization was $204 million compared to $185 million in the corresponding period in 2012. The increase was primarily due to increases of $8 million in depreciation and amortization resulting from certain unit retirement decisions (with respect to the portion of such units dedicated to wholesale service), $6 million in depreciation on additional plant in service primarily due to the completion of Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively, and $5 million due to reduced amortization of investment tax credits.

For year-to-date 2013, depreciation and amortization was $404 million compared to $373 million in the corresponding period in 2012. The increase was primarily due to increases of $14 million in depreciation on additional plant in service primarily due to the completion of Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively, $14 million in depreciation and amortization resulting from certain unit retirement decisions (with respect to the portion of such units dedicated to wholesale service), and $6 million due to reduced amortization of investment tax credits, partially offset by $9 million in amortization of the regulatory liability previously established for state income tax credits, as authorized by the Georgia PSC.

See Note 1 to the financial statements of Georgia Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information on the state income tax credits regulatory liability.

Taxes Other Than Income Taxes

In the second quarter 2013, taxes other than income taxes were $95 million compared to $94 million in the corresponding period in 2012. The increase was not material.

For year-to-date 2013, taxes other than income taxes were $190 million compared to $181 million in the corresponding period in 2012. The increase was primarily due to a $6 million increase in property taxes and a $5 million increase in municipal franchise fees related to higher retail revenues in 2013.

Allowance for Equity Funds Used During Construction

In the second quarter 2013, AFUDC equity was $7 million compared to $13 million in the corresponding period in 2012. For year-to-date 2013, AFUDC equity was $13 million compared to $26 million in the corresponding period in 2012. The decreases were primarily due to the completion of Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively.

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Income Taxes

In the second quarter 2013, income taxes were $177 million compared to $152 million in the corresponding period in 2012. For year-to-date 2013, income taxes were $301 million compared to $244 million in the corresponding period in 2012. The increases were primarily due to higher pre-tax earnings, state income tax credits recognized in 2012, and a decrease in non-taxable AFUDC equity.

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 successful completion of ongoing construction projects. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced 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.

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 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.

Climate Change Litigation

Kivalina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

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Hurricane Katrina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On May 14, 2013, the U.S. Court of Appeals for the Fifth Circuit upheld the U.S. District Court for the Southern District of Mississippi's dismissal of the case. The decision is subject to appeal; therefore, the ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for information regarding the EPA's MATS rule, the 2007 State of Georgia Multi-Pollutant Rule, the Cross State Air Pollution Rule, and the EPA's SO₂ rule.

On April 30, 2013, the State of Georgia finalized revisions to the 2007 State of Georgia Multi-Pollutant Rule and a companion rule requiring a 95% reduction in SO₂ emissions from certain coal-fired generating units. The revisions modify the compliance dates under those two rules for units yet to be controlled to synchronize them with the MATS rule compliance deadline. The revisions also allow natural gas to be used as a compliance alternative at Plant Yates. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" herein for additional information regarding the conversion of Plant Yates Units 6 and 7.

On July 25, 2013, the EPA issued initial nonattainment area designations under the one-hour National Ambient Air Quality Standard for SO₂ based on ambient air quality monitoring data. No areas within Georgia Power's service territory were designated as nonattainment under this rule. The EPA has deferred designation of attainment and unclassifiable areas and may designate additional areas as nonattainment in the future, which could include areas within Georgia Power's service territory. The ultimate outcome of this matter 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 proposed revision of the current steam electric effluent guidelines and rule for cooling water intake structures.

On June 7, 2013, the EPA published a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Georgia Power's facilities, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

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Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the proposed regulation of greenhouse gas emissions through establishment of new source performance standards.

Although the outcome of the proposed regulations and guidelines cannot be determined at this time, additional restrictions on Georgia Power's greenhouse gas emissions at the federal or state level could result in significant additional compliance costs, including capital expenditures. These costs could affect future unit retirement and replacement decisions. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

PSC Matters

Fuel Cost Recovery

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

As of June 30, 2013, Georgia Power's fuel cost over recovery balance totaled $108 million and is included in current liabilities on Georgia Power's Condensed Balance Sheet herein.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any 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.

Rate Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate Plans" of Georgia Power in Item 7 of the Form 10-K and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K for information regarding Georgia Power's current retail rate plan.

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of recent and future investments in infrastructure including environmental controls, transmission and distribution, generation, and smart grid technologies in order to maintain high levels of reliability and superior customer service.

The primary points of the 2013 Rate Case are:


•	Continuation of the traditional base rate tariffs through December 31, 2016 based on a test year ending July 31, 2014 with a modification for an appropriate three-year levelization adjustment.


•	Continuation of the ECCR tariff through December 31, 2016 with a modification for an appropriate three-year levelization adjustment.


•	Continuation of an allowed retail ROE range of 10.25% to 12.25%.


•	Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range will be shared with Georgia Power's customers and the remaining one-third will be retained by Georgia Power.


•	Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

The Georgia PSC is scheduled to issue a final order in this matter during December 2013. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality," " – Water Quality," and " – Coal Combustion Byproducts" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" and " – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, proposed cooling water intake structure rules, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia's Multi-Pollutant Rule; Georgia Power's analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations; the 2010 ARP; the 2011 IRP; and the 2013 IRP.

On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (32 MWs), which was retired on April 25, 2013.

On July 11, 2013, the Georgia PSC approved Georgia Power's request to decertify and retire Plant Boulevard Units 2 and 3 (28 MWs) effective July 17, 2013. Plant Branch Units 3 and 4 (1,016 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) will be decertified and retired by April 16, 2015, the compliance date of the MATS rule. The decertification date of Plant Branch Unit 1 was extended from December 31, 2013 as specified in the final order in the 2011 IRP to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (316 MWs) was also approved and will be effective by April 16, 2016, assuming a one-year extension of the MATS rule compliance date is approved by the State of Georgia Environmental Protection Division to allow for necessary transmission system reliability improvements.

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any over or under recovered cost of removal balances remaining at the unit retirement dates for each retirement unit until the 2013 Rate Case. The Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases.

The decertification of these units, fuel conversions, and procurement of additional solar generation are not expected to have a material impact on Georgia Power's financial statements; however, the ultimate outcome depends on the Georgia PSC's order in the 2013 Rate Case and future fuel cases and cannot be determined at this time.

Nuclear Construction

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC 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, the eighth Vogtle Construction Monitoring (VCM) report, and pending litigation.

In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to an NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, and $50 million, effective January 1, 2011, 2012, and 2013, respectively. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At June 30, 2013, approximately $46 million of these 2009 and 2010 costs remained unamortized in CWIP.

In February 2012, separate groups of petitioners filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC's issuance of the combined construction and operating licenses (COLs) and certification of the Westinghouse Design Control Document, as amended (DCD). These petitions were consolidated in April 2012. Also in February 2012, one of the groups of petitioners filed a motion with the NRC to stay the effectiveness of the COLs pending the outcome of the petitions pending before the U.S. District Court for the District of Columbia Circuit. The NRC denied this motion in April 2012. On May 14, 2013, the U.S. Court of Appeals for the District of Columbia Circuit ruled in favor of the NRC, upholding the COLs and allowing for the continuation of the construction. On July 23, 2013, the U.S. Court of Appeals for the District of Columbia Circuit rejected the petitioners' request for rehearing.

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December 31, 2012. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, the eighth VCM report also requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the construction period are estimated to total approximately $2.0 billion. The Georgia PSC is scheduled to vote on the eighth VCM report in October 2013.

On July 30, 2013, Georgia Power and the Georgia PSC staff entered into a stipulation to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, which had been requested in the eighth VCM report, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the parties. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent; therefore, any related financing costs during construction potentially would be subject to recovery through AFUDC. The stipulation also provides that Georgia Power will combine the ninth and tenth VCM reports scheduled to be filed by August 31, 2013 and February 28, 2014, respectively, into a single report covering the period from January 1 through December 31, 2013 to be filed by February 28, 2014. Additionally, Georgia Power will file an abbreviated status update by September 3, 2013, which will include the costs incurred from January 1 through June 30, 2013. Georgia Power expects to resume filing semi-annual VCM reports in August 2014. The stipulation is subject to approval by the Georgia PSC.

In addition, processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including rigorous inspections by Southern Nuclear and the NRC that occur throughout construction. During the fourth quarter 2012, certain details of the rebar design for the Plant Vogtle Unit 3 nuclear island were evaluated for consistency with the DCD and deviations were identified. On February 26, 2013 and March 1, 2013, the NRC approved the two license amendment requests required to conform the rebar design details to NRC requirements and, on March 14, 2013, the placement of basemat structural concrete for the nuclear island of Plant Vogtle Unit 3 was completed. Additional license amendment requests have been filed and approved or are pending before the NRC. Various design and other issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Owners, the Contractor, or both.

As construction continues, additional delays in the fabrication and assembly of structural modules, the failure of such modules to meet applicable standards, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues may further impact project schedule and cost. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4, 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.

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Other Matters

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

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

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011. On March 19, 2013, the NRC issued an order relating to hardened vents for certain classes of containment structures, including the one in use at Plant Hatch. On June 6, 2013, the NRC issued a new order superseding the March 19, 2013 order regarding enhanced safety for hardened vents. Georgia Power is continuing to analyze the impact of this order. The ultimate outcome of this matter cannot be determined at this time; however, management does not currently anticipate that the compliance costs associated with this order would have a material impact on Georgia Power's financial statements.

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.

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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, 2013. Georgia 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 $931 million for the first six months of 2013 compared to $915 million for the corresponding period in 2012. The increase was primarily due to higher retail operating revenues and lower fuel inventory additions in 2013, partially offset by fuel cost recovery. Net cash used for investing activities totaled $807 million for the first six months of 2013 compared to $1.2 billion used in the corresponding period in 2012. The decrease was primarily due to lower cash payments for construction expenditures in 2013 and lower investments in restricted cash as a result of pollution control revenue bond refinancing. Net cash used for financing activities totaled $140 million for the first six months of 2013 compared to $468 million provided from financing activities in the corresponding period in 2012. The decrease is primarily due to lower net issuances of debt in 2013. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2013 include increases of $417 million in total property, plant, and equipment and $308 million in debt.

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 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. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. Approximately $1.03 billion will be required through June 30, 2014 to fund maturities of long-term debt.

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

Sources of Capital

Except as described below with respect to potential 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

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– FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.

In 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future borrowings by Georgia Power related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.46 billion and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. In the event that the DOE does not issue a loan guarantee or Georgia Power determines that the final terms and conditions of the loan guarantee by the DOE are not in the best interest of its customers, Georgia Power expects to finance the construction of Plant Vogtle Units 3 and 4 through traditional capital markets financings. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. The conditional commitment will expire on September 30, 2013, unless further extended by the DOE. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Nuclear Construction" herein for more information on Plant Vogtle Units 3 and 4.

Georgia 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. Georgia Power has substantial cash flow from operating activities and access to the capital markets to meet liquidity needs.

At June 30, 2013, Georgia Power had approximately $29 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2013 were as follows:



Expires^(a)
	2016		2018		Total		Unused
(in millions)					(in millions)
	$	150	$	1,600	$	1,750	$	1,740

(a) No credit arrangements expire in 2013, 2014, 2015, or 2017.

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

These credit arrangements provide liquidity support to Georgia Power's commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2013 was approximately $874 million.

As reflected in the table above, during the first six months of 2013, Georgia Power amended certain of its credit arrangements. In February 2013, Georgia Power amended its multi-year credit arrangement, which extended the maturity date from 2016 to 2018. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration.

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

These arrangements contain covenants that limit debt levels and contain cross default provisions that are restricted only to the indebtedness of Georgia Power. Georgia Power is currently in compliance with all such covenants.

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Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 2013				Short-term Debt During the Period^(a)(b)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	314	0.2	%	$	140	0.2	%	$	318
Short-term bank debt	—		—	%	115		0.9	%	300
Total	$	314	0.2	%	$	255	0.5	%

(a) Excludes notes payable related to other energy service contracts of $2 million.

(b) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2013.

Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

Credit Rating Risk

Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. The maximum potential collateral requirements under these contracts at June 30, 2013 were as follows:




Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	65
Below BBB- and/or Baa3	1,321

Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant 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 Georgia Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

On May 24, 2013, S&P revised the ratings outlook for Southern Company and the traditional operating companies, including Georgia Power, from stable to negative.

Market Price Risk

Georgia Power's market risk exposure relative to interest rate changes for the second quarter 2013 has not changed materially compared with the December 31, 2012 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As a result, Georgia Power had no material change in market risk exposure for the second quarter 2013 relative to fuel and electricity prices when compared with the December 31, 2012 reporting period.

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and six months ended June 30, 2013 were as follows:



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(15	)	$	(33	)
Contracts realized or settled	4			14
Current period changes^(a)	(18		)	(10		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(29	)	$	(29	)


(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$	(2	)	$	4
Natural gas options	(12		)	—
Total changes	$	(14	)	$	4

The net hedge volumes of energy-related derivative contracts were as follows:



	June 30, 2013	March 31, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	10	11	12
Commodity – Natural gas options	68	79	93
Total hedge volume	78	90	105

The weighted average swap contract cost above market prices was approximately $0.94 per mmBtu as of June 30, 2013, $0.64 per mmBtu as of March 31, 2013, and $1.09 per mmBtu as of December 31, 2012. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. All natural gas hedge gains and losses are recovered through Georgia Power's fuel cost recovery mechanism.

Regulatory hedges relate to Georgia Power's fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Georgia Power's fuel cost recovery mechanism.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2013 and 2012 for energy-related derivative contracts that are not hedges were not material.

Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at June 30, 2013 were as follows:



	June 30, 2013 Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3
				(in millions)
Level 1	$	—		$	—		$	—
Level 2	(29		)	(19		)	(10		)
Level 3	—			—			—
Fair value of contracts outstanding at end of period	$	(29	)	$	(19	)	$	(10	)

For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Georgia Power in Item 7 and Note 1 under "Financial Instruments" and Note 11 to the financial statements of Georgia Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

In January 2013, Georgia Power's $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes was paid at maturity.

In March 2013, Georgia Power entered into three 60-day floating rate bank loans bearing interest based on one-month LIBOR. Each of these short-term loans was for $100 million aggregate principal amount, and the proceeds were used for working capital and other general corporate purposes, including Georgia Power's continuous construction program. These bank loans were repaid at maturity.

In March 2013, Georgia Power issued $400 million aggregate principal amount of Series 2013A 4.30% Senior Notes due March 15, 2043. Also in March 2013, Georgia Power issued $250 million aggregate principal amount of Series 2013B Floating Rate Senior Notes due March 15, 2016. The proceeds from the sale of the Series 2013A Senior Notes, together with the proceeds from the sale of the Series 2013B Senior Notes, were used to repay at maturity $350 million aggregate principal amount of Georgia Power's Series 2010A Floating Rate Senior Notes due March 15, 2013, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.

In March 2013, the Development Authority of Monroe County issued $17.5 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2013 due April 1, 2043 for the benefit of Georgia Power. The proceeds were used to redeem, in April 2013, $17.5 million aggregate principal amount of Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 1997.

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

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GULF POWER COMPANY

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	305,550		$	294,878		$	565,427		$	533,398
Wholesale revenues, non-affiliates	31,894			28,729			53,102			55,847
Wholesale revenues, affiliates	19,050			28,702			48,505			65,066
Other revenues	14,679			17,899			30,413			32,142
Total operating revenues	371,173			370,208			697,447			686,453
Operating Expenses:
Fuel	140,347			141,220			261,193			262,308
Purchased power, non-affiliates	13,054			12,085			24,189			23,310
Purchased power, affiliates	10,934			5,210			14,246			7,723
Other operations and maintenance	76,846			79,779			155,508			155,009
Depreciation and amortization	37,081			35,173			74,134			68,480
Taxes other than income taxes	23,760			25,276			47,386			49,060
Total operating expenses	302,022			298,743			576,656			565,890
Operating Income	69,151			71,465			120,791			120,563
Other Income and (Expense):
Allowance for equity funds used during construction	1,521			1,736			2,655			2,973
Interest expense, net of amounts capitalized	(14,293		)	(15,698		)	(28,662		)	(31,066		)
Other income (expense), net	(1,391		)	1,112			(2,367		)	103
Total other income and (expense)	(14,163		)	(12,850		)	(28,374		)	(27,990		)
Earnings Before Income Taxes	54,988			58,615			92,417			92,573
Income taxes	20,755			22,102			34,841			33,843
Net Income	34,233			36,513			57,576			58,730
Dividends on Preference Stock	1,651			1,550			3,202			3,101
Net Income After Dividends on Preference Stock	$	32,582		$	34,963		$	54,374		$	55,629

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Net Income	$	34,233	$	36,513	$	57,576	$	58,730
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $90, $90, $180 and $180, respectively	143		143		286		286
Total other comprehensive income (loss)	143		143		286		286
Comprehensive Income	$	34,376	$	36,656	$	57,862	$	59,016

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2013			2012
	(in thousands)
Operating Activities:
Net income	$	57,576		$	58,730
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	77,627			71,707
Deferred income taxes	36,407			70,153
Allowance for equity funds used during construction	(2,655		)	(2,973		)
Pension, postretirement, and other employee benefits	5,452			2,383
Stock based compensation expense	1,028			1,044
Other, net	2,209			7,503
Changes in certain current assets and liabilities —
-Receivables	(59,770		)	(18,580		)
-Prepayments	1,271			1,813
-Fossil fuel stock	19,332			3,982
-Materials and supplies	(987		)	(4,100		)
-Prepaid income taxes	(2,822		)	(3,566		)
-Other current assets	13			—
-Accounts payable	(9,703		)	(17,481		)
-Accrued taxes	13,632			6,788
-Accrued compensation	(8,308		)	(6,239		)
-Over recovered regulatory clause revenues	(15,659		)	25,099
-Other current liabilities	(1,199		)	(1,659		)
Net cash provided from operating activities	113,444			194,604
Investing Activities:
Property additions	(137,283		)	(169,462		)
Cost of removal, net of salvage	(7,010		)	(14,817		)
Change in construction payables	6,307			3,661
Payments pursuant to long-term service agreements	(2,855		)	(4,086		)
Other investing activities	120			18
Net cash used for investing activities	(140,721		)	(184,686		)
Financing Activities:
Increase in notes payable, net	1,230			5,980
Proceeds —
Common stock issued to parent	40,000			40,000
Capital contributions from parent company	1,419			954
Preference stock	50,000			—
Pollution control revenue bonds	63,000			—
Senior notes	90,000			100,000
Redemptions —
Pollution control revenue bonds	(63,000		)	—
Senior notes	—			(91,363		)
Payment of preference stock dividends	(3,101		)	(3,101		)
Payment of common stock dividends	(57,700		)	(57,900		)
Other financing activities	(3,105		)	(653		)
Net cash provided from (used for) financing activities	118,743			(6,083		)
Net Change in Cash and Cash Equivalents	91,466			3,835
Cash and Cash Equivalents at Beginning of Period	32,167			17,328
Cash and Cash Equivalents at End of Period	$	123,633		$	21,163
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $1,408 and $1,185 capitalized for 2013 and 2012, respectively)	$	26,987		$	30,100
Income taxes, net	428			(32,848		)
Noncash transactions — accrued property additions at end of period	29,036			27,127

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2013			At December 31, 2012
	(in thousands)
Current Assets:
Cash and cash equivalents	$	123,633		$	32,167
Receivables —
Customer accounts receivable	76,156			58,449
Unbilled revenues	66,575			53,363
Under recovered regulatory clause revenues	36,401			6,138
Other accounts and notes receivable	11,563			11,859
Affiliated companies	8,344			13,624
Accumulated provision for uncollectible accounts	(1,246		)	(1,490		)
Fossil fuel stock, at average cost	134,378			153,710
Materials and supplies, at average cost	54,352			53,365
Other regulatory assets, current	27,889			30,576
Prepaid expenses	37,165			62,877
Other current assets	3,545			2,690
Total current assets	578,755			477,328
Property, Plant, and Equipment:
In service	4,286,432			4,260,844
Less accumulated provision for depreciation	1,173,917			1,168,055
Plant in service, net of depreciation	3,112,515			3,092,789
Construction work in progress	220,134			136,062
Total property, plant, and equipment	3,332,649			3,228,851
Other Property and Investments	15,628			15,737
Deferred Charges and Other Assets:
Deferred charges related to income taxes	51,190			50,139
Other regulatory assets, deferred	376,888			372,294
Other deferred charges and assets	33,473			33,053
Total deferred charges and other assets	461,551			455,486
Total Assets	$	4,388,583		$	4,177,402

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2013			At December 31, 2012
	(in thousands)
Current Liabilities:
Securities due within one year	$	90,000		$	60,000
Notes payable	125,000			127,002
Accounts payable —
Affiliated	73,600			66,161
Other	45,342			54,551
Customer deposits	35,096			34,749
Accrued taxes —
Accrued income taxes	14,725			45
Other accrued taxes	20,441			7,036
Accrued interest	11,195			12,364
Accrued compensation	6,657			14,966
Other regulatory liabilities, current	6,666			25,887
Liabilities from risk management activities	14,511			16,529
Other current liabilities	20,187			19,930
Total current liabilities	463,420			439,220
Long-term Debt	1,245,248			1,185,870
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	675,960			648,952
Accumulated deferred investment tax credits	4,731			5,408
Employee benefit obligations	127,310			126,871
Other cost of removal obligations	220,782			213,413
Other regulatory liabilities, deferred	47,356			47,863
Deferred capacity expense	158,858			137,568
Other deferred credits and liabilities	78,100			93,497
Total deferred credits and other liabilities	1,313,097			1,273,572
Total Liabilities	3,021,765			2,898,662
Preference Stock	146,569			97,998
Common Stockholder's Equity:
Common stock, without par value—
Authorized — 20,000,000 shares
Outstanding — June 30, 2013: 4,942,717 shares
— December 31, 2012: 4,542,717 shares	433,060			393,060
Paid-in capital	550,345			547,798
Retained earnings	238,139			241,465
Accumulated other comprehensive loss	(1,295		)	(1,581		)
Total common stockholder's equity	1,220,249			1,180,742
Total Liabilities and Stockholder's Equity	$	4,388,583		$	4,177,402

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 2013 vs. SECOND QUARTER 2012

AND

YEAR-TO-DATE 2013 vs. YEAR-TO-DATE 2012

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Gulf Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, restoration following major storms, and fuel. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.

On July 12, 2013, Gulf Power filed a petition with the Florida PSC requesting a two-step increase in retail rates to the extent necessary to generate additional gross annual revenues in the amount of $74.4 million effective in 2014 and additional annual gross revenues of $16.4 million effective July 1, 2015. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Base Rate Case" herein for additional information.

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

Gulf Power's net income after dividends on preference stock for the second quarter 2013 was $32.6 million compared to $35.0 million for the corresponding period in 2012. The decrease was primarily due to lower revenues in the second quarter 2013 due to less favorable weather, partially offset by a decrease in routine and planned maintenance expense at generation and distribution facilities. Gulf Power's net income after dividends on preference stock for year-to-date 2013 was $54.4 million compared to $55.6 million for the corresponding period in 2012. The decrease was primarily due to lower wholesale revenues from non-affiliates in 2013 and an increase in depreciation in 2013, partially offset by increased retail revenues in 2013 primarily resulting from the retail base rate increase effective April 2012.

Retail Revenues

In the second quarter 2013, retail revenues were $305.6 million compared to $294.9 million for the corresponding period in 2012. For year-to-date 2013, retail revenues were $565.4 million compared to $533.4 million for the corresponding period in 2012.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:



	Second Quarter 2013					Year-to-Date 2013
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	294.9				$	533.4
Estimated change in –
Rates and pricing	0.5			0.1		6.3			1.2
Sales growth (decline)	1.1			0.4		(1.6		)	(0.3	)
Weather	(4.7		)	(1.6	)	(1.1		)	(0.2	)
Fuel and other cost recovery	13.8			4.7		28.4			5.3
Retail – current year	$	305.6		3.6	%	$	565.4		6.0	%

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC 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 2013 when compared to the corresponding periods in 2012. The increase in the second quarter 2013 was not material. The increase in year-to-date 2013 was primarily due to the retail base rate increase effective April 2012, partially offset by lower revenues associated with environmental and energy conservation cost recovery clauses.

Revenues attributable to changes in sales increased in the second quarter 2013 when compared to the corresponding period in 2012. Weather-adjusted KWH energy sales to residential and commercial customers increased 3.1% and 0.6%, respectively, primarily due to customer growth. KWH energy sales to industrial customers decreased 5.7% primarily due to changes in customer production levels and increased customer co-generation.

Revenues attributable to changes in sales decreased year-to-date 2013 when compared to the corresponding period in 2012. Weather-adjusted KWH energy sales to residential customers increased 0.3% primarily due to customer growth. Weather-adjusted KWH energy sales to commercial customers decreased 0.2% primarily due to a decrease in customer usage partially offset by customer growth. KWH energy sales to industrial customers decreased 4.4% primarily due to changes in customer production levels and increased customer co-generation.

Fuel and other cost recovery revenues increased in the second quarter and year-to-date 2013 when compared to the corresponding periods in 2012 primarily due to higher revenues associated with recoverable fuel costs. Recoverable fuel costs increased primarily due to higher average costs per KWH of generation and purchased power. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery" herein for additional information.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Wholesale 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. Wholesale revenues from sales to non-affiliates include unit power sales under long-term contracts to other utilities in Florida and Georgia. Wholesale revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost.

In the second quarter 2013, wholesale revenues from non-affiliates were $31.9 million compared to $28.7 million for the corresponding period in 2012. The increase was primarily due to higher energy revenues related to a 51.3% increase in KWH sales to unit power customers to serve their loads. The increase was partially offset by a 6.6% decrease in capacity revenues primarily related to certain contract provisions that allow for cost adjustments related to new environmental requirements.

For year-to-date 2013, wholesale revenues from non-affiliates were $53.1 million compared to $55.8 million for the corresponding period in 2012. The decrease was primarily due to a 9.5% decrease in capacity revenues primarily related to certain contract provisions that allow for cost adjustments related to new environmental requirements.

Wholesale Revenues – Affiliates

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 2013, wholesale revenues from sales to affiliates were $19.0 million compared to $28.7 million for the corresponding period in 2012. The decrease was primarily due to lower energy revenues related to a 49.3% decrease in KWH sales resulting from lower Gulf Power generation dispatched to serve affiliated companies' demand in the second quarter 2013 compared to the corresponding period in 2012. This decrease was partially offset by a 31.0% increase in the price of energy sold to affiliates in the second quarter 2013, primarily as a result of higher fuel prices.

For year-to-date 2013, wholesale revenues from affiliates were $48.5 million compared to $65.1 million for the corresponding period in 2012. The decrease was primarily due to lower energy revenues related to a 39.3% decrease in KWH sales resulting from lower Gulf Power generation dispatched to serve affiliated companies' demand for year-to-date 2013 compared to the corresponding period in 2012. This decrease was partially offset by a 22.9% increase in the price of energy sold to affiliates for year-to-date 2013.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses



	Second Quarter 2013 vs. Second Quarter 2012					Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(0.9	)	(0.6	)	$	(1.1	)	(0.4	)
Purchased power – non-affiliates	1.0			8.0		0.9			3.7
Purchased power – affiliates	5.7			109.9		6.5			84.5
Total fuel and purchased power expenses	$	5.8				$	6.3

In the second quarter 2013, total fuel and purchased power expenses were $164.3 million compared to $158.5 million for the corresponding period in 2012. The increase in fuel and purchased power expenses was primarily due to a $22.7 million increase in the average cost of fuel and purchased power, partially offset by a $16.9 million decrease related to the volume of KWHs generated and purchased.

For year-to-date 2013, total fuel and purchased power expenses were $299.6 million compared to $293.3 million for the corresponding period in 2012. The increase in fuel and purchased power expenses was primarily due to a $44.3 million increase in the average cost of fuel and purchased power, partially offset by a $38.0 million decrease related to the volume of KWHs generated and purchased.

Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel cost and purchased power capacity recovery clauses. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery" and "– Purchased Power Capacity Recovery" herein for additional information.

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



	Second Quarter 2013	Second Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (millions of KWHs)	2,424	2,650	4,285	4,991
Total purchased power (millions of KWHs)	1,346	1,609	3,009	3,360
Sources of generation (percent) –
Coal	68	66	61	60
Gas	32	34	39	40
Cost of fuel, generated (cents per net KWH) –
Coal	4.52	4.34	4.58	4.32
Gas	4.28	4.27	3.98	3.81
Average cost of fuel, generated (cents per net KWH)	4.44	4.32	4.35	4.12
Average cost of purchased power (cents per net KWH)^(a)	4.20	2.74	3.77	2.61


(a)	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 2013, fuel expense was $140.3 million compared to $141.2 million for the corresponding period in 2012. The decrease was primarily due to an 8.5% decrease in KWH generated, partially offset by a 2.8% increase in the average cost of fuel.

For year-to-date 2013, fuel expense was $261.2 million compared to $262.3 million for the corresponding period in 2012. The decrease was primarily due to a 14.1% decrease in KWH generated, partially offset by a 5.6% increase in the average cost of fuel.

Table of Contents

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Non-Affiliates

In the second quarter 2013, purchased power expense from non-affiliates was $13.1 million compared to $12.1 million for the corresponding period in 2012. The increase reflects an increase of $2.4 million in energy costs, partially offset by a decrease of $1.4 million in capacity costs. The increase in energy costs was due to a 60.9% higher average cost per KWH purchased, partially offset by a 26.6% decrease in the volume of KWHs purchased.

For year-to-date 2013, purchased power expense from non-affiliates was $24.2 million compared to $23.3 million for the corresponding period in 2012. The increase reflects an increase of $2.5 million in energy costs, partially offset by a decrease of $1.6 million in capacity costs. The increase in energy costs was due to a 47.7% higher average cost per KWH purchased, partially offset by a 16.5% decrease in the volume of KWHs purchased.

Purchased Power – Affiliates

In the second quarter 2013, purchased power expense from affiliates was $10.9 million compared to $5.2 million for the corresponding period in 2012. The increase reflects an increase of $5.7 million in energy costs, due to a 220% increase in the volume of KWHs purchased, partially offset by a 38.5% lower average cost per KWH purchased.

For year-to-date 2013, purchased power expense from affiliates was $14.2 million compared to $7.7 million for the corresponding period in 2012. The increase reflects an increase of $7.0 million in energy costs, partially offset by a decrease of $0.5 million in capacity costs. The increase in energy costs was due to a 225% increase in the volume of KWHs purchased, partially offset by a 44.2% lower average cost per KWH purchased.

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

Other Operations and Maintenance Expenses

In the second quarter 2013, other operations and maintenance expenses were $76.9 million compared to $79.8 million for the corresponding period in 2012. The decrease was primarily due to decreases of $3.2 million in routine and planned maintenance expense at generation and distribution facilities.

For year-to-date 2013, other operations and maintenance expenses were $155.5 million compared to $155.0 million for the corresponding period in 2012. The change was not material.

Depreciation and Amortization

In the second quarter 2013, depreciation and amortization was $37.1 million compared to $35.2 million for the corresponding period in 2012. For year-to-date 2013, depreciation and amortization was $74.1 million compared to $68.5 million for the corresponding period in 2012. The increases were primarily due to additions at generation facilities and other net additions to transmission and distribution facilities.

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Interest Expense, Net of Amounts Capitalized

In the second quarter 2013, interest expense, net of amounts capitalized was $14.3 million compared to $15.7 million for the corresponding period in 2012. For year-to-date 2013, interest expense, net of amounts capitalized was $28.7 million compared to $31.1 million for the corresponding period in 2012. The decreases were primarily due to lower interest rates on pollution control bonds, senior notes, and customer deposits.

Income Taxes

In the second quarter 2013, income taxes were $20.8 million compared to $22.1 million for the corresponding period in 2012. The decrease was primarily due to lower pre-tax earnings.

For year-to-date 2013, income taxes were $34.8 million compared to $33.8 million for the corresponding period in 2012. The increase was primarily due to the recognition in 2012 of previously unrecognized tax benefits related to state income tax credits, as well as a settlement with the IRS related to the production activities deduction, and a reduction in the tax benefits associated with a decrease in AFUDC equity, which is non-taxable. See Note 5 to the financial statements of Gulf Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information on the settlement with the IRS.

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 energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power's service territory. 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.

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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. 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 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.

Gulf Power has determined it is not economical to add the environmental controls at Plant Scholz necessary to comply with the MATS rule and that coal-fired generation at Plant Scholz will cease by April 2015. The plant is scheduled to be fully depreciated by April 2015.

Climate Change Litigation

Kivalina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

Hurricane Katrina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On May 14, 2013, the U.S. Court of Appeals for the Fifth Circuit upheld the U.S. District Court for the Southern District of Mississippi's dismissal of the case. The decision is subject to appeal; therefore, the ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Gulf Power in Item 7 of the Form 10-K for information regarding the EPA's MATS rule, the Cross State Air Pollution Rule, and the EPA's SO₂ rule.

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unclassifiable areas and may designate additional areas as nonattainment in the future, which could include areas within Gulf Power's service territory. The ultimate outcome of this matter 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 proposed revision of the current steam electric effluent guidelines and rule for cooling water intake structures.

On June 7, 2013, the EPA published a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Gulf Power's facilities, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the proposed regulation of greenhouse gas emissions through establishment of new source performance standards.

Although the outcome of the proposed regulations and guidelines cannot be determined at this time, additional restrictions on Gulf Power's greenhouse gas emissions at the federal or state level could result in significant additional compliance costs, including capital expenditures. These costs could affect future unit retirement and replacement decisions. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

PSC Matters

Retail Base Rate Case

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

On July 12, 2013, Gulf Power filed a petition with the Florida PSC requesting an increase in retail rates to the extent necessary to generate additional gross annual revenues in the amount of $74.4 million effective in 2014. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail ROE of 11.5%. The Florida PSC is expected to make a decision on this matter in the first quarter 2014.

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analyzed by the Florida PSC to be able to set reasonable rates for the period the new rates will be in effect. The period January 1, 2014 through December 31, 2014 best represents expected future operations of Gulf Power as the regional economy continues to emerge from the recession. The petition also requests that the Florida PSC approve the projected January 1, 2014 through December 31, 2014 test year and consent to new rate schedules going into operation as soon as possible.

Additionally, Gulf Power has requested that the Florida PSC approve a step adjustment in base rates for the costs associated with certain transmission system upgrades related to Gulf Power's compliance with the MATS rule. If the Florida PSC determines that these costs are more appropriate for recovery through base rates rather than the Environmental Cost Recovery Clause, the requested step adjustment would increase retail rates to the extent necessary to generate additional gross revenues in the amount of $16.4 million, to be effective July 1, 2015.

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

Cost Recovery Clauses

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC 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.

Fuel Cost Recovery

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

Under recovered fuel costs at June 30, 2013 totaled $16.4 million which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. The under recovered fuel cost balance is expected to be offset by approximately $26.6 million during the third quarter 2013 as a result of a payment from one of Gulf Power's fuel vendors due to the resolution of a contract dispute. At December 31, 2012, the over recovered fuel costs totaled $17.1 million, which is included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheet herein.

Purchased Power Capacity Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Purchased Power Capacity Recovery" of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Cost Recovery Clauses – Purchased Power Capacity Recovery," respectively, in Item 8 of the Form 10-K for additional information.

At June 30, 2013, the over recovered purchased power capacity costs totaled $1.4 million, which is included in other regulatory liabilities, current on Gulf Power's Condensed Balance Sheet herein. At December 31, 2012, the under recovered purchased power capacity costs totaled $0.8 million, which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein.

Environmental Cost Recovery

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

Under recovered environmental costs at June 30, 2013 totaled $11.5 million compared to $1.9 million at December 31, 2012. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.

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Energy Conservation Cost Recovery

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

Under recovered energy conservation costs at June 30, 2013 totaled $5.1 million compared to $0.8 million at December 31, 2012. These amounts are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheets herein.

Other Matters

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

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.

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, 2013. Gulf 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 "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

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Net cash provided from operating activities totaled $113.4 million for the first six months of 2013 compared to $194.6 million for the corresponding period in 2012. The $81.2 million decrease was primarily related to the recovery of fuel costs which moved from an over recovered to an under recovered position and a decrease in cash flows related to deferred income taxes. Net cash used for investing activities totaled $140.7 million in the first six months of 2013 primarily due to property additions to utility plant and costs of removal. Net cash provided from financing activities totaled $118.7 million for the first six months of 2013, primarily due to issuances of senior notes and common and preference stock, partially offset by payment of common stock dividends. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2013 include a net increase of $103.8 million in property, plant, and equipment, primarily due to the addition of environmental control projects at generation facilities and other net additions to transmission and distribution facilities, an increase in cash and cash equivalents of $91.5 million due to financing activities, including $40.0 million from the issuance of common stock.

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 the related interest, leases, derivative obligations, preference stock dividends, purchase commitments, trust funding requirements, and unrecognized tax benefits. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. Approximately $90 million was required through June 30, 2014 to fund maturities of long-term debt. Subsequent to June 30, 2013, Gulf Power repaid $90 million of securities, of which $60 million was paid at maturity and $30 million was redeemed prior to maturity.

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.

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At June 30, 2013, Gulf Power had approximately $123.6 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2013 were as follows:



Expires^(a)										Executable Term Loans				Due Within One Year
2013		2014		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	20	$	90	$	165	$	275	$	275	$	45	$	—	$	45	$	65


(a)	No credit arrangements expire in 2015.

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.

These credit arrangements provide liquidity support to Gulf Power's commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2013 was approximately $69 million. In addition, Gulf Power has substantial cash flows from operating activities and access to the capital markets to meet liquidity needs.

As reflected in the table above, during the first six months of 2013, Gulf Power entered into, amended, or renewed certain of its credit arrangements. In March 2013, Gulf Power amended several credit arrangements, which extended the maturity dates from 2014 to 2016. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration.

Most of these arrangements contain covenants that limit debt levels and contain cross default provisions that are restricted only to the indebtedness of Gulf Power. Gulf Power is currently in compliance with all such covenants.

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, 2013				Short-term Debt During the Period^(a)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	—	—	%	$	119	0.2	%	$	173
Short-term bank debt	125		1.2	%	37		1.2	%	125
Total	$	125	1.2	%	$	156	0.5	%


(a)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2013.

Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

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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, 2013 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	92
Below BBB- and/or Baa3	459

Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant 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.

On May 24, 2013, S&P revised the ratings outlook for Southern Company and the traditional operating companies, including Gulf Power, from stable to negative.

Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the second quarter 2013 has not changed materially compared with the December 31, 2012 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Gulf Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to natural gas purchases, Gulf Power continues to manage a financial hedging program for fuel purchased to operate its electric generating fleet implemented per the guidelines of the Florida PSC. As a result, Gulf Power had no material change in market risk exposure for the second quarter 2013 when compared with the December 31, 2012 reporting period.

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and six months ended June 30, 2013 were as follows:



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(2	)	$	(23	)
Contracts realized or settled	—			5
Current period changes^(a)	(19		)	(3		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(21	)	$	(21	)


(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$	(19	)	$	2
Natural gas options	—			—
Other energy-related derivatives	—			—
Total changes	$	(19	)	$	2

The net hedge volumes of energy-related derivative contracts were as follows:



	June 30, 2013	March 31, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	79	70	71
Commodity – Natural gas options	—	—	—
Total hedge volume	79	70	71

The weighted average swap contract cost above market prices was approximately $0.26 per mmBtu as of June 30, 2013, $0.02 per mmBtu as of March 31, 2013, and $0.32 per mmBtu as of December 31, 2012. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Natural gas settlements are recovered through Gulf Power's fuel cost recovery clause.

Regulatory hedges relate to Gulf Power's fuel-hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through Gulf Power's fuel cost recovery clause.

Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2013 and 2012 for energy-related derivative contracts that are not hedges were not material.

Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at June 30, 2013 were as follows:



	June 30, 2013 Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2	(21		)	(13		)	(8		)	—
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(21	)	$	(13	)	$	(8	)	$	—

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For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 and Note 1 under "Financial Instruments" and Note 10 to the financial statements of Gulf Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

In February 2013, Gulf Power issued 400,000 shares of common stock to Southern Company and realized proceeds of $40 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 2013, Gulf Power entered into a three-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $125 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Gulf Power's continuous construction program. This bank loan was repaid in July 2013.

In June 2013, Gulf Power issued 500,000 shares of Series 2013A 5.60% Preference Stock and realized proceeds of $50 million. Also in June 2013, Gulf Power issued $90 million aggregate principal amount of Series 2013A 5.00% Senior Notes due June 15, 2043. The proceeds from the sale of the Preference Stock, together with the proceeds from the issuance of the Series 2013A Senior Notes, were used to repay at maturity $60 million aggregate principal amount of Gulf Power's Series G 4.35% Senior Notes due July 15, 2013, to repay a portion of a three-month floating rate bank loan in an aggregate principal amount outstanding of $125 million, for a portion of the redemption in July 2013 of $30 million aggregate principal amount outstanding of Gulf Power’s Series H 5.25% Senior Notes due July 15, 2033, and for general corporate purposes, including Gulf Power’s continuous construction program.

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

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CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	214,254		$	192,177		$	382,564		$	358,448
Wholesale revenues, non-affiliates	71,938			64,116			137,047			118,347
Wholesale revenues, affiliates	15,902			5,324			24,243			9,364
Other revenues	4,341			4,467			8,515			8,639
Total operating revenues	306,435			266,084			552,369			494,798
Operating Expenses:
Fuel	142,193			105,469			246,757			194,088
Purchased power, non-affiliates	1,778			1,134			3,145			3,077
Purchased power, affiliates	3,922			10,843			13,611			19,703
Other operations and maintenance	54,456			60,501			109,268			115,396
Depreciation and amortization	22,209			22,517			45,442			44,998
Taxes other than income taxes	20,272			18,634			39,689			40,337
Estimated loss on Kemper IGCC	450,000			—			912,000			—
Total operating expenses	694,830			219,098			1,369,912			417,599
Operating Income (Loss)	(388,395		)	46,986			(817,543		)	77,199
Other Income and (Expense):
Allowance for equity funds used during construction	29,042			13,870			55,116			25,697
Interest expense, net of amounts capitalized	(10,389		)	(13,023		)	(20,798		)	(20,828		)
Other income (expense), net	(2,262		)	(159		)	(3,809		)	(281		)
Total other income and (expense)	16,391			688			30,509			4,588
Earnings (Loss) Before Income Taxes	(372,004		)	47,674			(787,034		)	81,787
Income taxes (benefit)	(153,327		)	12,214			(322,469		)	20,639
Net Income (Loss)	(218,677		)	35,460			(464,565		)	61,148
Dividends on Preferred Stock	433			433			866			866
Net Income (Loss) After Dividends on Preferred Stock	$	(219,110	)	$	35,027		$	(465,431	)	$	60,282

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)



	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2013			2012		2013			2012
	(in thousands)					(in thousands)
Net Income (Loss)	$	(218,677	)	$	35,460	$	(464,565	)	$	61,148
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $- and $(296), respectively	—			—		—			(478		)
Reclassification adjustment for amounts included in net income, net of tax of $132, $132, $263 and $148, respectively	213			212		425			238
Total other comprehensive income (loss)	213			212		425			(240		)
Comprehensive Income (Loss)	$	(218,464	)	$	35,672	$	(464,140	)	$	60,908

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,
	2013			2012
	(in thousands)
Operating Activities:
Net income (loss)	$	(464,565	)	$	61,148
Adjustments to reconcile net income (loss) to net cash provided from (used for) operating activities —
Depreciation and amortization, total	43,263			43,955
Deferred income taxes	(337,167		)	1,280
Investment tax credits received	66,474			13,974
Allowance for equity funds used during construction	(55,116		)	(25,697		)
Pension, postretirement, and other employee benefits	6,184			3,993
Hedge settlements	—			(15,983		)
Stock based compensation expense	1,547			1,344
Regulatory assets associated with Kemper IGCC	(13,399		)	(6,431		)
Estimated loss on Kemper IGCC	912,000			—
Kemper regulatory deferral	26,979			—
Other, net	1,068			3,783
Changes in certain current assets and liabilities —
-Receivables	(37,431		)	(12,424		)
-Fossil fuel stock	34,205			(32,797		)
-Materials and supplies	(6,509		)	212
-Prepaid income taxes	8,823			11,974
-Other current assets	(4,879		)	(7,281		)
-Accounts payable	(5,417		)	3,408
-Accrued taxes	(24,101		)	(16,785		)
-Accrued interest	8,502			7,346
-Accrued compensation	(10,461		)	(7,002		)
-Over recovered regulatory clause revenues	(27,838		)	15,871
-Other current liabilities	282			294
Net cash provided from operating activities	122,444			44,182
Investing Activities:
Property additions	(789,021		)	(763,641		)
Cost of removal, net of salvage	(2,033		)	(1,217		)
Construction payables	23,314			57,283
Capital grant proceeds	4,500			6,146
Other investing activities	(11,172		)	(9,690		)
Net cash used for investing activities	(774,412		)	(711,119		)
Financing Activities:
Proceeds —
Capital contributions from parent company	351,198			277,633
Bonds-Other	15,814			—
Senior notes issuances	—			400,000
Interest-bearing refundable deposit related to asset sale	—			150,000
Other long-term debt issuances	350,000			—
Redemptions —
Capital leases	—			(633		)
Other long-term debt	—			(165,000		)
Return of paid in capital	(16,424		)	—
Payment of preferred stock dividends	(866		)	(866		)
Payment of common stock dividends	(71,956		)	(53,400		)
Other financing activities	(1,431		)	998
Net cash provided from financing activities	626,335			608,732
Net Change in Cash and Cash Equivalents	(25,633		)	(58,205		)
Cash and Cash Equivalents at Beginning of Period	145,008			211,585
Cash and Cash Equivalents at End of Period	$	119,375		$	153,380
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $37,036 and $29,433, net of $23,613 and $12,476 capitalized for 2013 and 2012, respectively)	$	13,423		$	16,603
Income taxes, net	(64,062		)	(7,756		)
Noncash transactions—accrued property additions at end of period	238,177			193,184

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, 2013			At December 31, 2012
	(in thousands)
Current Assets:
Cash and cash equivalents	$	119,375		$	145,008
Receivables —
Customer accounts receivable	44,767			29,561
Unbilled revenues	44,531			32,688
Other accounts and notes receivable	4,432			7,517
Affiliated companies	38,093			27,160
Accumulated provision for uncollectible accounts	(364		)	(373		)
Fossil fuel stock, at average cost	142,189			176,378
Materials and supplies, at average cost	40,769			34,260
Other regulatory assets, current	59,418			55,302
Prepaid income taxes	267,079			129,835
Other current assets	34,674			17,170
Total current assets	794,963			654,506
Property, Plant, and Equipment:
In service	3,171,850			3,036,159
Less accumulated provision for depreciation	1,098,201			1,065,474
Plant in service, net of depreciation	2,073,649			1,970,685
Construction work in progress	2,183,548			2,393,145
Total property, plant, and equipment	4,257,197			4,363,830
Other Property and Investments	4,939			4,887
Deferred Charges and Other Assets:
Deferred charges related to income taxes	95,233			71,869
Other regulatory assets, deferred	251,268			236,225
Other deferred charges and assets	34,415			42,304
Total deferred charges and other assets	380,916			350,398
Total Assets	$	5,438,015		$	5,373,621

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, 2013			At December 31, 2012
	(in thousands)
Current Liabilities:
Securities due within one year	$	342,285		$	276,471
Interest-bearing refundable deposit related to asset sale	150,000			150,000
Accounts payable —
Affiliated	57,523			54,769
Other	278,121			262,992
Customer deposits	14,490			14,202
Accrued taxes —
Accrued income taxes	7,208			2,339
Other accrued taxes	40,912			69,376
Accrued interest	38,878			30,376
Accrued compensation	5,244			15,706
Other regulatory liabilities, current	9,101			5,376
Over recovered regulatory clause liabilities	49,500			77,338
Liabilities from risk management activities	8,947			13,116
Other current liabilities	18,769			18,766
Total current liabilities	1,020,978			990,827
Long-term Debt	1,866,835			1,564,462
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	99,251			244,958
Deferred credits related to income taxes	9,240			10,106
Accumulated deferred investment tax credits	420,376			370,554
Employee benefit obligations	158,006			157,421
Other cost of removal obligations	152,211			143,461
Other regulatory liabilities, deferred	79,995			56,984
Other deferred credits and liabilities	49,664			52,860
Total deferred credits and other liabilities	968,743			1,036,344
Total Liabilities	3,856,556			3,591,633
Redeemable Preferred Stock	32,780			32,780
Common Stockholder's Equity:
Common stock, without par value —
Authorized —1,130,000 shares
Outstanding—1,121,000 shares	37,691			37,691
Paid-in capital	1,737,952			1,401,520
Retained earnings (deficit)	(218,676		)	318,710
Accumulated other comprehensive loss	(8,288		)	(8,713		)
Total common stockholder's equity	1,548,679			1,749,208
Total Liabilities and Stockholder's Equity	$	5,438,015		$	5,373,621

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

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SECOND QUARTER 2013 vs. SECOND QUARTER 2012

AND

YEAR-TO-DATE 2013 vs. YEAR-TO-DATE 2012

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 the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising 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. In addition, Mississippi Power is currently constructing the Kemper IGCC. Mississippi Power has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

On March 5, 2013, the Mississippi PSC issued an order with respect to Mississippi Power's request for an increase in rates which allows Mississippi Power an annual rate designed to collect $125 million for 2013, with such amounts to be recorded as a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service, increasing to $156 million in 2014, which represents a 15% and 3% increase in retail rates for 2013 and 2014, respectively. Also on March 5, 2013, the Mississippi PSC approved a $15.3 million, or 1.9%, increase in annual rates under Mississippi Power's PEP and a $35.5 million, or 4.7%, decrease in annual rates due to an annual adjustment to the retail fuel cost recovery factor, with all new rates effective March 19, 2013.

On July 29, 2013, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately $3.87 billion, net of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and certain exceptions to the $2.88 billion cost cap established by the Mississippi PSC. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, excluding the cost of the lignite mine and equipment, the cost of the carbon dioxide (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) and net of the DOE Grants.

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/A and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.

Mississippi Power continues to focus on several key performance indicators. 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/A. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for information regarding the revisions to the cost estimate for the Kemper

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IGCC that negatively impact Mississippi Power's actual performance on net income after dividends on preferred stock, one of its key performance indicators, for 2013 as compared to the target.

RESULTS OF OPERATIONS

Net Income (Loss)

N/M - Not meaningful

Mississippi Power's net loss after dividends on preferred stock for the second quarter 2013 was $219.1 million compared to net income after dividends on preferred stock of $35.0 million for the corresponding period in 2012. The decrease was primarily related to a revision 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 $245.3 million of DOE Grants and the Cost Cap Exceptions. The loss was partially offset by an increase in retail revenues primarily due to a base rate increase and a rate increase related to the Kemper IGCC cost recovery, an increase in AFUDC equity primarily related to the construction of the Kemper IGCC, and a decrease in non-fuel operations and maintenance expenses.

For year-to-date 2013, the net loss after dividends on preferred stock was $465.4 million compared to net income after dividends on preferred stock of $60.3 million for the corresponding period in 2012. The decrease was primarily related to the estimated probable losses on the construction of the Kemper IGCC recorded in the first and second quarters of 2013. These losses were partially offset by an increase in territorial base revenues primarily due to wholesale base rate increases effective April 1, 2012 and April 1, 2013, a rate increase related to the Kemper IGCC cost recovery, an increase in AFUDC equity primarily related to the construction of the Kemper IGCC, and a decrease in non-fuel operations and maintenance expenses.

Retail Revenues

In the second quarter 2013, retail revenues were $214.3 million compared to $192.2 million for the corresponding period in 2012. For year-to-date 2013, retail revenues were $382.6 million compared to $358.4 million for the corresponding period in 2012.

Details of the changes in retail revenues were as follows:



	Second Quarter 2013					Year-to-Date 2013
	(in millions)			(% change)		(in millions)		(% change)
Retail – prior year	$	192.2				$	358.4
Estimated change in –
Rates and pricing	8.2			4.3		4.5		1.3
Sales growth (decline)	3.2			1.7		0.4		0.1
Weather	(3.0		)	(1.6	)	0.5		0.1
Fuel and other cost recovery	13.7			7.1		18.8		5.2
Retail – current year	$	214.3		11.5	%	$	382.6	6.7	%

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related to the Kemper IGCC cost recovery. The year-to-date increase was partially offset by a $4.7 million accrual for a retail rate refund related to the 2012 PEP lookback filing.

Revenues attributable to changes in sales increased in the second quarter 2013 when compared to the corresponding period in 2012. Weather-adjusted KWH energy sales to commercial customers increased 1.6% when compared to the corresponding period in 2012 due to improved commercial economic activity. Weather-adjusted KWH energy sales to residential customers decreased 1.0% when compared to the corresponding period in 2012 due to slower residential growth. KWH energy sales to industrial customers decreased 0.3% due to planned maintenance outages for several larger customers.

Revenues attributable to changes in sales increased for year-to-date 2013 when compared to the corresponding period in 2012. Weather-adjusted KWH energy sales to commercial customers increased 0.3% when compared to the corresponding period in 2012 due to a slight increase in the number of customers and improving economic conditions. Weather-adjusted KWH energy sales to residential customers decreased 1.4% when compared to the corresponding period in 2012 due to slower residential growth. KWH energy sales to industrial customers decreased 2.2% due to planned maintenance outages for several larger customers.

Fuel and other cost recovery revenues increased in the second quarter and year-to-date 2013 when compared to the corresponding periods in 2012 primarily as a result of higher recoverable fuel costs. 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.

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

Wholesale Revenues – Non-Affiliates

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 revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

In the second quarter 2013, wholesale revenues from non-affiliates were $71.9 million compared to $64.1 million for the corresponding period in 2012. The increase was due to a $1.8 million increase in base revenues primarily resulting from a wholesale base rate increase effective April 1, 2013 and a $6.0 million increase in energy revenues, of which $6.8 million was associated with higher fuel prices, partially offset by a $0.8 million decrease associated with a decrease in KWH sales due to less favorable weather in the second quarter 2013 compared to the corresponding period in 2012.

For year-to-date 2013, wholesale revenues from non-affiliates were $137.0 million compared to $118.3 million for the corresponding period in 2012. The increase was due to an $8.0 million increase in base revenues primarily resulting from wholesale base rate increases effective April 1, 2012 and April 1, 2013 and a $10.7 million increase in energy revenues, of which $9.3 million was associated with higher fuel prices and $1.4 million was associated with an increase in KWH sales due to higher demand resulting from more favorable weather for year-to-date 2013 compared to the corresponding period in 2012.

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Wholesale Revenues – Affiliates

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliated sales and purchases 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 2013, wholesale revenues from affiliates were $15.9 million compared to $5.3 million for the corresponding period in 2012. The increase was primarily due to a $10.6 million increase in energy revenues, of which $5.5 million was associated with an increase in KWH sales and $5.1 million was associated with higher prices.

For year-to-date 2013, wholesale revenues from affiliates were $24.2 million compared to $9.4 million for the corresponding period in 2012. The increase was primarily due to a $14.8 million increase in energy revenues, of which $8.4 million was associated with an increase in KWH sales and $6.4 million was associated with higher prices.

Fuel and Purchased Power Expenses



	Second Quarter 2013 vs. Second Quarter 2012					Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	36.7		34.8		$	52.7		27.1
Purchased power – non-affiliates	0.7			56.8		—			2.2
Purchased power – affiliates	(6.9		)	(63.8	)	(6.1		)	(30.9	)
Total fuel and purchased power expenses	$	30.5				$	46.6

In the second quarter 2013, total fuel and purchased power expenses were $147.9 million compared to $117.4 million for the corresponding period in 2012. The increase was primarily due to a $17.4 million increase in the total volume of KWHs generated and purchased and a $13.1 million increase in the cost of fuel and purchased power.

For year-to-date 2013, total fuel and purchased power expenses were $263.5 million compared to $216.9 million for the corresponding period in 2012. The increase was primarily due to a $26.5 million increase in the total volume of KWHs generated and purchased and a $20.1 million increase in the cost of fuel and purchased power.

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

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



	Second Quarter 2013	Second Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (millions of KWHs)	3,753	3,359	6,957	6,341
Total purchased power (millions of KWHs)	209	466	601	912
Sources of generation (percent) –
Coal	43	29	35	25
Gas	57	71	65	75
Cost of fuel, generated (cents per net KWH) –
Coal	4.90	4.88	4.94	4.83
Gas	3.39	2.72	3.17	2.77
Average cost of fuel, generated (cents per net KWH)	4.09	3.39	3.85	3.34
Average cost of purchased power (cents per net KWH)	2.73	2.57	2.79	2.50

Fuel

In the second quarter 2013, fuel expense was $142.2 million compared to $105.5 million for the corresponding period in 2012. The increase was primarily due to a 24.6% increase in the average cost of natural gas per KWH generated and a 11.9% increase in the volume of KWHs generated resulting from higher energy demand in the second quarter 2013 as compared to the corresponding period in 2012.

For year-to-date 2013, fuel expense was $246.8 million compared to $194.1 million for the corresponding period in 2012. The increase was primarily due to a 14.4% increase in the average cost of natural gas per KWH generated and a 10.3% increase in the volume of KWHs generated resulting from higher energy demand in 2013 as compared to the corresponding period in 2012.

Purchased Power - Non-Affiliates

In the second quarter 2013, purchased power expense from non-affiliates was $1.8 million compared to $1.1 million for the corresponding period in 2012. The increase was primarily the result of a 25.3% increase in the volume of KWHs purchased and a 24.9% increase in the average cost per KWH purchased.

For year-to-date 2013, the change in purchased power expense from non-affiliates as compared to the corresponding period in 2012 was not material.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy 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 2013, purchased power expense from affiliates was $3.9 million compared to $10.8 million for the corresponding period in 2012. The decrease was primarily due to a 69.8% decrease in the volume of KWHs purchased, partially offset by a 19.9% increase in the average cost per KWH purchased.

For year-to-date 2013, purchased power expense from affiliates was $13.6 million compared to $19.7 million for the corresponding period in 2012. The decrease was primarily due to a 41.6% decrease in the volume of KWHs purchased, partially offset by an 18.3% increase in the average cost per KWH purchased.

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Other Operations and Maintenance Expenses

In the second quarter 2013, other operations and maintenance expenses were $54.5 million compared to $60.5 million for the corresponding period in 2012. The decrease was primarily due to a $3.1 million decrease in labor expenses, a $2.7 million decrease in generation maintenance expenses related to scheduled outages, and a $1.0 million decrease in transmission and distribution expenses related to overhead line maintenance and vegetation management costs. These decreases were partially offset by a $0.8 million increase in pension expense.

For year-to-date 2013, other operations and maintenance expenses were $109.3 million compared to $115.4 million for the corresponding period in 2012. The decrease was primarily due to a $3.7 million decrease in labor expenses, a $4.7 million decrease in generation maintenance expenses related to scheduled outages, and a $1.9 million decrease in transmission and distribution expenses related to overhead line maintenance and vegetation management costs. These decreases were partially offset by a $3.8 million increase in administrative and general expenses primarily related to pension expense.

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

Taxes Other Than Income Taxes

In the second quarter 2013, taxes other than income taxes were $20.3 million compared to $18.6 million for the corresponding period in 2012. The increase was primarily due to a $2.2 million increase in franchise taxes, partially offset by a $0.6 million decrease in payroll taxes due to a decrease in labor expenses.

For year-to-date 2013, taxes other than income taxes were $39.7 million compared to $40.3 million for the corresponding period in 2012. The decrease was primarily due to a $1.7 million decrease in ad valorem taxes and a $0.6 million decrease in payroll taxes due to a decrease in labor expenses, partially offset by a $1.7 million increase 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

N/M - Not meaningful

In the second quarter 2013 and year-to-date 2013, estimated probable losses on the Kemper IGCC of $450.0 million and $912.0 million, respectively, were recorded to 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 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/A 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.

Allowance for Equity Funds Used During Construction

In the second quarter 2013, AFUDC equity was $29.0 million compared to $13.9 million for the corresponding period in 2012. For year-to-date 2013, AFUDC equity was $55.1 million compared to $25.7 million for the corresponding period in 2012. These increases were primarily due to the construction of 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/A and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

Other Income (Expense), Net

N/M - Not meaningful

In the second quarter 2013, other income (expense), net was $(2.3) million compared to $(0.2) million for the corresponding period in 2012. For year-to-date 2013, other income (expense), net was $(3.8) million compared to $(0.3) million for the corresponding period in 2012. These decreases were due to a $1.4 million and a $2.8 million increase in consulting fees for the second quarter 2013 and year-to-date 2013, respectively.

Interest Expense, Net of Amounts Capitalized

In the second quarter 2013, interest expense, net of amounts capitalized was $10.4 million compared to $13.0 million for the corresponding period in 2012. Amounts capitalized primarily resulting from AFUDC debt associated with the Kemper IGCC in the second quarter 2013 were $12.5 million compared to $5.9 million for the corresponding period in 2012. This increase was partially offset by a $3.3 million increase in interest expense associated with issuances of new long-term debt and a $0.9 million increase in interest expense on the regulatory liability related to the Kemper IGCC rate recovery.

For year-to-date 2013, the change in interest expense, net of amounts capitalized was not material when compared to the corresponding period in 2012. Amounts capitalized primarily resulting from AFUDC debt associated with the Kemper IGCC for year-to-date 2013 were $23.6 million compared to $12.5 million for the corresponding period in 2012. The change in AFUDC debt along with a $2.1 million decrease in interest expense associated with the redemption of long-term debt in 2012 was offset by a $9.0 million increase in interest expense associated with issuances of new long-term debt, a $3.3 million increase in interest expense on the SMEPA deposit received in March 2012 related to the pending purchase of an undivided interest in the Kemper IGCC, and a $0.9 million increase in interest expense on the regulatory liability related to the Kemper IGCC rate recovery.

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

Income Taxes

N/M - Not meaningful

In the second quarter 2013, income taxes were $(153.3) million compared to $12.2 million for the corresponding period in 2012. For year-to-date 2013, income taxes were $(322.5) million compared to $20.6 million for the corresponding period in 2012. These decreases were primarily due to the reduction in pre-tax earnings (loss) related to the estimated probable losses for the Kemper IGCC.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of selling electricity. These factors include Mississippi Power's ability to 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 successful completion of ongoing construction projects, primarily the Kemper IGCC. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced 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/A.

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 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/A for additional information.

Climate Change Litigation

Kivalina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K/A for additional information. On May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

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Environmental Statutes and Regulations

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/A for information regarding the EPA's MATS rule, the Cross State Air Pollution Rule, and the EPA's SO₂ rule.

On July 25, 2013, the EPA issued initial nonattainment area designations under the one-hour National Ambient Air Quality Standard for SO₂ based on ambient air quality monitoring data. No areas within Mississippi Power's service territory were designated as nonattainment under this rule. The EPA has deferred designation of attainment and unclassifiable areas and may designate additional areas as nonattainment in the future, which could include areas within Mississippi Power's service territory. The ultimate outcome of this matter 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/A for additional information regarding the EPA's proposed revision of the current steam electric effluent guidelines and rule for cooling water intake structures.

On June 7, 2013, the EPA published a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Mississippi Power's facilities, which could result in significant capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K/A for additional information regarding the proposed regulation of greenhouse gas emissions through establishment of new source performance standards.

Although the outcome of the proposed regulations and guidelines cannot be determined at this time, additional restrictions on Mississippi Power's greenhouse gas emissions at the federal or state level could result in significant additional compliance costs, including capital expenditures. These costs could affect future unit retirement and

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replacement decisions. Also, additional compliance costs and costs related to unit retirements could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" and "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A and Note (B) to the Condensed Financial Statement under "FERC Matters" herein for additional information.

In March 2012, Mississippi Power entered into a settlement agreement with its wholesale customers to increase wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff by approximately $22.6 million annually, and the FERC approved interim rates effective May 1, 2012. In September 2012, Mississippi Power, with its wholesale customers, filed a final settlement agreement with the FERC. On May 3, 2013, Mississippi Power received an order from the FERC accepting the settlement agreement.

On April 1, 2013, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an additional increase in the MRA cost-based electric tariff, which was accepted by the FERC on May 30, 2013. In accordance with the 2013 settlement agreement, base rates under the MRA cost-based electric tariff increased approximately $24.2 million annually, effective April 1, 2013. The amount of base rate revenues to be received in 2013 from the agreed upon increase will be approximately $18.0 million.

PSC Matters

General

In August 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing for informational purposes only the ROE formulas used by Mississippi Power and all other regulated electric utilities in Mississippi. On March 14, 2013, the Mississippi Public Utilities Staff (MPUS) filed with the Mississippi PSC its report on the ROE formulas used by Mississippi Power and all other regulated electric utilities in Mississippi. The ultimate outcome of this matter cannot be determined at this time.

Energy Efficiency

On July 11, 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, are required to be filed within six months of the order and will be in effect for two to three years. An annual report addressing the performance of all energy efficiency programs will be required to be filed. Mississippi Power does not currently anticipate that additional annual costs to comply with the rule will be material. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Performance Evaluation Plan" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K/A for additional information regarding Mississippi Power's base rates.

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that are currently under review. On March 5, 2013, the revised annual PEP filing for 2013 was approved by the Mississippi PSC, which resulted in a rate increase of 1.925%, or $15.3 million, annually, with the new rates effective March 19, 2013. Mississippi Power may be entitled to $3.3 million in additional revenues in 2013 as a result of the late implementation of the 2013 PEP rate increase.

On March 15, 2013, Mississippi Power submitted its annual PEP lookback filing for 2012, which indicated a refund due to customers of $4.7 million, which was accrued in retail revenues. On May 1, 2013, the MPUS contested the filing.

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

System Restoration Rider

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – System Restoration Rider" in Item 8 of the Form 10-K/A for additional information.

On June 4, 2013, the Mississippi PSC approved Mississippi Power's request to continue a zero System Restoration Rider rate for 2013 and to accrue approximately $3.2 million to the property damage reserve in 2013.

Environmental Compliance Overview Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Compliance Overview Plan" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K/A for information on Mississippi Power's annual environmental filing with the Mississippi PSC.

In April 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. In May 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project in December 2015. As of June 30, 2013, total project expenditures were $232.9 million, with Mississippi Power's portion being $116.4 million. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K/A for information regarding Mississippi Power's fuel cost recovery.

On January 18, 2013, in compliance with Mississippi Power's filing requirement, Mississippi Power requested an annual adjustment of the retail fuel cost recovery factor in an amount equal to a decrease of 4.7%, or $35.5 million, of total 2012 retail revenue. The Mississippi PSC approved the retail fuel cost recovery factor on March 5, 2013, with the new rates effective March 19, 2013.

At June 30, 2013, the amount of over recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $38.0 million compared to $56.6 million at December 31, 2012. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At June 30, 2013, the amount of over recovered wholesale MRA and MB fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $11.9 million and $0.9 million, respectively, compared to $19.0 million and $2.1 million, respectively, at December 31, 2012. In addition, at June 30, 2013, the amount of under recovered MRA emissions allowance cost included on Mississippi Power's Condensed Balance Sheets herein was $1.4 million compared to $0.4 million at December 31, 2012. Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel

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cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.

Ad Valorem Tax Adjustment

On March 27, 2013, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2013, which requested an annual rate increase of 0.9%, or $7.1 million, due to an increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4. On June 4, 2013, the filing was approved by the Mississippi PSC. See RESULTS OF OPERATIONS – "Taxes Other Than Income Taxes" of Mississippi Power in Item 7 of the Form 10-K/A for additional information.

Storm Damage Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Storm Damage Cost Recovery" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Storm Damage Cost Recovery" in Item 8 in the Form 10-K/A for information regarding Mississippi Power's storm damage cost recovery. Mississippi Power maintains a reserve to cover the cost of damage from major storms to its transmission and distribution facilities and generally the cost of uninsured damage to its generation facilities and other property. At June 30, 2013, the balance in the storm reserve was $58.5 million.

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/A for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Project Approval

In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC (2010 MPSC Order) located in Kemper County, Mississippi. The Sierra Club filed an appeal of the Mississippi PSC's issuance of the CPCN and, in March 2012, the Mississippi Supreme Court reversed the decision of the Chancery Court upholding the 2010 MPSC Order and remanded the matter to the Mississippi PSC. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN. In April 2012, the Mississippi PSC issued a detailed order (2012 MPSC Order) confirming the CPCN for the Kemper IGCC, which the Sierra Club appealed to the Chancery Court. In December 2012, the Chancery Court affirmed the 2012 MPSC Order which confirmed the issuance of the CPCN for the Kemper IGCC. On January 8, 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court. The ultimate outcome of the CPCN challenge cannot be determined at this time.

The Kemper IGCC is currently under construction and will utilize an integrated coal gasification combined cycle 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 operations on June 5, 2013. In connection with the Kemper IGCC, Mississippi Power also is constructing and plans to operate approximately 61 miles of CO₂ pipeline infrastructure. The Kemper IGCC and the CO₂ pipeline are scheduled to be placed in-service in May 2014. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO₂ Pipeline Facilities" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO₂ Pipeline Facilities" in Item 8 of the Form 10-K/A for additional information regarding the lignite mine and the CO₂ pipeline.

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Kemper IGCC Cost Estimate

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC Order was $2.4 billion, net of $245 million of DOE Grants, 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 Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions as contemplated in the Settlement Agreement (described below) and the 2012 MPSC Order, which includes the Cost Cap Exceptions. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

On July 29, 2013, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately $3.87 billion, net of the DOE Grants and the Cost Cap Exceptions. Estimated amounts of the Cost Cap Exceptions include $245 million for the lignite mine and equipment, $115 million for the CO₂ pipeline facilities, $324 million of AFUDC, and $101 million of other general exceptions. The revised cost estimate reflects additional cost pressures, including labor costs, piping and other material costs, engineering and support costs, start-up costs, and decreases in construction labor productivity. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, excluding the Cost Cap Exceptions and net of the DOE Grants. As a result of the revisions to the cost estimate, Mississippi Power recorded additional pre-tax charges to income for estimated probable losses of $462.0 million ($285.3 million after tax) and $450.0 million ($277.9 million after tax) in the first and second quarters of 2013, respectively. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC."

Mississippi Power's analysis of the estimated cost and schedule to complete the Kemper IGCC will be ongoing throughout the construction period. Mississippi Power could experience further construction cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, or contractor or supplier delay or non-performance under construction or other agreements. Furthermore, Mississippi Power could also experience schedule delays associated with start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems, which would result in further cost increases or require repayment of a portion of investment tax credits received. 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 will be reflected in Mississippi Power's statements of income and these changes could be material.

As of June 30, 2013, Mississippi Power had spent a total of $3.29 billion on the Kemper IGCC. These costs include $2.74 billion for the portion of the Kemper IGCC subject to the construction cost cap, $210.2 million for the lignite mine and equipment, $86.1 million for the CO₂ pipeline facilities, $193.8 million of AFUDC, and $55.2 million of other costs, including certain general exceptions and certain regulatory assets. Of this total, $2.24 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $990 million), $49.7 million in other regulatory assets, $3.9 million in other deferred charges and assets on Mississippi Power's Condensed Balance Sheet herein, and $1.0 million was previously expensed. Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period. This includes deferred costs associated with the generation resource planning, evaluation, and screening activities. The amortization period for the regulatory asset will be determined by the Mississippi PSC at a later date. 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.

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

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Rate Recovery of Kemper IGCC Costs

See "FERC Matters" for additional information regarding Mississippi Power's MRA cost-based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See "Baseload Act" herein for additional information.

On January 24, 2013, Mississippi Power entered into a settlement agreement (Settlement Agreement) with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC. Under the 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 as well as any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. Mississippi Power intends to finance (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 the Cost Cap Exceptions, (2) the accrued AFUDC, and (3) exceptions not provided for in the Seven-Year Rate Plan (discussed below) through securitization as provided in State of Mississippi legislation. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective after the Kemper IGCC is placed in service and following completion of the Mississippi PSC's final prudence review of costs for the Kemper IGCC.

Under the terms of the Settlement Agreement, Mississippi Power and the Mississippi PSC agreed to follow certain regulatory procedures and schedules for resolving the cost recovery matters related to the Kemper IGCC. These procedures and schedules include the following: (1) Mississippi Power's filing on January 25, 2013 of a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service; (2) the Mississippi PSC's decision on that matter on March 5, 2013; (3) Mississippi Power's collaboration with the MPUS to file with the Mississippi PSC within three months of the Settlement Agreement a rate recovery plan for the Kemper IGCC for the first seven years of its operation, along with a proposed revenue requirement under such plan for 2014 through 2020 (Seven-Year Rate Plan) (which was made on February 26, 2013 and updated on March 22, 2013); (4) the Mississippi PSC's decision on the Seven-Year Rate Plan within four months of that filing (which is now expected to occur in late 2013); (5) Mississippi Power's agreement to limit the portion of prudently-incurred Kemper IGCC costs to be included in rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, excluding AFUDC, provided that this limitation will not prevent Mississippi Power from securing alternate financing to recover any prudently-incurred Kemper IGCC costs, including plant costs above the $2.4 billion certificated cost estimate and AFUDC, not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement; and (6) the Mississippi PSC's completion of its prudence review of the Kemper IGCC costs incurred through 2012 within six months of the Settlement Agreement (which is now expected to occur in early 2014 for costs incurred through March 31, 2013), an additional prudence review upon considering the Seven-Year Rate Plan for costs incurred through the most recent reporting period (which is now expected to be unnecessary due to the July 26, 2013 scheduling order discussed below), and a final prudence review of the remaining project costs within six months of the Kemper IGCC's in-service date (which is now expected to include a prudence review of all costs incurred after March 31, 2013). The Settlement Agreement provides that Mississippi Power may terminate the agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization was enacted into law on February 26, 2013. Mississippi Power is currently working with the Mississippi PSC and the MPUS to implement the procedural schedules set forth in the Settlement Agreement and additional variations to the schedule are likely.

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rate impacts beginning in May 2014 when the Kemper IGCC is expected to be placed in service. As of June 30, 2013, $27.0 million had been collected and recorded as a regulatory liability with $3.0 million included in other regulatory liabilities, current and $24.0 million included in other regulatory liabilities, deferred in Mississippi Power's Condensed Balance Sheet herein. On March 21, 2013, a legal challenge to the 2013 Kemper IGCC Order was filed with the Mississippi Supreme Court.

Because the 2013 Kemper IGCC Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act described below, Mississippi Power continues to record AFUDC on the Kemper IGCC during the construction period. 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's rate plans filed pursuant to the Settlement Agreement contemplate the continued accrual of AFUDC through the May 2014 expected in-service date.

On March 22, 2013, Mississippi Power, in compliance with the 2013 Kemper IGCC Order, filed a revision to the Seven-Year Rate Plan with the Mississippi PSC for the Kemper IGCC for 2014 through 2020, the first seven years of operation of the Kemper IGCC. The Seven-Year Rate Plan, which contemplates Mississippi Power's sale of a 15% undivided ownership interest in the Kemper IGCC, proposes recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. Mississippi Power expects a decision from the Mississippi PSC regarding the Seven-Year Rate Plan in late 2013. The 2013 Kemper IGCC Order, which increased rates beginning on March 19, 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization of the April 2014 regulatory liability balance to be used to mitigate rate impacts from the expected in-service date of May 2014 through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan filing, Mississippi Power proposes annual rate recovery to remain the same from 2014 through 2020. While it is the intent of Mississippi Power for the actual revenue requirement to equal the proposed revenue requirement, Mississippi Power proposes that the annual differences through 2020 for certain items contemplated in the Seven-Year Rate Plan will be deferred, subject to accrual of carrying costs, and the cumulative balance will be reviewed at the end of the term of the Settlement Agreement by the Mississippi PSC to determine the disposition of any potential remaining deferred balance.

The revenue requirements set forth in Mississippi Power's Seven-Year Rate Plan described above assume, among other things, the Kemper IGCC will be placed in service in May 2014, the sale of a 15% undivided interest in the Kemper IGCC to SMEPA will be completed as described herein, Mississippi Power's receipt of the benefits relating to tax credits described herein, and recovery of the Cost Cap Exceptions described herein.

On July 26, 2013, the Mississippi PSC issued a scheduling order for the prudence review of the Kemper IGCC costs incurred through March 31, 2013. Mississippi Power expects a decision from the Mississippi PSC in early 2014.

The ultimate outcome of these matters, including the resolution of legal challenges, determinations of prudency and the specific manner of recovery of costs relating to the Kemper IGCC, is subject to further regulatory actions and cannot be determined at this time.

Proposed Sale of Undivided Interest to SMEPA

In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In February 2012, the Mississippi PSC approved the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. In June 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012, and reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. On December 31, 2012, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2013. The sale and transfer of an interest in the Kemper IGCC to SMEPA is subject to approval by the Mississippi PSC.

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SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.

In March 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposit has been presented as a current liability in Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Mississippi Power's Condensed Statements of Cash Flows herein. On July 18, 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposit.

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

Baseload Act

In 2008, the Baseload Act was signed by the Governor of Mississippi and is designed to enhance the Mississippi PSC's authority to facilitate development and construction of base load generation in the State of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionality of the Baseload Act currently pending before the Mississippi Supreme Court. The ultimate outcome of the legal challenges to this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.

Tax Incentives

The IRS has allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Mississippi Power's utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the rules for Internal Revenue Code Section 48A investment tax credits. Through June 30, 2013, Mississippi Power had received or accrued tax benefits totaling $412 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. As a result of bonus tax depreciation on certain assets placed, or to be placed, in service in 2013 and 2014, and the subsequent reduction in federal taxable income, Mississippi Power estimates that it will be able to utilize all of these tax credits by June 30, 2014. IRS guidelines allow these unused tax credits to be carried forward for 20 years from the date received, if not utilized before then. In October 2012, Mississippi Power filed an application with the DOE for certification of the Kemper IGCC for additional tax credits under the Internal Revenue Code Section 48A (Phase III). On May 15, 2013, the IRS notified Mississippi Power that no Phase III tax credits were allocated to the Kemper IGCC.

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the tax credits will be subject to recapture if Mississippi Power fails to satisfy the in-service date requirements and CO₂ capture requirements described above.

On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and 50% bonus depreciation for property to be placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is expected to apply to the Kemper IGCC.

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

Income Tax Matters

Bonus Depreciation

On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property to be placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is expected to apply to the Kemper IGCC scheduled to be placed in service in May 2014.

Consequently, Mississippi Power's positive cash flow benefit is estimated to be between $150 million and $165 million in 2013.

Other Matters

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

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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/A. 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/A 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

Mississippi Power has revised its cost estimate to complete construction of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and the Cost Cap Exceptions. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, excluding the Cost Cap Exceptions and net of the DOE Grants. As a result of the revisions to the cost estimate, Mississippi Power recorded a pretax charge of $78 million in 2012, and additional pretax charges of $462 million and $450 million in the first and second quarters of 2013, respectively. 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 will be reflected in Mississippi Power's statements of income and these changes could be material. Mississippi Power's analysis will be ongoing throughout the construction period. Mississippi Power could experience further construction cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, or contractor or supplier delay or non-performance under construction or other agreements. Furthermore, Mississippi Power could also experience schedule delays associated with start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems, which would result in further cost increases or require repayment of a portion of investment tax credits received.

Given the significant judgment involved in estimating the future costs to complete construction, 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 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/A 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.

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/A and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Although earnings were negatively affected by the estimated probable losses relating to the Kemper IGCC, Mississippi Power's financial condition remained stable at June 30, 2013. These non-cash charges for the six months ended June 30, 2013 are expected to result in future cash expenditures with no return or recovery. Mississippi 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

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

Net cash provided from operating activities totaled $122.4 million for the first six months of 2013, an increase of $78.2 million as compared to the corresponding period in 2012. The increase in cash provided from operating activities is primarily due an increase in investment tax credits related to the Kemper IGCC, an increase in fossil fuel stock, the rate recovery increase for the Kemper IGCC, and an increase due to hedges settled in 2012, partially offset by a decrease in accounts receivable and a decrease in regulatory clause revenues due to an increase in fuel costs. Net cash used for investing activities totaled $774.4 million for the first six months of 2013 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $626.3 million for the first six months of 2013 primarily due to the issuances of bank notes and capital contributions from Southern Company. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2013 include a decrease in total property, plant, and equipment of $106.6 million, a decrease in accumulated deferred income taxes of $145.7 million, and a decrease in total common stockholder's equity of $200.5 million primarily due to the estimated probable losses on the Kemper IGCC, which was partially offset by an increase in paid-in capital of $336.4 million primarily due to capital contributions from Southern Company. Securities due within one year and long-term debt increased $368.2 million primarily due to the issuance of $350.0 million of bank notes and $15.8 million of revenue bonds. Prepaid income taxes and accumulated deferred investment tax credits increased $137.2 million and $49.8 million, respectively, primarily due to investment tax credits related to the Kemper IGCC.

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/A 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. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. Approximately $342.3 million will be required through June 30, 2014 to fund maturities of long-term debt.

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 on the construction of the Kemper IGCC. The construction program of Mississippi Power is estimated to include a base level investment of $1.5 billion, $736 million, and $255 million for 2013, 2014, and 2015, respectively. Included in these estimated amounts are expenditures related to construction of the Kemper IGCC of $1.3 billion and $456 million in 2013 and 2014, respectively, which are net of SMEPA's 15% proposed ownership share of the Kemper IGCC, which reflects costs of approximately $550 million in 2014. The estimated share for SMEPA reflects estimated construction costs relating to SMEPA's proposed ownership interest (including construction costs for all prior years relating to its proposed ownership interest).

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

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IGCC Cost Estimate" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Cost Estimate" herein for a discussion of factors that may impact the projected cost and/or schedule of the Kemper IGCC. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Except as described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily funds from operating cash flows, security issuances, term loans, short-term debt, 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. During the first six months of 2013, Mississippi Power received $350 million in capital contributions from Southern Company. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Mississippi Power in Item 7 of the Form 10-K/A for additional information.

Mississippi Power has received $245.3 million in DOE Grants that have been used for the construction of the Kemper IGCC. An additional $25 million in DOE Grants is expected to be received for the initial operation of the Kemper IGCC. 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.

Mississippi Power's current liabilities frequently exceed current assets because of the continued use of short-term obligations 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.

At June 30, 2013, Mississippi Power had approximately $119.4 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2013 were as follows:



Expires^(a)										Executable Term Loans				Due Within One Year
2013		2014		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	40	$	95	$	165	$	300	$	300	$	25	$	40	$	65	$	70

(a)No credit arrangements expire in 2015.

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

These credit arrangements provide liquidity support to Mississippi Power's commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2013 was approximately $40 million.

As reflected in the table above, in the first six months of 2013, Mississippi Power amended or renewed certain of its credit arrangements. In March 2013, Mississippi Power amended certain of its credit arrangements, which extended the maturity dates from 2014 to 2016 and revised the definition of debt to exclude securitized debt relating to the Kemper IGCC for purposes of calculating the debt covenant under these credit arrangements. 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. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration.

Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Mississippi Power. Mississippi Power is currently in compliance with all such covenants.

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

Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 2013				Short-term Debt During the Period^(a)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	—	—	%	$	12	0.2	%	$	38


(a)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2013.

Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At June 30, 2013, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $269 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

On May 24, 2013, S&P revised the ratings outlook for Southern Company and the traditional operating companies, including Mississippi Power, from stable to negative.

On May 30, 2013, Moody's placed the ratings of Mississippi Power on review for possible downgrade.

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Market Price Risk

Mississippi Power's market risk exposure relative to interest rate changes for the second quarter 2013 has not changed materially compared with the December 31, 2012 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Mississippi Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Mississippi Power continues to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As a result, Mississippi Power had no material change in market risk exposure for the second quarter 2013 when compared with the December 31, 2012 reporting period.

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three and six months ended June 30, 2013 were as follows:



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(5	)	$	(17	)
Contracts realized or settled	1			5
Current period changes^(a)	(9		)	(1		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(13	)	$	(13	)


(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$	(8	)	$	4
Natural gas options	—			—
Total changes	$	(8	)	$	4

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The net hedge volumes of energy-related derivative contracts were as follows:



	June 30, 2013	March 31, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	43	36	38
Commodity – Natural gas options	—	—	—
Total hedge volume	43	36	38

The weighted average swap contract cost above market prices was approximately $0.30 per mmBtu as of June 30, 2013, $0.13 per mmBtu as of March 31, 2013, and $0.44 per mmBtu as of December 31, 2012. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The costs associated with natural gas hedges are recovered through Mississippi Power's energy cost management clauses (ECM).

At June 30, 2013 and December 31, 2012, substantially all of Mississippi Power's energy-related derivative contracts were designated as regulatory hedges and are related to Mississippi Power's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM.

Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2013 and 2012 for energy-related derivative contracts that are not hedges were not material.

Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at June 30, 2013 were as follows:



				June 30, 2013 Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2	(13		)	(8		)	(5		)	—
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(13	)	$	(8	)	$	(5	)	$	—

For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Mississippi Power in Item 7 and Note 1 under "Financial Instruments" and Note 10 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A and Note (H) to the Condensed Financial Statements herein.

Financing Activities

In November 2012, Mississippi Power entered into a 366-day $100 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR. The first advance in the amount of $50 million was made in November 2012. In January 2013, the second advance in the amount of $50 million was made. The proceeds of the loan were used for working capital and for other general corporate purposes, including Mississippi Power's continuous construction program.

In March 2013, Mississippi Power entered into four two-year floating rate bank loans bearing interest based on one-month LIBOR. These term loans were for $50 million, $75 million, $75 million, and $100 million aggregate

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principal amounts, and proceeds were used for working capital and other general corporate purposes, including Mississippi Power's continuous construction program.

In March 2013, the Mississippi Business Finance Corporation (MBFC) issued $15.8 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A. Subsequent to June 30, 2013, MBFC issued $15.3 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A. The proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. See Note 6 to the financial statements of Mississippi Power under "Other Revenue Bonds" in Item 8 of the Form 10-K/A for additional information.

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

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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,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	216,647		$	177,865		$	440,076		$	318,422
Wholesale revenues, affiliates	88,638			105,950			166,829			217,738
Other revenues	1,970			1,990			3,297			3,326
Total operating revenues	307,255			285,805			610,202			539,486
Operating Expenses:
Fuel	110,630			91,551			230,002			180,629
Purchased power, non-affiliates	22,307			22,514			36,880			43,164
Purchased power, affiliates	6,282			2,914			14,147			5,254
Other operations and maintenance	62,661			40,205			113,611			88,594
Depreciation and amortization	44,898			34,016			85,058			65,929
Taxes other than income taxes	5,453			4,567			10,807			9,535
Total operating expenses	252,231			195,767			490,505			393,105
Operating Income	55,024			90,038			119,697			146,381
Other Income and (Expense):
Interest expense, net of amounts capitalized	(20,568		)	(13,949		)	(40,962		)	(27,591		)
Other income (expense), net	(1,691		)	(194		)	(1,948		)	(164		)
Total other income and (expense)	(22,259		)	(14,143		)	(42,910		)	(27,755		)
Earnings Before Income Taxes	32,765			75,895			76,787			118,626
Income taxes	4,843			29,293			19,673			42,708
Net Income	$	27,922		$	46,602		$	57,114		$	75,918

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Net Income	$	27,922	$	46,602	$	57,114	$	75,918
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $53, $- and $(120), respectively	—		88		—		(186		)
Reclassification adjustment for amounts included in net income, net of tax of $1,052, $956, $2,097 and $1,912, respectively	1,647		1,529		3,281		3,039
Total other comprehensive income (loss)	1,647		1,617		3,281		2,853
Comprehensive Income	$	29,569	$	48,219	$	60,395	$	78,771

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2013			2012
	(in thousands)
Operating Activities:
Net income	$	57,114		$	75,918
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	90,351			71,834
Deferred income taxes	13,693			58,921
Investment tax credits	16,443			1,750
Deferred revenues	(23,444		)	(16,431		)
Mark-to-market adjustments	(40		)	(3,847		)
Other, net	11,949			1,927
Changes in certain current assets and liabilities —
-Receivables	(23,335		)	(30,101		)
-Fossil fuel stock	(377		)	(3,301		)
-Materials and supplies	(2,560		)	(7,761		)
-Prepaid income taxes	(19,747		)	(32,804		)
-Other current assets	2,725			(377		)
-Accounts payable	(7,580		)	(494		)
-Accrued taxes	21,048			13,295
-Accrued interest	(41		)	409
-Other current liabilities	(390		)	(195		)
Net cash provided from operating activities	135,809			128,743
Investing Activities:
Plant acquisition	(111,600		)	(86,500		)
Property additions	(252,271		)	(67,846		)
Change in construction payables	106,795			(1,168		)
Payments pursuant to long-term service agreements	(22,469		)	(36,316		)
Investment in restricted cash	(20,000		)	3,015
Other investing activities	(206		)	(2,862		)
Net cash used for investing activities	(299,751		)	(191,677		)
Financing Activities:
Increase in notes payable, net	195,142			107,147
Proceeds —
Capital contributions	1,394			490
Other long-term debt	10,249			3,590
Repayments — Other long-term debt	(220		)	(650		)
Payment of common stock dividends	(64,560		)	(63,500		)
Other financing activities	8,212			2,746
Net cash provided from financing activities	150,217			49,823
Net Change in Cash and Cash Equivalents	(13,725		)	(13,111		)
Cash and Cash Equivalents at Beginning of Period	28,592			16,943
Cash and Cash Equivalents at End of Period	$	14,867		$	3,832
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $- and $12,941 capitalized for 2013 and 2012, respectively)	$	34,924		$	21,461
Income taxes, net	(3,799		)	13,708
Noncash transactions — accrued property additions at end of period	136,998			46,922

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2013		At December 31, 2012
	(in thousands)
Current Assets:
Cash and cash equivalents	$	14,867	$	28,592
Receivables —
Customer accounts receivable	85,142		62,857
Other accounts receivable	2,567		3,135
Affiliated companies	40,008		38,269
Fossil fuel stock, at average cost	21,993		21,616
Materials and supplies, at average cost	50,957		46,370
Prepaid service agreements—current	81,509		80,629
Prepaid income taxes	7,857		4,498
Other prepaid expenses	2,848		5,637
Assets from risk management activities	157		375
Total current assets	307,905		291,978
Property, Plant, and Equipment:
In service	4,076,217		4,059,839
Less accumulated provision for depreciation	828,819		786,620
Plant in service, net of depreciation	3,247,398		3,273,219
Construction work in progress	399,616		24,835
Total property, plant, and equipment	3,647,014		3,298,054
Other Property and Investments:
Goodwill	1,839		1,839
Other intangible assets, net of amortization of $4,378 and $3,141 at June 30, 2013 and December 31 2012, respectively	44,742		45,979
Total other property and investments	46,581		47,818
Deferred Charges and Other Assets:
Prepaid long-term service agreements	63,929		100,921
Other deferred charges and assets — affiliated	6,752		3,468
Other deferred charges and assets — non-affiliated	67,134		37,688
Total deferred charges and other assets	137,815		142,077
Total Assets	$	4,139,315	$	3,779,927

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2013		At December 31, 2012
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,430	$	259
Notes payable — non-affiliated	266,110		70,968
Accounts payable —
Affiliated	65,030		65,832
Other	126,728		26,204
Accrued taxes —
Accrued income taxes	17,030		87
Other accrued taxes	9,957		3,031
Accrued interest	22,218		22,259
Construction holdbacks	31,000		6,000
Liabilities from risk management activities	593		669
Other current liabilities	3,241		2,263
Total current liabilities	543,337		197,572
Long-term Debt	1,314,970		1,306,099
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	566,531		550,685
Investment tax credits	164,878		167,130
Deferred capacity revenues — affiliated	6,629		19,514
Other deferred credits and liabilities — affiliated	2,130		2,638
Other deferred credits and liabilities — non-affiliated	4,032		5,863
Total deferred credits and other liabilities	744,200		745,830
Total Liabilities	2,602,507		2,249,501
Redeemable Noncontrolling Interest	17,222		8,069
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—		—
Paid-in capital	1,028,942		1,027,548
Retained earnings	488,139		495,585
Accumulated other comprehensive income (loss)	2,505		(776		)
Total common stockholder's equity	1,519,586		1,522,357
Total Liabilities and Stockholder's Equity	$	4,139,315	$	3,779,927

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

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SECOND QUARTER 2013 vs. SECOND QUARTER 2012

AND

YEAR-TO-DATE 2013 vs. YEAR-TO-DATE 2012

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 continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into PPAs primarily with investor owned utilities, independent power producers, municipalities, and electric cooperatives.

In accordance with this overall growth strategy, on April 23, 2013 Southern Power and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Campo Verde Solar, LLC (Campo Verde). Campo Verde is constructing an approximately 139-MW solar facility in Southern California that is expected to begin commercial operation in the fourth quarter 2013. The output of the plant is contracted under a 20-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities. See Note (I) to the Condensed Financial Statements herein for additional information.

To evaluate operating results and to ensure Southern Power's ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (Peak Season EFOR), contract availability, and net income. Peak Season EFOR defines the hours during peak demand times when Southern Power's generating units are not available due to forced outages (the lower the better). Contract availability measures the percentage of scheduled hours delivered. Net income is the primary measure of Southern Power's financial performance.

RESULTS OF OPERATIONS

Net Income

Southern Power's net income for the second quarter 2013 was $27.9 million compared to $46.6 million for the corresponding period in 2012. Net income for year-to-date 2013 was $57.1 million compared to $75.9 million for the corresponding period in 2012. The decreases were primarily due to increases in depreciation, interest expense, and other operations and maintenance expenses, partially offset by an increase in capacity revenues and a decrease in income taxes.

Wholesale Revenues – Non-Affiliates

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 that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

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Wholesale revenues from non-affiliates for the second quarter 2013 were $216.6 million compared to $177.9 million for the corresponding period in 2012. The increase was due to a $24.1 million increase in capacity revenues, primarily due to an increase in the total MWs of capacity under contract with non-affiliates primarily due to the commencement of a new PPA at Plant Nacogdoches placed in service late June 2012, and a $14.6 million increase in energy sales, reflecting a 50.9% increase in the average price of energy primarily as a result of higher natural gas prices.

Wholesale revenues from non-affiliates for year-to-date 2013 were $440.1 million compared to $318.4 million for the corresponding period in 2012. The increase was due to a $76.0 million increase in energy sales, reflecting a 42.2% increase in the average price of energy, primarily as a result of higher natural gas prices, and a 5.1% increase in KWH sales, and a $45.7 million increase in capacity revenues primarily due to an increase in the total MWs of capacity under contract with non-affiliates primarily due to the commencement of a new PPA at Plant Nacogdoches placed in service late June 2012.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information.

Wholesale Revenues – Affiliates

Wholesale revenues from sales to affiliated 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 2013 were $88.6 million compared to $106.0 million for the corresponding period in 2012. The decrease was the result of a $14.1 million decrease in energy sales under the IIC and a $3.3 million decrease in energy sales under existing contracts, reflecting a 46.2% decrease in KWH sales primarily due to lower demand and higher gas prices, partially offset by a 42.7% increase in the average price of energy primarily as a result of higher natural gas prices.

Wholesale revenues from affiliates for year-to-date 2013 were $166.8 million compared to $217.7 million for the corresponding period in 2012. The decrease was the result of a $45.7 million decrease in energy sales under the IIC and a $5.2 million decrease in energy sales under existing contracts, reflecting a 46.6% decrease in KWH sales primarily due to lower demand and higher gas prices, partially offset by a 25.8% increase in the average price of energy primarily as a result of higher natural gas prices.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information.

Fuel and Purchased Power Expenses



	Second Quarter 2013 vs. Second Quarter 2012					Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	19.1		20.8		$	49.4		27.3
Purchased power – non-affiliates	(0.2		)	(0.9	)	(6.3		)	(14.6	)
Purchased power – affiliates	3.3			115.6		8.9			169.3
Total fuel and purchased power expenses	$	22.2				$	52.0

Southern Power PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is generally accompanied by an increase or decrease in related

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fuel revenues 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, affiliate-owned generation, or external purchases.

In the second quarter 2013, total fuel and purchased power expenses were $139.2 million compared to $117.0 million for the corresponding period in 2012. Fuel and purchased power expenses increased $55.2 million due to a 73.0% increase in the average cost of natural gas and a 42.8% increase in the average cost of purchased power. The increase was partially offset by a $33.0 million decrease associated with a 28.8% net decrease in the volume of KWHs generated and purchased primarily due to lower demand and the availability of lower cost affiliate power.

For year-to-date 2013, total fuel and purchased power expenses were $281.0 million compared to $229.0 million for the corresponding period in 2012. Fuel and purchased power expenses increased $89.2 million due to a 50.3% increase in the average cost of natural gas and a 30.3% increase in the average cost of purchased power. The increase was partially offset by a $37.2 million decrease associated with a 16.0% net decrease in the volume of KWHs generated and purchased primarily due to lower demand and the availability of lower cost affiliate power.

In the second quarter 2013, fuel expense was $110.6 million compared to $91.5 million for the corresponding period in 2012. The increase was due to a $46.7 million increase associated with the average cost of natural gas per KWH generated, partially offset by a $27.6 million decrease associated with the volume of KWHs generated.

For year-to-date 2013, fuel expense was $230.0 million compared to $180.6 million for the corresponding period in 2012. The increase was due to a $77.3 million increase associated with the average cost of natural gas per KWH generated, partially offset by a $27.9 million decrease associated with the volume of KWHs generated.

In the second quarter 2013, purchased power expense was $28.5 million compared to $25.4 million for the corresponding period in 2012. The increase was due to an $8.5 million increase associated with the cost of purchased power, partially offset by a $5.4 million decrease associated with the volume of KWHs purchased.

For year-to-date 2013, purchased power expense was $51.0 million compared to $48.4 million for the corresponding period in 2012. The increase was due to an $11.9 million increase associated with the cost of purchased power, partially offset by a $9.3 million decrease associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

In the second quarter 2013, other operations and maintenance expenses were $62.7 million compared to $40.2 million for the corresponding period in 2012. For year-to-date 2013, other operations and maintenance expenses were $113.6 million compared to $88.6 million for the corresponding period in 2012. The increases were primarily due to scheduled outage costs. Also contributing to the increases were operating costs associated with Plant Nacogdoches placed in service in June 2012, Plant Apex placed in service in July 2012, Plant Granville placed in service in October 2012, and Plant Cleveland placed in service in December 2012.

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Depreciation and Amortization

In the second quarter 2013, depreciation and amortization was $44.9 million compared to $34.0 million for the corresponding period in 2012. For year-to-date 2013, depreciation and amortization was $85.1 million compared to $65.9 million for the corresponding period in 2012. The increases were primarily due to an increase in plant in service, including the additions of Plants Nacogdoches, Apex, Granville, and Cleveland in 2012.

Taxes Other than Income Taxes

In the second quarter 2013, taxes other than income taxes were $5.5 million compared to $4.6 million for the corresponding period in 2012. For year-to-date 2013, taxes other than income taxes were $10.8 million compared to $9.5 million for the corresponding period in 2012. The increases were primarily due to an increase in property tax expense resulting from an increase in plant in service, including the additions of Plants Nacogdoches, Apex, and Cleveland in 2012.

Interest Expense, Net of Amounts Capitalized

In the second quarter 2013, interest expense, net of amounts capitalized was $20.6 million compared to $13.9 million for the corresponding period in 2012. For year-to-date 2013, interest expense, net of amounts capitalized was $41.0 million compared to $27.6 million for the corresponding period in 2012. The increases were primarily due to a decrease in capitalized interest resulting from the completion of Plants Nacogdoches and Cleveland in June 2012 and December 2012, respectively.

Income Taxes

In the second quarter 2013, income taxes were $4.8 million compared to $29.3 million for the corresponding period in 2012. The decrease was primarily due to a $16.3 million decrease associated with lower pre-tax earnings and an $8.3 million decrease related to an increase in the amount of tax benefit recognized from investment tax credits (ITCs) compared to the corresponding period in 2012.

For year-to-date 2013, income taxes were $19.7 million compared to $42.7 million for the corresponding period in 2012. The decrease was primarily due to a $15.8 million decrease associated with lower pre-tax earnings and a $9.3 million decrease related to an increase in the amount of tax benefit recognized from ITCs compared to the corresponding period in 2012.

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FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's target market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, 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, 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.

Climate Change Litigation

Kivalina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Kivalina Case" of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under "Environmental Matters – Climate Change Litigation – Kivalina Case" in Item 8 of the Form 10-K for additional information. On May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

Hurricane Katrina Case

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under "Environmental Matters – Climate Change Litigation – Hurricane Katrina Case" in Item 8 of the Form 10-K for additional information. On May 14, 2013, the U.S. Court of Appeals for the Fifth Circuit upheld the U.S. District Court for the Southern District of Mississippi's dismissal of the case. The decision is subject to appeal; therefore, the ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule.

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Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed revision of the current steam electric effluent guidelines and rule for cooling water intake structures.

On June 7, 2013, the EPA published a proposed rule which requests comments on a range of potential regulatory options for addressing certain wastestreams from steam electric power plants. These regulations could result in the installation of additional controls at certain of Southern Power's facilities, which could result in capital expenditures and compliance costs. The ultimate impact of these proposed regulations will, however, depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information regarding the proposed regulation of greenhouse gas emissions through establishment of new source performance standards.

Although the outcome of federal, state, and international initiatives cannot be determined at this time, additional restrictions on Southern Power's greenhouse gas emissions at the federal or state level could result in additional compliance costs, including capital expenditures. Additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through PPAs. Further, higher costs that are recovered through regulated rates at other utilities could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

Income Tax Matters

Investment Tax Credits

In 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA included renewable energy incentives. Southern Power has recognized ITCs under the renewable energy incentives related to Plants Nacogdoches, Cimarron, Apex, Granville, Spectrum, and Campo Verde, which have had a material impact on cash flows and net income. On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several renewable energy incentives through 2013, including extending ITCs for biomass projects which begin construction before January 1, 2014.

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Acquisitions

Campo Verde Solar, LLC

On April 23, 2013, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Campo Verde from First Solar, Inc., the developer of the project. Campo Verde is constructing an approximately 139-MW solar photovoltaic facility in Southern California. The solar facility is expected to begin commercial operation in the fourth quarter 2013. Construction costs incurred through June 30, 2013 were $323.6 million. The total estimated cost of the project is expected to be between $490 million and $500 million. See Note (I) to the Condensed Financial Statements herein for additional information.

Construction Projects

Spectrum Nevada Solar, LLC

In September 2012, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Spectrum Nevada Solar, LLC (Spectrum) from Sun Edison, LLC, the original developer of the project. Spectrum is constructing an approximately 30-MW solar photovoltaic facility in North Las Vegas, Nevada. The solar facility is expected to begin commercial operation in the third quarter 2013. Construction costs incurred through June 30, 2013 were $63.0 million. The total estimated cost of the project is expected to be between $114 million and $131.5 million.

Power Sales Agreements

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.

On April 23, 2013, a subsidiary of Southern Power assumed a PPA with San Diego Gas & Electric Company in connection with the acquisition of Campo Verde. The solar facility is expected to begin commercial operation in the fourth quarter 2013. See Note (I) to the Condensed Financial Statements herein for additional information.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Southern Power 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 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.

See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies and other matters being litigated which may affect future earnings potential.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Contingent Obligations, Depreciation, and Investment Tax Credits.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at June 30, 2013. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements 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 $135.8 million for the first six months of 2013, an increase of $7.1 million as compared to the first six months of 2012. The increase in cash provided from operating activities was primarily due to an increase in cash received for ITCs, partially offset by an increase in operating costs. Net cash used for investing activities totaled $299.8 million for the first six months of 2013 primarily due to expenditures related to the acquisition and construction of Plants Campo Verde and Spectrum. Net cash provided from financing activities totaled $150.2 million for the first six months of 2013 primarily due to an increase in notes payable. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.

Significant asset changes in the balance sheet for the first six months of 2013 include a $374.8 million increase in construction work in progress primarily due to the acquisition and construction of Plants Campo Verde and Spectrum.

Significant liability and stockholder's equity changes in the balance sheet for the first six months of 2013 include a $195.1 million increase in notes payable to non-affiliates due to the timing of cash transactions and a $100.5 million increase in accounts payable primarily related to construction of Plant Campo Verde.

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. There are no requirements through June 30, 2014 to fund maturities of long-term debt.

The construction 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 due to market opportunities and Southern Power's ability to execute its growth strategy. Actual construction 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.

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Sources of Capital

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

Southern Power's current liabilities frequently 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.

To meet liquidity and capital resource requirements, Southern Power had at June 30, 2013 cash and cash equivalents of approximately $14.9 million and a committed credit facility of $500 million (Facility). In February 2013, Southern Power amended the Facility, which extended the maturity date from 2016 to 2018. 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 is currently in compliance with all such covenants. Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes.

Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 2013				Short-term Debt During the Period ^(a)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	266	0.4	%	$	210	0.4	%	$	266


(a)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2013.

Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, and cash.

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.

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The maximum potential collateral requirements under these contracts at June 30, 2013 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	459
Below BBB- and/or Baa3	1,312

Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant 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, through the acquisition of Plant Rowan, Southern Power assumed a PPA with North Carolina Municipal Power Agency No. 1 that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power'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.

Market Price Risk

Southern Power is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power's policies in areas such as counterparty exposure and risk management practices. Southern Power'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 tests, and sensitivity analysis.

Southern Power's market risk exposure relative to interest rate changes for the second quarter 2013 has not changed materially compared with the December 31, 2012 reporting period. Since a significant portion of outstanding indebtedness bears interest at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Because energy from Southern Power's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

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The changes in fair value of energy-related derivative contracts for the three and six months ended June 30, 2013 were as follows:



	Second Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	3.6		$	0.8
Contracts realized or settled	(1.3		)	(1.1		)
Current period changes^(a)	(1.4		)	1.2
Contracts outstanding at the end of the period, assets (liabilities), net	$	0.9		$	0.9

(a) Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The change in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2013 was a decrease of $2.7 million and an increase of $0.1 million, respectively, which is due to both power and natural gas positions. The changes are attributable to both the volume and prices of power and natural gas as follows:



	June 30, 2013		March 31, 2013			December 31, 2012
Power – net purchased or (sold)
MWHs (in thousands)	—		(52.8		)	—
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	—	$	3.58		$	—
Natural gas net purchased
Commodity – million mmBtu	2.4		5.2			5.0
Commodity – weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	0.01	$	(0.57	)	$	(0.02	)

The net fair value of energy-related derivative contracts by hedge designation reflected in the financial statements as assets (liabilities) consists of the following:



Asset (Liability) Derivatives	June 30, 2013		December 31, 2012
	(in millions)
Cash flow hedges	$	—	$	—
Not designated	0.9		0.8
Total fair value	$	0.9	$	0.8

Gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are initially deferred in AOCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in Southern Power's statements of income as incurred.

For Southern Power's energy-related derivatives not designated as hedging instruments, a substantial portion of the pre-tax realized and unrealized gains and losses is associated with hedging fuel price risk of certain PPA customers and has no impact on net income or on fuel expense as presented in Southern Power's statements of income. As a result, for the three and six months ended June 30, 2013 and 2012, the pre-tax effects of energy-related derivatives not designated as hedging instruments on Southern Power's statements of income were not material.

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at June 30, 2013 were as follows:



			June 30, 2013 Fair Value Measurements
	Total		Maturity
	Fair Value		Year 1			Years 2&3		Years 4&5
	(in millions)
Level 1	$	—	$	—		$	—	$	—
Level 2	0.9		(0.4		)	0.3		1.0
Level 3	—		—			—		—
Fair value of contracts outstanding at end of period	$	0.9	$	(0.4	)	$	0.3	$	1.0

For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Power in Item 7 and Note 1 under "Financial Instruments" and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

During the six months ended June 30, 2013, Southern Power prepaid $0.4 million of long-term debt to TRE.

In March 2013, Southern Power issued an additional $1.7 million under a promissory note, due September 30, 2032, to TRE related to the financing of Spectrum.

In the second quarter 2013, Southern Power issued an aggregate $8.7 million under a promissory note, due April 30, 2033, to TRE related to the financing of Campo Verde.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern 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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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

INDEX TO APPLICABLE NOTES TO

FINANCIAL STATEMENTS BY REGISTRANT



Registrant	Applicable Notes

Southern Company	A, B, C, D, E, F, G, H, I, J, K

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, 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:


(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, 2012 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, 2013 and 2012. 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 (with respect to Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power) and the Form 10-K/A (with respect to Mississippi Power) and details which have not changed significantly in amount or composition since the filings of the Form 10-K or the Form 10-K/A, as applicable, 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 (with respect to Southern Company, Alabama Power, Georgia Power, Gulf Power, and Southern Power) and the Form 10-K/A (with respect to Mississippi Power). 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.


(B)	CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants (other than Mississippi Power) in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A for information relating to various lawsuits, other contingencies, and regulatory matters.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide (CO₂) and other emissions, coal combustion byproducts, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent. 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 (other than Mississippi Power) in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A, 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.

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Environmental Matters

New Source Review Actions

In 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. The EPA alleged NSR violations at five coal-fired generating facilities operated by Alabama Power, including a unit co-owned by Mississippi Power, and three coal-fired generating facilities operated by Georgia Power, including a unit co-owned by Gulf Power. The civil action sought penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The case against Georgia Power (including claims related to the unit co-owned by Gulf Power) was administratively closed in 2001 and has not been reopened. After Alabama Power was dismissed from the original action, the EPA filed a separate action in 2001 against Alabama Power (including claims related to the unit co-owned by Mississippi Power) in the U.S. District Court for the Northern District of Alabama.

In 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree, resolving claims relating to the alleged NSR violations at Plant Miller. In 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims, including one relating to the unit co-owned by Mississippi Power. In 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power summary judgment on all remaining claims and dismissed the case with prejudice. That judgment is on appeal to the U.S. Court of Appeals for the Eleventh Circuit. In February 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power.

Southern Company and each traditional operating company believe each such traditional operating company complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.

Climate Change Litigation

Kivalina Case

In 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs alleged that the village was being destroyed by erosion allegedly caused by global warming that the plaintiffs attributed to emissions of greenhouse gases by the defendants. The plaintiffs asserted claims for public and private nuisance and contended that some of the defendants (including Southern Company) acted in concert and were therefore jointly and severally liable for the plaintiffs' damages. The suit sought damages for lost property values and for the cost of relocating the village, which was alleged to be $95 million to $400 million. In 2009, the U.S. District Court for the Northern District of California granted the defendants' motions to dismiss the case. In September 2012, the U.S. Court of Appeals for the Ninth Circuit upheld the U.S. District Court for the Northern District of California's dismissal of the case. In November 2012, the U.S. Court of Appeals for the Ninth Circuit denied the plaintiffs' request for review of the decision. On February 25, 2013, the plaintiffs filed a petition for writ of certiorari with the U.S. Supreme Court. On May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

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Hurricane Katrina Case

In 2005, immediately following Hurricane Katrina, a lawsuit was filed in the U.S. District Court for the Southern District of Mississippi by Ned Comer on behalf of Mississippi residents seeking recovery for property damage and personal injuries caused by Hurricane Katrina. In 2006, the plaintiffs amended the complaint to include Southern Company and many other electric utilities, oil companies, chemical companies, and coal producers. The plaintiffs allege that the defendants contributed to climate change, which contributed to the intensity of Hurricane Katrina. In 2007, the U.S. District Court for the Southern District of Mississippi dismissed the case. On appeal to the U.S. Court of Appeals for the Fifth Circuit, a three-judge panel reversed the U.S. District Court for the Southern District of Mississippi, holding that the case could proceed, but, on rehearing, the full U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs' appeal, resulting in reinstatement of the decision of the U.S. District Court for the Southern District of Mississippi in favor of the defendants. In 2011, the plaintiffs filed an amended version of their class action complaint, arguing that the earlier dismissal was on procedural grounds and under Mississippi law the plaintiffs have a right to re-file. The amended complaint was also filed against numerous chemical, coal, oil, and utility companies, including Alabama Power, Georgia Power, Gulf Power, and Southern Power. On May 14, 2013, the U.S. Court of Appeals for the Fifth Circuit upheld the U.S. District Court for the Southern District of Mississippi's March 2012 dismissal of the case. The decision is subject to appeal. Each Southern Company entity named in the lawsuit believes that these claims are without merit. While each Southern Company entity named in the lawsuit believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether any Southern Company entity named in the lawsuit will incur any liability in connection with this matter. The ultimate outcome of this matter 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, 2013 was $18 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). 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 on the Georgia Hazardous Sites Inventory and the CERCLA NPL 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. 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 action and a 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. On February 1, 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion ruling that Georgia Power has no liability in the private action. On May 10, 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.

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The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the regulatory treatment, they 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" 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 $51 million as of June 30, 2013. 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, there was no impact on net income as a result of these estimates.

In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power's transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. The feasibility study/presumptive remedy document was originally filed with TCEQ in 2011 and remains under consideration by the agency. Amounts expensed and accrued related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of PRPs. The remediation expenses incurred by Mississippi Power are 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. The DOE failed to timely perform and has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel beginning no later than January 31, 1998. Consequently, Alabama Power and Georgia Power have pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

As a result of the first lawsuit, Georgia Power recovered approximately $27 million, based on its ownership interests, and Alabama Power recovered approximately $17 million, representing substantially all of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In April 2012, Alabama Power credited the award to cost of service for the benefit of customers. In July 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers.

In 2008, Alabama Power and Georgia Power filed a second lawsuit 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. Damages are being sought for the period from January 1, 2005 through December 31, 2010. 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, 2013 for any potential recoveries from the second lawsuit. 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.

Sufficient pool storage capacity for spent fuel is available at Plant Vogtle Units 1 and 2 to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle Units 1 and 2 has begun. The facility is expected to begin operation in sufficient time to maintain full-core discharge

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capability, with additional on-site dry storage to be added as needed. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K/A for additional information regarding Mississippi Power's settlement agreement with its wholesale customers for revised rates related to the wholesale Municipal and Rural Associations (MRA) cost-based electric tariff. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A, and "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.

In March 2012, Mississippi Power entered into a settlement agreement with its wholesale customers to increase wholesale base revenues under the MRA cost-based electric tariff by approximately $22.6 million annually, and the FERC approved interim rates effective May 1, 2012. In September 2012, Mississippi Power, with its wholesale customers, filed a final settlement agreement with the FERC. On May 3, 2013, Mississippi Power received an order from the FERC accepting the settlement agreement.

Retail Regulatory Matters

Alabama Power

Rate CNP

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Rate CNP" and "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP PPA) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power's under recovered Rate CNP PPA balance at June 30, 2013 and at December 31, 2012 was $9 million. This under recovered balance at June 30, 2013 is included in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. For Rate CNP PPA, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs. Alabama Power's under recovered Rate CNP Environmental balance at June 30, 2013 and December 31, 2012 was $21 million. This under recovered balance at June 30, 2013 consists of $8 million in under recovered regulatory clause revenues and $13 million in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.

Retail Energy Cost Recovery

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Energy Cost Recovery" and "Retail Regulatory Matters – Energy Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's energy cost recovery. Alabama Power's over recovered fuel costs at June 30, 2013 totaled $13 million as compared to an under recovered balance of $4 million at December 31, 2012. The over recovered fuel costs at June 30, 2013 are included in other regulatory

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liabilities, current and the under recovered fuel costs at December 31, 2012 are included in deferred under recovered regulatory clause revenues on Southern Company's and Alabama Power's Condensed Balance Sheets herein. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs.

Natural Disaster Cost Recovery

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve" and "Retail Regulatory Matters – Natural Disaster Reserve," respectively, in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2013, the NDR had an accumulated balance of $95 million as compared to $103 million at December 31, 2012, which is included on Southern Company's and Alabama Power's Condensed Balance Sheets herein under other regulatory liabilities, deferred. The decrease in the NDR is a result of storm activity. The related accruals are reflected as operations and maintenance expenses on Southern Company's and Alabama Power's Condensed Statements of Income herein.

Georgia Power

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, 2013 and December 31, 2012, Georgia Power's fuel cost over recovery balance totaled $108 million included in current liabilities and $230 million included in current liabilities and other deferred credits and liabilities, respectively, on Southern Company's and Georgia Power's Condensed Balance Sheets herein.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any 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.

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters –Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for information regarding Georgia Power's current retail rate plan.

The primary points of the 2013 Rate Case are:


•	Continuation of the traditional base rate tariffs through December 31, 2016 based on a test year ending July 31, 2014 with a modification for an appropriate three-year levelization adjustment.


•	Continuation of the ECCR tariff through December 31, 2016 with a modification for an appropriate three-year levelization adjustment.


•	Continuation of an allowed retail ROE range of 10.25% to 12.25%.

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•	Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range will be shared with Georgia Power's customers and the remaining one-third will be retained by Georgia Power.


•	Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

The Georgia PSC is scheduled to issue a final order in this matter during December 2013. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plans

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

On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (32 MWs), which was retired on April 25, 2013.

The decertification of these units, fuel conversions, and procurement of additional solar generation are not expected to have a material impact on Southern Company's or Georgia Power's financial statements; however, the ultimate outcome depends on the Georgia PSC's order in the 2013 Rate Case and future fuel cases and cannot be determined at this time.

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Georgia Power executed two PPAs to purchase 50 MWs and 56 MWs, respectively, of biomass capacity and energy from two facilities that will commence in 2015 and end in 2035. On May 21, 2013, the Georgia PSC approved the biomass capacity and energy PPAs. These four PPAs result in additional contractual obligations of approximately $13 million in 2015, $47 million in 2016, $49 million in 2017, and $1.29 billion thereafter.

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, the eighth Vogtle Construction Monitoring (VCM) report, and pending litigation.

In 2008, Georgia Power, acting for itself and as agent for the 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 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. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. The Vogtle 3 and 4 Agreement provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.

Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain 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 Owners, 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, effective December 30, 2011, and issued combined construction and operating licenses (COLs) in February 2012. Receipt of the COLs allowed full construction to begin.

In February 2012, separate groups of petitioners filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC's issuance of the COLs and certification of the DCD. These petitions were consolidated in April 2012. Also in February 2012, one of the groups of petitioners filed a motion with the NRC to stay the effectiveness of the COLs pending the outcome of the petitions pending before the U.S. District Court for the District of Columbia Circuit. The NRC denied this motion in April 2012. On May 14, 2013, the U.S. Court of Appeals for the District of Columbia Circuit ruled in favor of the NRC, upholding the COLs and

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allowing for the continuation of the construction. On July 23, 2013, the U.S. Court of Appeals for the District of Columbia Circuit rejected the petitioners' request for rehearing.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. On February 19, 2013, the Georgia PSC voted to approve Georgia Power's seventh VCM report, including construction capital costs incurred through June 30, 2012 of approximately $2.0 billion. Georgia Power's eighth VCM report requests approval for an additional $0.2 billion of construction capital costs incurred through December 31, 2012. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, the eighth VCM report also requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. Associated financing costs during the construction period are estimated to total approximately $2.0 billion. The Georgia PSC is scheduled to vote on the eighth VCM report in October 2013.

In July 2012, the 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 Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The Contractor has claimed that its estimated adjustment attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars) with respect to these issues. The Contractor also has asserted it is entitled to further schedule extensions. Georgia Power has not agreed with either the proposed cost or schedule adjustments or that the Owners have any responsibility for costs related to these issues. In November 2012, Georgia Power and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Owners are not responsible for these costs. Also in November 2012, the Contractor filed suit against Georgia Power and the other Owners in the U.S. District Court for the District of Columbia alleging the Owners are responsible for these costs. While litigation has commenced and Georgia Power intends to vigorously defend its positions, Georgia Power expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

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As construction continues, additional delays in the fabrication and assembly of structural modules, the failure of such modules to meet applicable standards, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues may further impact project schedule and cost. Additional claims by the Contractor or Georgia Power (on behalf of the 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.

Gulf Power has calculated its revenue deficiency based on the projected period January 1, 2014 through December 31, 2014 which serves as the test year. The test year provides the appropriate period of utility operations to be analyzed by the Florida PSC to be able to set reasonable rates for the period the new rates will be in effect. The period January 1, 2014 through December 31, 2014 best represents expected future operations of Gulf Power as the regional economy continues to emerge from the recession. The petition also requests that the Florida PSC approve the projected January 1, 2014 through December 31, 2014 test year and consent to new rate schedules going into operation as soon as possible.

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

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.

Fuel Cost Recovery

See Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Cost Recovery Clauses – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

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Purchased Power Capacity Recovery

See Notes 1 and 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Cost Recovery Clauses – Purchased Power Capacity Recovery," respectively, in Item 8 of the Form 10-K for additional information.

Environmental Cost Recovery

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.

Energy Conservation Cost Recovery

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Energy Conservation Cost Recovery" in Item 8 of the Form 10-K for additional information.

Mississippi Power

Energy Efficiency

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/A for additional information regarding Mississippi Power's base rates.

On January 18, 2013, Mississippi Power filed its annual PEP filing for 2013, which indicated a rate increase of 1.990%, or $15.8 million, annually. On March 4, 2013, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) filed a joint stipulation which revised the annual PEP filing for 2013 to reflect the removal of certain costs related to unresolved matters that are currently under review. On March 5, 2013, the revised annual PEP filing for 2013 was approved by the Mississippi PSC, which resulted in a rate increase of 1.925%, or $15.3 million, annually, with the new rates effective March 19, 2013. Mississippi Power may be entitled to $3.3 million in additional revenues in 2013 as a result of the late implementation of the 2013 PEP rate increase.

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

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System Restoration Rider

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – System Restoration Rider" in Item 8 of the Form 10-K/A for additional information.

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K/A for information on Mississippi Power's annual environmental filing with the Mississippi PSC.

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/A for information regarding Mississippi Power's fuel cost recovery.

Ad Valorem Tax Adjustment

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Storm Damage Cost Recovery

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Storm Damage Cost Recovery" in Item 8 in the Form 10-K/A for information regarding Mississippi Power's storm damage cost recovery. Mississippi Power maintains a reserve to cover the cost of damage from major storms to its transmission and distribution facilities and generally the cost of uninsured damage to its generation facilities and other property. At June 30, 2013, the balance in the storm reserve was $58.5 million.

Integrated Coal Gasification Combined Cycle

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 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K/A for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Project Approval

The Kemper IGCC is currently under construction and will utilize an integrated coal gasification combined cycle 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 operations on June 5, 2013. In connection with the Kemper IGCC, Mississippi Power also is constructing and plans to operate approximately 61 miles of CO₂ pipeline infrastructure. The Kemper IGCC and the CO₂ pipeline are scheduled to be placed in service in May 2014. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO₂ Pipeline Facilities" in Item 8 of the Form 10-K and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Lignite Mine and CO₂ Pipeline Facilities" in Item 8 of the Form 10-K/A for additional information regarding the lignite mine and the CO₂ pipeline.

Kemper IGCC Cost Estimate

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC Order was $2.4 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants), 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 Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions as contemplated in the Settlement Agreement (described below) and the 2012 MPSC Order, which includes 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). Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

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On July 29, 2013, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately $3.87 billion, net of the DOE Grants and the Cost Cap Exceptions. Estimated amounts of the Cost Cap Exceptions include $245 million for the lignite mine and equipment, $115 million for the CO2 pipeline facilities, $324 million of AFUDC, and $101 million of other general exceptions. The revised cost estimate reflects additional cost pressures, including labor costs, piping and other material costs, engineering and support costs, start-up costs, and decreases in construction labor productivity. Mississippi Power does not intend to seek any joint owner contributions or rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, excluding the Cost Cap Exceptions and net of the DOE Grants. As a result of the revisions to the cost estimate, Mississippi Power recorded pre-tax charges to income for estimated probable losses of $78.0 million ($48.2 million after tax) in 2012, $462.0 million ($285.3 million after tax) in the first quarter 2013, and $450 million ($277.9 million after tax) in the second quarter 2013. Southern Company evaluated the portion of the estimated probable loss related to 2012 and concluded it was not material to Southern Company. Therefore, Southern Company recorded pre-tax charges to income for estimated probable losses of $540.0 million ($333.5 million after tax) in the first quarter 2013 and $450 million ($277.9 million after tax) in the second quarter 2013.

Southern Company's and Mississippi Power's analysis of the estimated cost and schedule to complete the Kemper IGCC will be ongoing throughout the construction period. Mississippi Power could experience further construction cost increases and/or schedule delays with respect to the Kemper IGCC as a result of factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, or contractor or supplier delay or non-performance under construction or other agreements. Furthermore, Mississippi Power could also experience schedule delays associated with start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations and/or unforeseen engineering problems, which would result in further cost increases or require repayment of a portion of investment tax credits received. 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 will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.

As of June 30, 2013, Mississippi Power had spent a total of $3.29 billion on the Kemper IGCC. These costs include $2.74 billion for the portion of the Kemper IGCC subject to the construction cost cap, $210.2 million for the lignite mine and equipment, $86.1 million for the CO₂ pipeline facilities, $193.8 million of AFUDC, and $55.2 million of other costs, including certain general exceptions and certain regulatory assets. Of this total, $2.24 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $990 million), $49.7 million in other regulatory assets, $3.9 million in other deferred charges and assets on Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and $1.0 million was previously expensed. Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period. This includes deferred costs associated with the generation resource planning, evaluation, and screening activities. The amortization period for the regulatory asset will be determined by the Mississippi PSC at a later date. 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.

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

Rate Recovery of Kemper IGCC Costs

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related to the Kemper IGCC. Under the 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 as well as any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. Mississippi Power intends to finance (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 the Cost Cap Exceptions, (2) the accrued AFUDC, and (3) exceptions not provided for in the Seven-Year Rate Plan (discussed below) through securitization as provided in State of Mississippi legislation. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective after the Kemper IGCC is placed in service and following completion of the Mississippi PSC's final prudence review of costs for the Kemper IGCC.

On March 5, 2013, the Mississippi PSC issued an order (2013 Kemper IGCC Order) approving a 15% increase in retail rates effective on March 19, 2013, and an additional 3% increase in retail rates effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. All amounts collected through April 2014, which are expected to total $126 million, will be recorded as a regulatory liability to be used to mitigate rate impacts beginning in May 2014 when the Kemper IGCC is expected to be placed in service. As of June 30, 2013, $27.0 million had been collected and recorded as a regulatory liability with $3.0 million included in other regulatory liabilities, current and $24.0 million included in other regulatory liabilities, deferred in Southern Company's and Mississippi Power's Condensed Balance Sheets herein. On March 21, 2013, a legal challenge to the 2013 Kemper IGCC Order was filed with the Mississippi Supreme Court.

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pursuant to the Settlement Agreement contemplate the continued accrual of AFUDC through the May 2014 expected in-service date.

Proposed Sale of Undivided Interest to SMEPA

The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In September 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.

In March 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposit has been presented as a current liability in Southern Company's and Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Southern

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Company's and Mississippi Power's Condensed Statements of Cash Flows herein. On July 18, 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposit.

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

Baseload Act

Tax Incentives

A portion of the tax credits realized by Mississippi Power will be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above. In addition, all or a portion of the tax credits will be subject to recapture if Mississippi Power fails to satisfy the in-service date requirements and CO₂ capture requirements described above.

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

Other Matters

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switchyard. Plant Bowen Unit 1 (approximately 700 MWs) was returned to service on August 3, 2013. Plant Bowen Unit 2 (approximately 700 MWs) remains offline, pending completion of repairs. Georgia Power expects that any material repair costs related to the damage will be covered by property insurance. The ultimate outcome of this matter cannot be determined at this time.

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(C)	FAIR VALUE MEASUREMENTS

As of June 30, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:



	Fair Value Measurements Using
As of June 30, 2013:	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	$	—	$	16	$	—	$	16
Interest rate derivatives	—		6		—		6
Nuclear decommissioning trusts^(a)	525		828		—		1,353
Cash equivalents	159		—		—		159
Other investments	9		—		15		24
Total	$	693	$	850	$	15	$	1,558
Liabilities:
Energy-related derivatives	$	—	$	89	$	—	$	89

Alabama Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	4
Nuclear decommissioning trusts:^(b)
Domestic equity	328		70		—		398
Foreign equity	29		56		—		85
U.S. Treasury and government agency securities	—		28		—		28
Corporate bonds	—		102		—		102
Mortgage and asset backed securities	—		22		—		22
Other	—		9		—		9
Total	$	357	$	291	$	—	$	648
Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15

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	Fair Value Measurements Using
As of June 30, 2013:	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	$	—	$	4	$	—	$	4
Nuclear decommissioning trusts:^{(b) (c)}
Domestic equity	168		1		—		169
Foreign equity	—		115		—		115
U.S. Treasury and government agency securities	—		97		—		97
Municipal bonds	—		57		—		57
Corporate bonds	—		130		—		130
Mortgage and asset backed securities	—		120		—		120
Other	—		21		—		21
Total	$	168	$	545	$	—	$	713
Liabilities:
Energy-related derivatives	$	—	$	33	$	—	$	33

Gulf Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	4
Cash equivalents	16		—		—		16
Total	$	16	$	4	$	—	$	20
Liabilities:
Energy-related derivatives	$	—	$	25	$	—	$	25

Mississippi Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents	99		—		—		99
Total	$	99	$	2	$	—	$	101
Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15

Southern Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Liabilities:
Energy-related derivatives	$	—	$	1	$	—	$	1


(a)	For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.


(b)	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.


(c)	Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of June 30, 2013, approximately $38 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

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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 LIBOR interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.

"Other investments" include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.

For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics.

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, 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.

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As of June 30, 2013, 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, 2013:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	115	None	Monthly	5 days
Corporate bonds - commingled funds	6		None	Daily	1 to 3 days
Equity - commingled funds	56		None	Daily/Monthly	Daily/7 days
Other - commingled funds	21		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	—		None	Daily	15 days
Cash equivalents:
Money market funds	159		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	56		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	99		None	Daily	15 days
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	115		None	Monthly	5 days
Corporate bonds - commingled funds	6		None	Daily	Not applicable
Other - commingled funds	21		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	16		None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	99		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 and 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 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 commingled funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations with maturity shortening provisions. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The commingled funds included with corporate bonds represent the investment of cash collateral received under the

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Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Alabama Power's nuclear decommissioning trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.

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, 2013, the fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, decreased by $7 million and increased by $51 million, respectively, at Southern Company. For the three and six months ended June 30, 2013, Alabama Power recorded an increase in fair value of $5 million and $43 million, respectively, as an increase in regulatory liabilities. Georgia Power recorded a decrease in fair value of $12 million as an increase of its regulatory asset related to its asset retirement obligations for the three months ended June 30, 2013 and an increase of $8 million as a decrease of its regulatory asset related to its asset retirement obligations for the six months ended June 30, 2013.

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.

As of June 30, 2013, 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:
Southern Company	$	21,942	$	22,734
Alabama Power	$	6,179	$	6,573
Georgia Power	$	9,622	$	9,878
Gulf Power	$	1,335	$	1,391
Mississippi Power	$	2,209	$	2,201
Southern Power	$	1,316	$	1,377

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.

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(D)	STOCKHOLDERS' EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effects of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:



	Three Months Ended June 30, 2013	Three Months Ended June 30, 2012	Six Months Ended June 30, 2013	Six Months Ended June 30, 2012
	(in millions)
As reported shares	874	872	872	870
Effect of options and performance share award units	5	8	5	9
Diluted shares	879	880	877	879

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three and six months ended June 30, 2013 and 2012.

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		Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries		Total Stockholders' Equity
	(in thousands)						(in millions)
Balance at December 31, 2012	877,803	(10,035	)	$	18,297		$	707	$	19,004
Net income after dividends on preferred and preference stock	—	—		378			—		378
Other comprehensive income (loss)	—	—		9			—		9
Stock issued	6,144	—		244			49		293
Stock repurchased, at cost	—	—		(18		)	—		(18		)
Cash dividends on common stock	—	—		(870		)	—		(870		)
Other	—	(9	)	—			—		—
Balance at June 30, 2013	883,947	(10,044	)	$	18,040		$	756	$	18,796

Balance at December 31, 2011	865,664	(539	)	$	17,578		$	707	$	18,285
Net income after dividends on preferred and preference stock	—	—		991			—		991
Other comprehensive income (loss)	—	—		(1		)	—		(1		)
Stock issued	9,697	—		395			—		395
Cash dividends on common stock	—	—		(837		)	—		(837		)
Other	—	(26	)	(2		)	—		(2		)
Balance at June 30, 2012	875,361	(565	)	$	18,124		$	707	$	18,831

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In July 2012, Southern Company announced a program to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. As of December 31, 2012, Southern Company had repurchased a total of approximately 9 million shares at a total cost of $430 million. There were no repurchases under this program in the first six months of 2013 and no further repurchases under the program are anticipated.


(E)	FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' variable rate pollution control revenue bonds. See Note 6 to the financial statements of each registrant (other than Mississippi Power) under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note 6 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K/A for additional information.

The following table outlines the committed credit arrangements by company as of June 30, 2013:



	Expires^(a)												Executable Term Loans				Due Within One Year
Company	2013		2014		2016		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	77		225		—		1,000		1,302		1,301		53		—		53		99
Georgia Power	—		—		150		1,600		1,750		1,740		—		—		—		—
Gulf Power	20		90		165		—		275		275		45		—		45		65
Mississippi Power	40		95		165		—		300		300		25		40		65		70
Southern Power	—		—		—		500		500		486		—		—		—		—
Other	25		75		—		—		100		100		25		—		25		75
Total	$	162	$	485	$	480	$	4,100	$	5,227	$	5,202	$	148	$	40	$	188	$	309

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

As reflected in the table above, during the first six months of 2013, Southern Company and certain of its subsidiaries entered into, amended, or renewed certain of their credit arrangements. In February 2013, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended their multi-year credit arrangements, which extended the maturity dates from 2016 to 2018. In March 2013, Gulf Power and Mississippi Power each amended certain of their credit arrangements, which extended the maturity dates from 2014 to 2016 and, in the case of Mississippi Power, also revised the definition of debt to exclude securitized debt relating to the Kemper IGCC for purposes of calculating the debt covenant under these credit arrangements. See Note (B) under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

Subsequent to June 30, 2013, SEGCO amended a $25 million credit arrangement, which extended the maturity date from 2013 to 2015.

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

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(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, 2013. 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, and Gulf Power in Item 8 of the Form 10-K and Note 2 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A for additional information.

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Components of the net periodic benefit costs for the three and six months ended June 30, 2013 and 2012 were as follows:



Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2013
Service cost	$	58		$	14		$	18		$	2		$	2
Interest cost	97			23			35			5			4
Expected return on plan assets	(150		)	(39		)	(53		)	(7		)	(6		)
Amortization:
Prior service costs	6			1			2			1			—
Net (gain)/loss	50			13			18			2			3
Net cost	$	61		$	12		$	20		$	3		$	3
Six Months Ended June 30, 2013
Service cost	$	116		$	27		$	35		$	5		$	5
Interest cost	194			46			69			9			9
Expected return on plan assets	(301		)	(78		)	(106		)	(13		)	(13		)
Amortization:
Prior service costs	13			3			5			1			—
Net (gain)/loss	100			26			37			4			5
Net cost	$	122		$	24		$	40		$	6		$	6
Three Months Ended June 30, 2012
Service cost	$	49		$	11		$	15		$	3		$	3
Interest cost	99			24			36			4			4
Expected return on plan assets	(146		)	(41		)	(55		)	(7		)	(6		)
Amortization:
Prior service costs	8			1			3			1			1
Net (gain)/loss	23			6			8			1			—
Net cost	$	33		$	1		$	7		$	2		$	2
Six Months Ended June 30, 2012
Service cost	$	99		$	22		$	30		$	5		$	5
Interest cost	197			47			71			8			9
Expected return on plan assets	(291		)	(81		)	(110		)	(13		)	(12		)
Amortization:
Prior service costs	15			3			6			1			1
Net (gain)/loss	47			12			16			2			1
Net cost	$	67		$	3		$	13		$	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, 2013
Service cost	$	6		$	1		$	1		$	1		$	1
Interest cost	18			4			8			—			1
Expected return on plan assets	(14		)	(6		)	(6		)	—			(1		)
Amortization:
Transition obligation	1			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	3			1			2			—			—
Net cost	$	15		$	1		$	6		$	1		$	1
Six Months Ended June 30, 2013
Service cost	$	12		$	3		$	3		$	1		$	1
Interest cost	37			9			16			1			2
Expected return on plan assets	(28		)	(12		)	(12		)	—			(1		)
Amortization:
Transition obligation	2			—			2			—			—
Prior service costs	2			2			—			—			—
Net (gain)/loss	6			1			4			—			—
Net cost	$	31		$	3		$	13		$	2		$	2
Three Months Ended June 30, 2012
Service cost	$	6		$	2		$	2		$	1		$	1
Interest cost	21			6			10			1			1
Expected return on plan assets	(15		)	(6		)	(7		)	(1		)	(1		)
Amortization:
Transition obligation	3			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	1			—			1			—			—
Net cost	$	17		$	3		$	7		$	1		$	1
Six Months Ended June 30, 2012
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	42			11			19			2			2
Expected return on plan assets	(30		)	(12		)	(14		)	(1		)	(1		)
Amortization:
Transition obligation	5			1			3			—			—
Prior service costs	2			2			—			—			—
Net (gain)/loss	3			—			2			—			—
Net cost	$	33		$	5		$	13		$	2		$	2

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(G)	EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

Effective Tax Rate

See Note 5 to the financial statements of each registrant (other than Mississippi Power) in Item 8 of the Form 10-K and Note 5 to the financial statements of Mississippi Power in Item 8 of the Form 10-K/A for information on the effective income tax rate.

Southern Company

Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity.

Southern Company's effective tax rate was 31.4% for the six months ended June 30, 2013 compared to 34.1% for the corresponding period in 2012. The decrease was primarily due to an increase in non-taxable AFUDC equity combined with lower net income. The decrease was partially offset by the recognition in 2012 of previously unrecognized tax benefits related to state income tax credits and a settlement with the IRS related to the methodology used to calculate the production activities deduction as defined in Section 199 of the Internal Revenue Code.

Alabama Power

Alabama Power's effective tax rate was 39.2% for the six months ended June 30, 2013 compared to 38.9% for the corresponding period in 2012.

Georgia Power

Georgia Power's effective tax rate was 38.2% for the six months ended June 30, 2013 compared to 34.2% for the corresponding period in 2012. The increase was primarily due to an increase in non-deductible book depreciation, the recognition in 2012 of previously unrecognized tax benefits related to state income tax credits, a settlement with the IRS related to the production activities deduction, and a decrease in non-taxable AFUDC equity.

Gulf Power

Gulf Power's effective tax rate was 37.7% for the six months ended June 30, 2013 compared to 36.6% for the corresponding period in 2012. The increase was primarily due to the recognition in 2012 of previously unrecognized tax benefits related to state income tax credits and a settlement with the IRS related to the production activities deduction.

Mississippi Power

Mississippi Power's effective tax rate was (41.0)% for the six months ended June 30, 2013 compared to 25.2% for the corresponding period in 2012. The decrease was primarily due to a net loss for the current period and an increase in non-taxable AFUDC equity related to the construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was 25.1% for the six months ended June 30, 2013 compared to 35.9% for the corresponding period in 2012. The decrease was primarily due to an increase in investment tax credits, partially offset by an increase in state income taxes as a result of apportionment changes.

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Unrecognized Tax Benefits

Changes during 2013 for unrecognized tax benefits were as follows:



	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Unrecognized tax benefits as of December 31, 2012	$	70	$	31	$	23	$	5	$	6	$	3
Tax positions from current periods	6		1		3		—		—		1
Balance as of June 30, 2013	$	76	$	32	$	26	$	5	$	6	$	4

The tax positions from current periods relate primarily to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Property Related Expenditures" herein for additional information.

The impact on the effective tax rate, if recognized, was as follows:



	As of June 30, 2013			As of December 31, 2012
		Southern Company
	(in millions)
Tax positions impacting the effective tax rate		$	6	$	5
Tax positions not impacting the effective tax rate		70		65
Balance of unrecognized tax benefits		$	76	$	70

The tax positions impacting the effective tax rate primarily relate to state income tax credits. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Property Related Expenditures" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

All of the registrants classify interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits at June 30, 2013 and December 31, 2012 was not material.

None of the registrants accrued any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the registrants' unrecognized tax positions will significantly increase or decrease within 12 months. The resolution of the tax accounting method change for repairs-generation assets, as well as the conclusion or settlement of state audits, could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Tax Method of Accounting for Property Related Expenditures

Southern Company submitted a tax accounting method change related to the deductibility of repair costs associated with its subsidiaries' generation, transmission, and distribution systems effective for the 2009 consolidated federal income tax return in 2010. In August 2011, the IRS issued a revenue procedure, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. Consequently, Southern Company incorporated into its federal income tax returns changes that conform to the new regulations and reversed all unrecognized tax positions related to transmission and distribution property.

In December 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, on April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the

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deductibility of repair costs associated with generation assets. Southern Company is currently reviewing this new guidance and expects more detailed guidance concerning these regulations. Due to uncertainty regarding the ultimate resolution of the repair costs for generation assets, an unrecognized tax position was recorded for the tax accounting method change for repairs-generation assets. The ultimate outcome of these matters cannot be determined at this time; however, implementing these regulations is not expected to have a material impact on net income.


(H)	DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

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.

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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, 2013, 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 date for derivatives not designated as hedges, were as follows:



	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company	270	2017	2017
Alabama Power	68	2017	—
Georgia Power	78	2017	—
Gulf Power	79	2017	—
Mississippi Power	43	2017	—
Southern Power	2	—	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 9 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 1 million mmBtu for Mississippi Power, and 1 million mmBtu for Southern Power.

For cash flow hedges, the amounts expected to be reclassified from AOCI to revenue and fuel expense for the next 12-month period ending June 30, 2014 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.

At June 30, 2013, the following interest rate derivatives were outstanding:

Notional

Amount

Interest Rate

Received

Interest Rate

Paid

Hedge

Maturity Date

Fair Value
Gain (Loss)
June 30, 2013

(in millions)

Fair value hedges of existing debt

Southern Company

350

4.15

3-month
LIBOR +
1.96%

^(a)

May 2014


(a)	Weighted average

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The estimated pre-tax gains (losses) that will be reclassified from AOCI to interest expense for the next 12-month period ending June 30, 2014 are immaterial for all registrants.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge 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. Any ineffectiveness is typically recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At June 30, 2013, the fair value of the foreign currency derivatives outstanding was immaterial.

Derivative Financial Statement Presentation and Amounts

At June 30, 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:



Asset Derivatives at June 30, 2013
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	7	$	2	$	2	$	2	$	1
Other deferred charges and assets	7		2		2		2		1
Total derivatives designated as hedging instruments for regulatory purposes	$	14	$	4	$	4	$	4	$	2	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	6	$	—	$	—	$	—	$	—	$	—
Other deferred charges and assets	—		—		—		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	6	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities	$	—	$	—	$	—	$	—	$	—	$	—
Other deferred charges and assets	2		—		—		—		—		2
Total derivatives not designated as hedging instruments	$	2	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	22	$	4	$	4	$	4	$	2	$	2

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Liability Derivatives at June 30, 2013
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	54	$	10	$	21	$	14	$	9
Other deferred credits and liabilities	34		5		12		11		6
Total derivatives designated as hedging instruments for regulatory purposes	$	88	$	15	$	33	$	25	$	15	N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	89	$	15	$	33	$	25	$	15	$	1

At December 31, 2012, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:



Asset Derivatives at December 31, 2012
	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	$	10	$	2	$	6	$	1	$	1
Other deferred charges and assets	13		3		5		3		2
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	5	$	11	$	4	$	3	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	—	$	—	$	—	$	—
Other deferred charges and assets	3		—		—		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	10	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities	$	1	$	—	$	—	$	—	$	—	$	1
Other deferred charges and assets	2		—		—		—		—		2
Total derivatives not designated as hedging instruments	$	3	$	—	$	—	$	—	$	—	$	3
Total asset derivatives	$	36	$	5	$	11	$	4	$	3	$	3

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Liability Derivatives at December 31, 2012
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	74	$	14	$	30	$	17	$	13
Other deferred credits and liabilities	35		4		15		10		6
Total derivatives designated as hedging instruments for regulatory purposes	$	109	$	18	$	45	$	27	$	19	N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	1	$	—	$	—	$	—	$	—	$	1
Other deferred credits and liabilities	1		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	2	$	—	$	—	$	—	$	—	$	2
Total liability derivatives	$	111	$	18	$	45	$	27	$	19	$	2

All derivative instruments are measured at fair value. See Note (C) herein for additional information.

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 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 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.

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Derivative Contracts at June 30, 2013
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	16		$	4		$	4		$	4		$	2		$	2
Gross amounts not offset in the Balance Sheet ^(b)	(15		)	(4		)	(4		)	(4		)	(2		)	(1		)
Net energy-related derivative assets	$	1		$	—		$	—		$	—		$	—		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	89		$	15		$	33		$	25		$	15		$	1
Gross amounts not offset in the Balance Sheet ^(b)	(15		)	(4		)	(4		)	(4		)	(2		)	(1		)
Net energy-related derivative liabilities	$	74		$	11		$	29		$	21		$	13		$	—

(a) None of the registrants offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.



Derivative Contracts at December 31, 2012
	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)	$	26		$	5		$	11		$	4		$	3		$	3
Gross amounts not offset in the Balance Sheet ^(b)	(23		)	(4		)	(11		)	(4		)	(2		)	(1		)
Net energy-related derivative assets	$	3		$	1		$	—		$	—		$	1		$	2
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet ^(a)	$	111		$	18		$	45		$	27		$	19		$	2
Gross amounts not offset in the Balance Sheet ^(b)	(23		)	(4		)	(11		)	(4		)	(2		)	(1		)
Net energy-related derivative liabilities	$	88		$	14		$	34		$	23		$	17		$	1

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At June 30, 2013 and December 31, 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:



Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 2013
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(54	)	$	(10	)	$	(21	)	$	(14	)	$	(9	)
Other regulatory assets, deferred	(34		)	(5		)	(12		)	(11		)	(6		)
Other regulatory liabilities, current	7			2			2			2			1
Other regulatory liabilities, deferred ^(a)	7			2			2			2			1
Total energy-related derivative gains (losses)	$	(74	)	$	(11	)	$	(29	)	$	(21	)	$	(13	)


(a)	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, 2012
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	$	(74	)	$	(14	)	$	(30	)	$	(17	)	$	(13	)
Other regulatory assets, deferred	(35		)	(4		)	(15		)	(10		)	(6		)
Other regulatory liabilities, current	10			2			6			1			1
Other regulatory liabilities, deferred ^(a)	13			3			5			3			2
Total energy-related derivative gains (losses)	$	(86	)	$	(13	)	$	(34	)	$	(23	)	$	(16	)


(a)	Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

For the three and six months ended June 30, 2013 and 2012, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Company's statements of income were immaterial.

For the three and six months ended June 30, 2013 and 2012, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company's and Mississippi Power's statements of income were immaterial and were offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there was no impact on Southern Company's or Mississippi Power's statements of income.

For the three months ended June 30, 2013 and 2012, 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 AOCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships						Statements of Income Location	Amount
	2013		2012				2013			2012
	(in millions)						(in millions)
Southern Company
Interest rate derivatives	$	—	$	(18	)	Interest expense, net of amounts capitalized	$	(5	)	$	(4	)
Alabama Power
Interest rate derivatives	$	—	$	(18	)	Interest expense, net of amounts capitalized	$	(1	)	$	—
Southern Power
Interest rate derivatives	$	—	$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(3	)

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the six months ended June 30, 2013 and 2012, 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 AOCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships						Statements of Income Location	Amount
	2013		2012				2013			2012
	(in millions)						(in millions)
Southern Company
Interest rate derivatives	$	—	$	(12	)	Interest expense, net of amounts capitalized	$	(10	)	$	(7	)
Alabama Power
Interest rate derivatives	$	—	$	(11	)	Interest expense, net of amounts capitalized	$	(1	)	$	—
Southern Power
Interest rate derivatives	$	—	$	—		Interest expense, net of amounts capitalized	$	(6	)	$	(5	)

For the three and six months ended June 30, 2013 and 2012, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were immaterial for Georgia Power, Gulf Power, and Mississippi Power.

For the three and six months ended June 30, 2013 and 2012, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments on the statements of income were immaterial for all registrants.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For Southern Power's energy-related derivatives not designated as hedging instruments, a substantial portion of the pre-tax realized and unrealized gains and losses is associated with hedging fuel price risk of certain PPA customers and has no impact on net income or on fuel expense as presented in Southern Company's and Southern Power's statements of income. As a result, for the three and six months ended June 30, 2013 and 2012, the pre-tax effects of energy-related derivatives not designated as hedging instruments on Southern Company's and Southern Power's statements of income were immaterial.

For the three and six months ended June 30, 2013 and 2012, the pre-tax effects of foreign currency derivatives not designated as hedging instruments were recorded as regulatory assets and liabilities and were immaterial for Southern Company and Mississippi Power.

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, 2013, the fair value of derivative liabilities with contingent features, by registrant, was as follows:



	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
					(in millions)
Derivative liabilities	$	20	$	4	$	7	$	7	$	2	$	—

At June 30, 2013, the registrants had no collateral posted with their derivative counterparties. 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. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $20 million for each registrant. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants have a credit rating change to below investment grade.

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

Campo Verde Solar, LLC

On April 23, 2013, Southern Power and Turner Renewable Energy, LLC, through Southern Turner Renewable Energy, LLC (STR), acquired all of the outstanding membership interests of Campo Verde Solar, LLC (Campo Verde) from First Solar, Inc., the developer of the project. Campo Verde is constructing an approximately 139-MW solar photovoltaic facility in Southern California. The solar facility is expected to begin commercial operation in the fourth quarter 2013. The output of the plant is contracted under a 20-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy, which is expected to begin in the fourth quarter 2013. The acquisition is in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Campo Verde included cash consideration of $136.6 million, of which $111.6 million was paid at closing and $25.0 million will be paid upon achievement of certain milestones. The allocation of the purchase price to individual assets has not been finalized. Under an engineering, procurement, and construction agreement (Construction Agreement), an additional $353 million to $363 million will be paid to a subsidiary of First Solar, Inc. (Construction Contractor) to complete construction of the solar facility.

In the event certain unforeseeable conditions occur at the project site, the Construction Contractor may terminate the Construction Agreement, and in the event the Construction Contractor does not achieve certain construction or project development milestones by certain dates, STR may terminate the Construction Agreement. In each case, a subsidiary of First Solar will be required to make a termination payment to STR equal to STR's investment in Campo Verde (net of any tax or other benefits received by STR) and STR will be required to transfer its ownership in Campo Verde to the subsidiary of First Solar (Termination Payment and Transfer). In addition, under the acquisition agreement, a subsidiary of First Solar may require the Termination Payment and Transfer to occur in the event costs relating to certain contingencies exceed a certain threshold until such time that the contingencies are satisfactorily resolved under the terms of the acquisition agreement, and STR may require the Termination Payment and Transfer to occur in the event certain contingencies are not satisfactorily resolved. The ultimate outcome of this matter cannot be determined at this time; however, STR believes the likelihood of a Termination Payment and Transfer to be remote at the acquisition date.

(J) INVESTMENTS IN LEVERAGED LEASES

See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

restructuring, Southern Company recalculated its net investment in the lease to reflect changes in the future cash flows to Southern Company as owner/lessor. As a result of the recalculation, Southern Company recorded an after-tax charge to income during the first quarter 2013 of approximately $16 million. This noncash charge reflects a reallocation of previously recognized lease income that will be reflected in income over the remaining term of the lease.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(K) SEGMENT AND RELATED INFORMATION

Southern Company's reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $89 million and $167 million for the three and six months ended June 30, 2013, respectively, and $106 million and $218 million for the three and six months ended June 30, 2012, 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 intersegment revenues are not material. Financial data for business segments and products and services was as follows:



	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2013:
Operating revenues	$	4,018	$	307	$	(95	)	$	4,230	$	38		$	(22	)	$	4,246
Segment net income (loss)^(a)(b)	268		28		—			296		4			(3		)	297
Six Months Ended June 30, 2013:
Operating revenues	7,687		610		(181		)	8,116		73			(46		)	8,143
Segment net income (loss)^(a)(c)	334		57		—			391		(12		)	(1		)	378
Total assets at June 30, 2013	$	59,177	$	4,139	$	(122	)	$	63,194	$	1,064		$	(297	)	$	63,961
Three Months Ended June 30, 2012:
Operating revenues	$	3,989	$	286	$	(109	)	$	4,166	$	35		$	(20	)	$	4,181
Segment net income (loss)^(a)	549		47		—			596		27			—			623
Six Months Ended June 30, 2012:
Operating revenues	7,438		539		(222		)	7,755		73			(43		)	7,785
Segment net income (loss)^(a)	888		76		—			964		28			(1		)	991
Total assets at December 31, 2012	$	58,600	$	3,780	$	(129	)	$	62,251	$	1,116		$	(218	)	$	63,149

(a) After dividends on preferred and preference stock of subsidiaries.

(b) Segment net income (loss) for the three months ended June 30, 2013 includes a $450 million pre-tax charge ($277.9 million after tax) for an estimated probable loss on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Cost Estimate" herein for additional information.

(c) Segment net income (loss) for the six months ended June 30, 2013 includes a $990 million pre-tax charge ($611.3 million after tax) for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Cost Estimate" herein for additional information.

Products and Services



	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2013	$	3,620	$	454	$	156	$	4,230
Three Months Ended June 30, 2012	3,597		415		154		4,166

Six Months Ended June 30, 2013	6,918		886		312		8,116
Six Months Ended June 30, 2012	6,689		764		302		7,755

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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.



2013	Total Number of Shares Purchased^(a)	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ^(a)
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
Total	—	N/A	N/A	N/A

(a)

In July 2012, Southern Company announced a program to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. As of December 31, 2012, Southern Company had repurchased a total of 9,439,561 shares under this program. In January 2013, Southern Company announced that it planned to continue this program through 2015. There were no repurchases under this program in the first six months of 2013 and no further repurchases under the program are anticipated.

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Item 6. Exhibits.



(3) Articles of Incorporation

Gulf Power

(d)1	-	Amendment to the amended and restated Articles of Incorporation of Gulf Power dated June 17, 2013. (Designated in Form 8-K dated June 10, 2013, File No. 1-31737, as Exhibit 4.7.)

(4) Instruments Describing Rights of Security Holders, Including Indentures

Gulf Power

(d)1	-	Twentieth Supplemental Indenture to Senior Note Indenture dated as of June 18, 2013, providing for the issuance of the Series 2013A 5.00% Senior Notes due June 15, 2043. (Designated in Form 8-K dated June 10, 2013, File No. 1-31737, as Exhibit 4.2.)

(10) Material Contracts

Georgia Power

(c)1	-	Separation Agreement between Georgia Power and Ronnie L. Labrato effective April 1, 2013.

(c)2	-	Release Agreement between Georgia Power and Ronnie L. Labrato effective April 1, 2013.

Mississippi Power
(e)1	-	Consulting Agreement between Mississippi Power and Edward Day, VI effective May 20, 2013.

(e)2	-	Separation and Release Agreement between Mississippi Power and Thomas O. Anderson, IV effective May 31, 2013.

(e)3	-	Amended Deferred Compensation Agreement, effective December 31, 2008 between Southern Company, Southern Company Services, Inc., Georgia Power, Gulf Power and G. Edison Holland, Jr. (Designated in Form 10-Q for the quarter ended March 31, 2011, File No. 001-11229, as Exhibit 10(a)2.)

(e)4	-	Base Salaries of Named Executive Officers.

(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, 2012, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.)

Alabama Power

(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2012, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)

Georgia Power

(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2012, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)

(c)2	-	Power of Attorney for W. Ron Hinson. (Designated in Form 10-Q for the quarter ended March 31, 2013, File No. 1-6468 as Exhibit 24(c)2 and incorporated herein by reference.)

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Gulf Power

(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2012, File No. 001-31737 as Exhibit 24(d) and incorporated herein by reference.)

Mississippi Power

(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2012, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.)
(e)2	-	Power of Attorney for G. Edison Holland, Jr.


Southern Power

(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2012, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)

(31) Section 302 Certifications

Southern Company

(a)1	-	Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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

(b)1	-	Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(b)2	-	Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Georgia Power

(c)1	-	Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(c)2	-	Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Gulf Power

(d)1	-	Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(d)2	-	Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Mississippi Power

(e)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(e)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Southern Power

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

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

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(32) Section 906 Certifications

Southern Company

(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Alabama Power

(b)	-	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Georgia Power

(c)	-	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Gulf Power

(d)	-	Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Mississippi Power

(e)	-	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Southern Power

(f)	-	Certificate of Southern Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

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(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 6, 2013

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ALABAMA POWER COMPANY

SIGNATURES



		ALABAMA POWER COMPANY

By		Charles D. McCrary
		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 6, 2013

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GEORGIA POWER COMPANY

SIGNATURES



		GEORGIA POWER COMPANY

By		W. Paul Bowers
		President and Chief Executive Officer
		(Principal Executive Officer)

By		W. Ron Hinson
		Executive Vice President, Chief Financial Officer, Treasurer, and Comptroller
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 6, 2013

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GULF POWER COMPANY

SIGNATURES



		GULF POWER COMPANY

By		S. W. Connally, Jr.
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Richard S. Teel
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 6, 2013

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MISSISSIPPI POWER COMPANY

SIGNATURES



		MISSISSIPPI POWER COMPANY

By		G. Edison Holland, Jr.
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Moses H. Feagin
		Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 6, 2013

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SOUTHERN POWER COMPANY

SIGNATURES



		SOUTHERN POWER COMPANY

By		Oscar C. Harper IV
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Michael W. Southern
		Senior Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 6, 2013

202