10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

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

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 September 30, 2013
The Southern Company	Par Value $5 Per Share	881,740,546
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.

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 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	44
	Condensed Statements of Comprehensive Income	44
	Condensed Statements of Cash Flows	45
	Condensed Balance Sheets	46
	Management's Discussion and Analysis of Financial Condition and Results of Operations	48
	Georgia Power Company
	Condensed Statements of Income	66
	Condensed Statements of Comprehensive Income	66
	Condensed Statements of Cash Flows	67
	Condensed Balance Sheets	68
	Management's Discussion and Analysis of Financial Condition and Results of Operations	70
	Gulf Power Company
	Condensed Statements of Income	90
	Condensed Statements of Comprehensive Income	90
	Condensed Statements of Cash Flows	91
	Condensed Balance Sheets	92
	Management's Discussion and Analysis of Financial Condition and Results of Operations	94
	Mississippi Power Company
	Condensed Statements of Operations	110
	Condensed Statements of Comprehensive Income (Loss)	110
	Condensed Statements of Cash Flows	111
	Condensed Balance Sheets	112
	Management's Discussion and Analysis of Financial Condition and Results of Operations	114
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	141
	Condensed Consolidated Statements of Comprehensive Income	141
	Condensed Consolidated Statements of Cash Flows	142
	Condensed Consolidated Balance Sheets	143
	Management's Discussion and Analysis of Financial Condition and Results of Operations	145
	Notes to the Condensed Financial Statements	157
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41
Item 4.	Controls and Procedures	41

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 30, 2013

		Page     Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	203
Item 1A.	Risk Factors	203
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	203
	Signatures	206

4

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 as approved by the Georgia PSC
2013 IRP	Georgia Power's triennial Integrated Resource Plan as approved by the Georgia PSC
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
Fitch	Fitch Ratings, Inc.
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	Mercury and Air Toxics Standards
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
MWH	Megawatt-hour
NCCR	Nuclear Construction Cost Recovery
NDR	Natural Disaster Reserve
NRC	Nuclear Regulatory Commission
NSR	New Source Review
OCI	Other Comprehensive Income

5

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

6

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail 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, completion dates of construction projects, completion dates of acquisitions, 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 and retiree benefit plans and the Southern Company system's nuclear decommissioning trust funds;

• advances in technology;

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

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

• actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of Mississippi Power's proposed rate recovery plan, as revised, which includes the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently

7

requires that the Kemper IGCC be placed in service in 2014, and satisfaction of requirements to utilize investment tax credits and grants;

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

• 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.

8

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	4,319		$	4,379		$	11,237		$	11,068
Wholesale revenues	520			497			1,406			1,261
Other electric revenues	166			157			477			459
Other revenues	12			16			40			46
Total operating revenues	5,017			5,049			13,160			12,834
Operating Expenses:
Fuel	1,580			1,553			4,216			3,907
Purchased power	145			164			367			455
Other operations and maintenance	928			906			2,849			2,817
MC Asset Recovery insurance settlement	—			—			—			(19		)
Depreciation and amortization	480			449			1,422			1,335
Taxes other than income taxes	243			237			710			690
Estimated loss on Kemper IGCC	150			—			1,140			—
Total operating expenses	3,526			3,309			10,704			9,185
Operating Income	1,491			1,740			2,456			3,649
Other Income and (Expense):
Allowance for equity funds used during construction	53			39			139			102
Leveraged lease income (loss)	5			5			(11		)	16
Interest expense, net of amounts capitalized	(202		)	(218		)	(628		)	(649		)
Other income (expense), net	(10		)	(4		)	(20		)	(4		)
Total other income and (expense)	(154		)	(178		)	(520		)	(535		)
Earnings Before Income Taxes	1,337			1,562			1,936			3,114
Income taxes	468			569			657			1,098
Consolidated Net Income	869			993			1,279			2,016
Dividends on Preferred and Preference Stock of Subsidiaries	17			17			49			49
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	852		$	976		$	1,230		$	1,967
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.97		$	1.11		$	1.41		$	2.26
Diluted EPS	$	0.97		$	1.11		$	1.40		$	2.23
Average number of shares of common stock outstanding (in millions)
Basic	878			876			874			872
Diluted	881			883			879			880
Cash dividends paid per share of common stock	$	0.5075		$	0.4900		$	1.5050		$	1.4525

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

10

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)						(in millions)
Consolidated Net Income	$	869		$	993		$	1,279		$	2,016
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $1, $- and $(4), respectively	—			(4		)	—			(11		)
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $5 and $4, respectively	1			3			7			7
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $-, $3 and $1, respectively	1			1			4			3
Total other comprehensive income (loss)	2			—			11			(1		)
Dividends on preferred and preference stock of subsidiaries	(17		)	(17		)	(49		)	(49		)
Comprehensive Income	$	854		$	976		$	1,241		$	1,966

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

11

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2013			2012
	(in millions)
Operating Activities:
Consolidated net income	$	1,279		$	2,016
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,725			1,602
Deferred income taxes	263			645
Allowance for equity funds used during construction	(139		)	(102		)
Leveraged lease income (loss)	11			(16		)
Pension, postretirement, and other employee benefits	124			78
Stock based compensation expense	48			45
Retail fuel cost recovery — long-term	(123		)	118
Estimated loss on Kemper IGCC	1,140			—
Other, net	64			34
Changes in certain current assets and liabilities —
-Receivables	(407		)	(157		)
-Fossil fuel stock	471			(232		)
-Materials and supplies	33			(28		)
-Other current assets	(1		)	22
-Accounts payable	(140		)	(240		)
-Accrued taxes	268			311
-Accrued compensation	(198		)	(142		)
-Retail fuel cost recovery — short-term	(3		)	112
-Other current liabilities	(4		)	(22		)
Net cash provided from operating activities	4,411			4,044
Investing Activities:
Property additions	(3,978		)	(3,558		)
Investment in restricted cash	(169		)	(230		)
Distribution of restricted cash	94			234
Nuclear decommissioning trust fund purchases	(744		)	(758		)
Nuclear decommissioning trust fund sales	742			756
Cost of removal, net of salvage	(90		)	(83		)
Change in construction payables, net	(8		)	(61		)
Other investing activities	51			(58		)
Net cash used for investing activities	(4,102		)	(3,758		)
Financing Activities:
Decrease in notes payable, net	(70		)	(521		)
Proceeds —
Long-term debt issuances	2,421			3,114
Interest-bearing refundable deposit related to asset sale	—			150
Preference stock	50			—
Common stock issuances	479			381
Redemptions —
Long-term debt	(1,767		)	(2,098		)
Common stock repurchased	(19		)	(85		)
Payment of common stock dividends	(1,314		)	(1,267		)
Payment of dividends on preferred and preference stock of subsidiaries	(49		)	(49		)
Other financing activities	14			30
Net cash used for financing activities	(255		)	(345		)
Net Change in Cash and Cash Equivalents	54			(59		)
Cash and Cash Equivalents at Beginning of Period	628			1,315
Cash and Cash Equivalents at End of Period	$	682		$	1,256
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $67 and $62 capitalized for 2013 and 2012, respectively)	$	564		$	589
Income taxes, net	149			6
Noncash transactions — accrued property additions at end of period	539			531
Noncash transactions — capital lease obligation	83			—

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

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2013			At December 31, 2012
	(in millions)
Current Assets:
Cash and cash equivalents	$	682		$	628
Restricted cash and cash equivalents	—			7
Receivables —
Customer accounts receivable	1,292			961
Unbilled revenues	473			441
Under recovered regulatory clause revenues	45			29
Other accounts and notes receivable	269			235
Accumulated provision for uncollectible accounts	(19		)	(17		)
Fossil fuel stock, at average cost	1,349			1,819
Materials and supplies, at average cost	959			1,000
Vacation pay	164			165
Prepaid expenses	418			657
Other regulatory assets, current	120			163
Other current assets	33			74
Total current assets	5,785			6,162
Property, Plant, and Equipment:
In service	64,793			63,251
Less accumulated depreciation	22,821			21,964
Plant in service, net of depreciation	41,972			41,287
Other utility plant, net	252			263
Nuclear fuel, at amortized cost	832			851
Construction work in progress	7,144			5,989
Total property, plant, and equipment	50,200			48,390
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,397			1,303
Leveraged leases	658			670
Miscellaneous property and investments	220			216
Total other property and investments	2,275			2,189
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,402			1,385
Unamortized debt issuance expense	146			133
Unamortized loss on reacquired debt	291			309
Other regulatory assets, deferred	4,012			4,032
Other deferred charges and assets	586			549
Total deferred charges and other assets	6,437			6,408
Total Assets	$	64,697		$	63,149

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

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2013			At December 31, 2012
	(in millions)
Current Liabilities:
Securities due within one year	$	1,307		$	2,335
Interest-bearing refundable deposit related to asset sale	150			150
Notes payable	750			825
Accounts payable	1,281			1,387
Customer deposits	377			370
Accrued taxes —
Accrued income taxes	87			10
Other accrued taxes	512			391
Accrued interest	262			237
Accrued vacation pay	210			212
Accrued compensation	250			433
Other regulatory liabilities, current	89			107
Other current liabilities	429			557
Total current liabilities	5,704			7,014
Long-term Debt	21,053			19,274
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,291			9,938
Deferred credits related to income taxes	203			211
Accumulated deferred investment tax credits	819			894
Employee benefit obligations	2,548			2,540
Asset retirement obligations	1,967			1,748
Other cost of removal obligations	1,278			1,194
Other regulatory liabilities, deferred	375			289
Other deferred credits and liabilities	550			668
Total deferred credits and other liabilities	18,031			17,482
Total Liabilities	44,788			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 — September 30, 2013: 890 million shares
— December 31, 2012: 878 million shares
Treasury — September 30, 2013: 8.1 million shares
— December 31, 2012: 10.0 million shares
Par value	4,447			4,389
Paid-in capital	5,262			4,855
Treasury, at cost	(363		)	(450		)
Retained earnings	9,543			9,626
Accumulated other comprehensive loss	(111		)	(123		)
Total Common Stockholders' Equity	18,778			18,297
Preferred and Preference Stock of Subsidiaries	756			707
Total Stockholders' Equity	19,534			19,004
Total Liabilities and Stockholders' Equity	$	64,697		$	63,149

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

14

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2013 vs. THIRD 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 (in which Mississippi Power is ultimately expected to hold an 85% ownership interest in the 582-MW facility). See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

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 has negatively impacted the Southern Company system's 2013 actual performance on its peak season equivalent forced outage rate, one of its key performance indicators, 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 have negatively impacted Southern Company's earnings per share, one of its key performance indicators, for 2013, as compared to the target.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(124)	(12.7)	$(737)	(37.5)

Southern Company's third quarter 2013 net income after dividends on preferred and preference stock of subsidiaries was $852 million ($0.97 per share) compared to $976 million ($1.11 per share) for the third quarter 2012. The decrease was primarily related to a $150 million pre-tax charge ($93 million after-tax) for 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 million of grants awarded to the project by the DOE under the

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 was a decrease in revenues due to less favorable weather in the third quarter 2013 as compared to the corresponding period in 2012, partially offset by an increase related to retail revenue rate effects at Georgia Power. In addition, depreciation increased related to new generating plants in service and operations and maintenance expenses increased.

Southern Company's year-to-date 2013 net income after dividends on preferred and preference stock of subsidiaries was $1.2 billion ($1.41 per share) compared to $2.0 billion ($2.26 per share) for year-to-date 2012. The decrease was primarily related to $1.1 billion in pre-tax charges ($704 million after-tax) for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of 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.

Retail Revenues

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(60)	(1.4)	$169	1.5

In the third quarter 2013, retail revenues were $4.3 billion compared to $4.4 billion for the corresponding period in 2012. For year-to-date 2013, retail revenues were $11.2 billion compared to $11.1 billion for the corresponding period in 2012.

Details of the changes in retail revenues were as follows: 

	Third Quarter 2013				Year-to-Date 2013
	(in millions)			(% change)	(in millions)			(% change)
Retail – prior year	$	4,379			$	11,068
Estimated change in –
Rates and pricing	34			0.8	139			1.2
Sales growth (decline)	9			0.2	(16		)	(0.1)
Weather	(94		)	(2.2)	(84		)	(0.8)
Fuel and other cost recovery	(9		)	(0.2)	130			1.2
Retail – current year	$	4,319		(1.4)%	$	11,237		1.5%

Revenues associated with changes in rates and pricing increased in the third quarter 2013 when compared to the corresponding period in 2012 primarily due to base tariff increases at Georgia Power effective January 1, 2013, as approved by the Georgia PSC, related to placing a new generating unit at Plant McDonough-Atkinson in service and the financing costs related to the construction of Plant Vogtle Units 3 and 4, partially offset by lower contributions from market-driven rates from commercial and industrial customers.

Revenues associated with changes in rates and pricing increased for year-to-date 2013 when compared to the corresponding period 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 and the financing costs related to the construction of Plant Vogtle Units 3 and 4, as well as higher contributions from market-driven rates from commercial and industrial customers.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues attributable to changes in sales increased in the third quarter 2013 when compared to the corresponding period in 2012. The increase was due to a 2.6% increase in industrial KWH sales and a 1.1% increase in weather-adjusted commercial KWH sales, partially offset by a 0.3% decrease in weather-adjusted residential KWH sales. The increase in industrial KWH sales for the third quarter 2013 was primarily due to increases in the paper, primary metals, and stone, clay, and glass sectors, partially offset by decreases in the pipeline and military sectors. The increase in weather-adjusted commercial KWH sales for the third quarter 2013 was primarily due to increased customer usage and customer growth. The decrease in weather-adjusted residential KWH sales for the third quarter 2013 was primarily due to decreased customer usage, partially offset by customer growth.

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 0.5% decrease in weather-adjusted residential KWH sales, partially offset by a 0.4% increase in industrial KWH sales. Weather-adjusted commercial KWH sales were flat. The decrease in weather-adjusted residential KWH sales for year-to-date 2013 was primarily due to decreased customer usage, partially offset by customer growth. The increase in industrial KWH sales for year-to-date 2013 was primarily due to increases in the primary metals, paper, and stone, clay, and glass sectors, partially offset by decreases in the chemicals and military sectors.

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 0.8% as compared to the corresponding period in 2012 while weather-adjusted commercial KWH sales increased 0.3% as compared to the corresponding period in 2012.

Fuel and other cost recovery revenues decreased $9 million in the third quarter 2013 when compared to the corresponding period in 2012 primarily due to an increase in hydro generation resulting from greater rainfall. Fuel and other cost recovery revenues increased$130 millionfor year-to-date 2013 when compared to the corresponding period in 2012 primarily due to higher fuel costs, partially offset by an increase in hydro generation resulting from greater rainfall. 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$23	4.6	$145	11.5

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 third quarter 2013, wholesale revenues were $520 million compared to $497 million for the corresponding period in 2012, reflecting a $14 million increase in capacity revenues and a $9 million increase in energy revenues. The increase in capacity revenues was primarily due to an increase in capacity amounts under existing PPAs. The increase in energy revenues was primarily related to an increase in the average cost of natural gas, partially offset

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

by a decrease in volume related to less favorable weather in the third quarter 2013 as compared to the corresponding period in 2012.

For year-to-date 2013, wholesale revenues were $1.4 billion compared to $1.3 billion for the corresponding period in 2012, reflecting an $86 million increase in energy revenues and a $59 million increase in capacity revenues. The increase in capacity revenues was primarily due to the commencement of a new PPA at Southern Power's Plant Nacogdoches, which was placed in service in June 2012 and an increase in capacity amounts under existing PPAs. 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 third quarter 2013 as compared to the corresponding period in 2012.

Fuel and Purchased Power Expenses

	Third Quarter 2013 vs. Third Quarter 2012				Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	27		1.7	$	309		7.9
Purchased power	(19		)	(11.6)	(88		)	(19.3)
Total fuel and purchased power expenses	$	8			$	221

In the third quarter 2013, total fuel and purchased power expenses were $1.73 billion compared to $1.72 billion for the corresponding period in 2012. The increase was primarily the result of an $86 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $63 million decrease in the volume of KWHs purchased and a $15 million decrease in the volume of KWHs generated as a result of less favorable weather compared to the corresponding period in 2012 reducing total demand.

For year-to-date 2013, total fuel and purchased power expenses were $4.6 billion compared to $4.4 billion for the corresponding period in 2012. The increase was primarily the result of a $364 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices and a $46 million increase in the volume of KWHs generated, partially offset by a $189 million decrease in the volume of KWHs purchased as a result of less favorable weather compared to the corresponding period in 2012 reducing total demand.

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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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter  2013	Third Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (billions of KWHs)	50	50	136	133
Total purchased power (billions of KWHs)	3	5	10	14
Sources of generation (percent) —
Coal	44	43	40	40
Nuclear	16	16	17	17
Gas	37	40	39	41
Hydro	3	1	4	2
Cost of fuel, generated (cents per net KWH) —
Coal	4.06	4.01	4.08	4.09
Nuclear	0.87	0.86	0.87	0.83
Gas	3.27	2.94	3.30	2.76
Average cost of fuel, generated (cents per net KWH)	3.24	3.09	3.21	2.97
Average cost of purchased power (cents per net KWH)(a)	5.66	4.98	5.22	4.32

(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 third quarter 2013, fuel expense was $1.58 billion compared to $1.55 billion for the corresponding period in 2012. The increase was primarily due to an 11.2% increase in the average cost of natural gas per KWH generated, partially offset by a 4.6% decrease in KWHs generated by natural gas and a 292.5% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

For year-to-date 2013, fuel expense was $4.2 billion compared to $3.9 billion for the corresponding period in 2012. The increase was primarily due to a 19.6% increase in the average cost of natural gas per KWH generated, partially offset by a 138.9% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

Purchased Power

In the third quarter 2013, purchased power expense was $145 million compared to $164 million for the corresponding period in 2012. The decrease was primarily due to a 27.3% 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 13.7% increase in the average cost per KWH purchased.

For year-to-date 2013, purchased power expense was $367 million compared to $455 million for the corresponding period in 2012. The decrease was primarily due to a 31.5% 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 20.8% 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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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$22	2.4	$32	1.1

In the third quarter 2013, other operations and maintenance expenses were $928 million compared to $906 million for the corresponding period in 2012. The increase was primarily due to a $12 million increase in pension costs, a $12 million increase in transmission and distribution costs, and a $5 million increase in customer service expenses, partially offset by a $9 million decrease in other production expenses primarily related to outage and maintenance costs and commodity and labor costs.

For year-to-date 2013, other operations and maintenance expenses were $2.85 billion compared to $2.82 billion for the corresponding period in 2012. The increase was primarily the result of a $37 million increase in pension costs, a $9 million increase in amortization of Alabama Power's nuclear outage expenses, and a $9 million increase in transmission and distribution costs. These increases were partially offset by a $16 million decrease in other production expenses primarily related to outage and maintenance costs and commodity and labor 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.

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

MC Asset Recovery Insurance Settlement

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$19	N/M

N/M – Not meaningful

In the second quarter 2012, Southern Company received an insurance recovery related to a litigation settlement with MC Asset Recovery, LLC, which resulted in income of $19 million. See Note 3 to the financial statements of Southern Company under "Insurance Recovery" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$31	6.9	$87	6.5

In the third quarter 2013, depreciation and amortization was $480 million compared to $449 million for the corresponding period in 2012. The increase was primarily due to additional plant in service related to the completion of Georgia Power's Plant McDonough-Atkinson Unit 6 in October 2012 and Southern Power's Plants Apex and Cleveland in July 2012 and December 2012, respectively, certain unit retirement decisions (with respect to the portion of such units dedicated to wholesale service) at Georgia Power, and additional transmission and distribution projects.

For year-to-date 2013, depreciation and amortization was $1.4 billion compared to $1.3 billion for the corresponding period in 2012. The increase was primarily due to additional plant in service related to the completion of Georgia Power's Plant McDonough-Atkinson Units 5 and 6 in April 2012 and October 2012, respectively, and Southern Power's Plant Nacogdoches in June 2012, Plant Apex in July 2012, and Plant Cleveland in December 2012, certain unit retirement decisions (with respect to the portion of such units dedicated to wholesale service) at Georgia Power, and additional transmission and distribution projects. These increases were partially offset by a net reduction in amortization primarily related to amortization of a regulatory liability for state income

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

tax credits at Georgia Power and by the deferral of certain expenses under an accounting order at Alabama Power. See Note 1 to the financial statements of Southern Company 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$6	2.5	$20	2.9

In the third quarter 2013, taxes other than income taxes were $243 million compared to $237 million for the corresponding period in 2012. The increase was the result of an increase in property taxes.

For year-to-date 2013, taxes other than income taxes were $710 million compared to $690 million for the corresponding period in 2012. The increase was primarily the result of increases in property taxes and municipal franchise fees.

Estimated Loss on Kemper IGCC

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$150	N/M	$1,140	N/M

N/M – Not meaningful

In the third quarter 2013 and year-to-date 2013, estimated probable losses on the Kemper IGCC of $150 million and $1.1 billion, 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$14	35.9	$37	36.3

In the third quarter 2013, AFUDC equity was $53 million compared to $39 million for the corresponding period in 2012. For year-to-date 2013, AFUDC equity was $139 million compared to $102 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)

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(27)	N/M

N/M – Not meaningful

For year-to-date 2013, leveraged lease income (loss) was $(11) million compared to $16 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(16)	(7.3)	$(21)	(3.2)

In the third quarter 2013, interest expense, net of amounts capitalized was $202 million compared to $218 million for the corresponding period in 2012. For year-to-date 2013, interest expense, net of amounts capitalized was $628 million compared to $649 million for the corresponding period in 2012. These decreases were primarily due to lower interest rates, the timing of issuances and redemptions of long term-debt, an increase in capitalized interest primarily resulting from AFUDC debt associated with Mississippi Power's Kemper IGCC, and an increase in capitalized interest associated with the construction of Southern Power's Plants Campo Verde and Spectrum. For year-to-date 2013, these decreases were partially offset by a decrease in capitalized interest resulting from the completion of Southern Power's Plants Nacogdoches and Cleveland, a reduction in AFUDC debt due to the completion of Georgia Power's Plant McDonough-Atkinson Units 5 and 6, and the conclusion of certain state and federal tax audits in 2012.

Other Income (Expense), Net

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	N/M	$(16)	N/M

N/M – Not meaningful

In the third quarter 2013, other income (expense), net was $(10) million compared to $(4) million for the corresponding period in 2012. The change was primarily related to charitable contributions, partially offset by gains on sales of non-utility property at Alabama Power.

For year-to-date 2013, other income (expense), net was $(20) million compared to $(4) million for the corresponding period in 2012. The change was primarily related to the conclusion of certain federal income tax audits in 2012 and charitable contributions, partially offset by gains on sales of non-utility property at Alabama Power.

Income Taxes

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(101)	(17.8)	$(441)	(40.2)

In the third quarter 2013, income taxes were $468 million compared to $569 million for the corresponding period in 2012. The decrease was primarily due to lower pre-tax earnings, an increase in tax benefits recognized from investment tax credits (ITCs) at Southern Power, and a net increase in non-taxable AFUDC equity.

For year-to-date 2013, income taxes were $657 million compared to $1.1 billion for the corresponding period in 2012. The decrease was primarily due to lower pre-tax earnings, a net increase in tax benefits recognized from ITCs, primarily at Southern Power, and a net increase in non-taxable AFUDC equity, partially offset by a decrease in state income tax credits, primarily at Georgia Power.

FUTURE EARNINGS POTENTIAL

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

New Source Review Actions

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – New Source Review Actions" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K for additional information. On September 19, 2013, a three-judge panel of the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment of the U.S. District Court for the Northern District of Alabama in favor of Alabama Power, which was based on the exclusion of the testimony of certain of the EPA's experts, and remanded the case back to the U.S. District Court for the Northern District of Alabama for further proceedings. On October 31, 2013, Alabama Power filed with the U.S. Court of Appeals for the Eleventh Circuit a petition for rehearing. In February 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the 2011 judgment and recusal of the judge in the case involving Alabama Power (including claims related to the unit co-owned by Mississippi Power), which remains pending. The ultimate outcome of these matters 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 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 case is now concluded.

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 the State 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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 and, on October 31, 2013, further extended the deadline until November 20, 2013.

The ultimate impact of these proposed regulations will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of the management and disposal of coal combustion byproducts. On September 30, 2013, the U.S. District Court for the District of Columbia issued an order granting partial summary judgment to the environmental groups and other parties, ruling that the EPA has a statutory obligation to review and revise, as necessary, the federal solid waste regulations applicable to coal combustion byproducts and, on October 29, 2013, directed the EPA to provide a proposed schedule to complete the rulemaking. The impact of this order depends on further judicial and regulatory action and, therefore, 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 – 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 September 20, 2013, the EPA proposed revised regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel-fired steam electric generating units. A Presidential memorandum issued on June 25, 2013 also directed the EPA 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 market-based contracts. 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. 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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

traditional operating companies continuously monitor their under or over recovered fuel cost balances. 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 $178 million at September 30, 2013 compared to the total over recovered fuel balance at Georgia Power, Gulf Power, and Mississippi Power at December 31, 2012 of approximately $303 million. At September 30, 2013, Gulf Power had under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $10 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.

See 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.

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. On August 13, 2013, the Alabama PSC voted to issue a report on Rate RSE that found that Alabama Power's Rate RSE mechanism continues to be just and reasonable to customers and Alabama Power, but recommended Alabama Power modify Rate RSE as follows:

• Eliminate the provision of Rate RSE establishing an allowed range of ROE, which is currently 13.0% to 14.5%, with an adjusting point of 13.75%.

• Eliminate the provision of Rate RSE limiting Alabama Power's capital structure to an allowed equity ratio of 45%.

• Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the current Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

• Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

Substantially all other provisions of Rate RSE would remain unchanged.

On August 21, 2013, Alabama Power filed its consent to these recommendations with the Alabama PSC. The changes are effective for calendar year 2014.

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 13, 2013, the Alabama PSC approved Alabama Power's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets currently being recovered through Rate RSE. The revenue impact as a result of this revision is estimated to be $50 million in 2014; however, this petition was 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. Any unrecovered amounts associated with

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

2014 environmental compliance costs will be reflected in the 2015 Rate CNP Environmental filing. 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.

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 September 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 13, 2013, the Alabama PSC approved Alabama Power's petition requesting authorization to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures to be deferred and amortized are estimated to total approximately $70 million. This petition was 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.

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 was 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%.

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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.

Hearings on Georgia Power’s testimony were held in October 2013. In testimony filed on October 18, 2013 and October 22, 2013, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period and a 10.0% ROE that would result in excess revenues of $165 million. However, the Georgia PSC Staff also proposed no change to Georgia Power’s current retail base rates through 2014. The excess earnings in 2014 would be used to reduce rate increases in 2015 and 2016. The Georgia PSC Staff further proposed reducing the allowed ROE range to 50 basis points above and below the authorized ROE with one-third of any earnings above the range used to reduce future ECCR tariff increases and the remaining two-thirds applied to rate reductions. Georgia Power disagrees with the Georgia PSC Staff's positions. Hearings on the Georgia PSC Staff and intervenor testimony and Georgia Power's rebuttal hearings will be held in November 2013.

The Georgia PSC is scheduled to issue a final order in this matter in 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. On September 30, 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 IRP in order to comply with the State of Georgia's Multi-Pollutant Rule.

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, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division on September 10, 2013 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, and subsequently has requested Georgia PSC approval. During 2013, Georgia Power has executed four PPAs to purchase a total of 169 MWs of biomass capacity and energy from four facilities in Georgia that will commence in 2015 and end in 2035. On May 21, 2013, the Georgia PSC approved two of the biomass PPAs. The two wind PPAs and the two Georgia PSC-approved biomass PPAs result in contractual obligations of approximately $13 million in 2015, $47 million in 2016, $49 million in 2017, and $1.29 billion thereafter. If approved by the Georgia PSC, the additional biomass PPAs will result in contractual obligations of approximately $1 million in 2015, $11 million in 2016, $12 million in 2017, and $249 million thereafter. The four biomass PPAs are contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.

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 $490 million and $540 million in 2013.

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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Kemper IGCC (in which Mississippi Power is ultimately expected to hold an 85% ownership interest in the 582-MW facility). 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 through 2015 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.

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Nuclear Decommissioning" and "Asset Retirement Obligations" herein for additional information. In September 2013, Alabama Power received a 2013 decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in the asset retirement obligation liability of approximately $102 million.

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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthernCompanyanditssubsidiariescannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofSouthernCompanyinItem8oftheForm10-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 and June 6, 2013, the NRC issued orders relating to hardened vents for certain classes of containment structures, including the ones in use at Plant Hatch. Southern Company is continuing to analyze the impact of these orders. The ultimate outcome of this matter cannot be determined at this time; however, management does not currently anticipate that the compliance costs associated with these orders 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 4, 2013. Plant Bowen Unit 2 (approximately 700 MWs) remains offline pending completion of the 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.

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

Mississippi Power has extended the scheduled in-service date for the Kemper IGCC to the fourth quarter 2014 and revised its cost estimate to complete construction 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, $450 million, and $150 million in the first, second, and third 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. Mississippi Power could experience further construction cost increases and/or schedule extensions 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 further schedule extensions associated with

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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.

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 MANAGEMENT'S DISCUSSION AND ANALYSIS – 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 for the nine months ended September 30, 2013 were negatively affected by the estimated probable losses relating to the Kemper IGCC, Southern Company's financial condition remained stable at September 30, 2013. These charges for the nine months ended September 30, 2013 have resulted in cash expenditures of $57 million with no recovery as of September 30, 2013 and are expected to result in future cash expenditures of $1.1 billion with no 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 $4.4 billion for the first nine months of 2013, an increase of $367 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 $4.1 billion for the first nine months of 2013 primarily due to property additions to utility plant. Net cash used for financing activities totaled $255 million for the first nine months of 2013. This was primarily due to redemptions of long-term debt and payments of common stock dividends, partially offset by issuances of long-term debt and common stock. 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 nine months of 2013 include an increase of $1.8 billion in total property, plant, and equipment for construction of generation, transmission, and distribution facilities and a $1.8 billion 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.

The market price of Southern Company's common stock at the end of the third quarter 2013 was $41.18 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $21.30 per share, representing a market-to-book ratio of 193%, compared to $42.81, $21.09, and 203%, respectively, at the end of 2012. The dividend for the third quarter 2013 was $0.5075 per share compared to $0.49 per share in the third 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.

32

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Approximately $1.3 billion will be required through September 30, 2014 to fund maturities and announced redemptions 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 $6.6 billion for 2013, $6.1 billion for 2014, and $5.2 billion for 2015. Included in these estimated amounts are expenditures related to construction of the Kemper IGCC of $1.6 billion in 2013 and $260 million in 2014, which is net of SMEPA's 15% proposed ownership share of the Kemper IGCC, which reflects costs of approximately $545 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).

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

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.

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, 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. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. The conditional commitment will

33

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

expire on December 31, 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 September 30, 2013, Southern Company and its subsidiaries had approximately $682 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2013 were as follows:

	Expires(a)														Executable Term Loans				Due Within One Year
Company	2013		2014		2015		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	1		268		35		—		1,000		1,304		1,304		53		—		53		146
Georgia Power	—		—		—		150		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		90		—		165		—		275		275		45		—		45		65
Mississippi Power	15		120		—		165		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		486		—		—		—		—
Other	—		75		25		—		—		100		100		25		—		25		50
Total	$	36	$	553	$	60	$	480	$	4,100	$	5,229	$	5,201	$	148	$	40	$	188	$	331

(a) No credit arrangements expire in 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 September 30, 2013 was approximately $1.8 billion. In addition, at September 30, 2013, the traditional operating companies had $455 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.

As reflected in the table above, during the first nine 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 to capitalization 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.

34

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 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	$	760	0.2%	$	971	0.2%	$	1,431
Short-term bank debt	—		—%	5		1.2%	125
Total	$	760	0.2%	$	976	0.2%

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

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	656
Below BBB- and/or Baa3	2,591

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 September 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

35

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 August 6, 2013, Moody's downgraded the senior unsecured debt and preferred stock ratings of Mississippi Power to Baa1 from A3 and to Baa3 from Baa2, respectively. Moody's maintained the stable ratings outlook for Mississippi Power.

On August 6, 2013, Fitch affirmed the senior unsecured debt and preferred stock ratings of Mississippi Power and revised the ratings outlook for Mississippi Power from stable to negative.

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 third quarter 2013 when compared to the December 31, 2012 reporting period.

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

	Third Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(73	)	$	(85	)
Contracts realized or settled	21			50
Current period changes(a)	(21		)	(38		)
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.

36

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 nine months ended September 30, 2013 were as follows:

	Third Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$	(1	)	$	11
Natural gas options	1			1
Total changes	$	—		$	12

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

	September 30, 2013	June 30, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	203	194	171
Commodity – Natural gas options	64	76	105
Total hedge volume	267	270	276

The weighted average swap contract cost above market prices was approximately $0.27 per mmBtu as of September 30, 2013, $0.28 per mmBtu as of June 30, 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.

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

Asset (Liability) Derivatives	September 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 nine months ended September 30, 2013 and 2012 were not material.

37

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2013 were as follows:

	September 30, 2013 Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2	(73		)	(43		)	(28		)	(2		)
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(73	)	$	(43	)	$	(28	)	$	(2	)

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 nine months of 2013, Southern Company issued approximately 6.6 million shares of common stock for approximately $206 million through the employee and director stock plans, of which 0.7 million shares related to Southern Company's performance share plan. 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. There were no repurchases under this program in the first nine months of 2013 and no further repurchases under the program are anticipated.

During the first seven months of 2013, all sales under the Southern Investment Plan and the employee savings plan were funded with shares acquired on the open market by the independent plan administrators. Beginning in August 2013, Southern Company began using shares held in treasury to satisfy the requirements under the Southern Investment Plan and the employee savings plan. During the third quarter 2013, Southern Company issued approximately 2.0 million shares of common stock previously held in treasury for approximately $80.9 million to satisfy the requirements under the Southern Investment Plan and the employee savings plan.

In addition, during the three months ended September 30, 2013, Southern Company issued approximately 5.4 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of approximately $222.2 million, net of $1.9 million in fees and commissions.

38

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Company(a)	Senior  Note Issuances		Senior  Note Redemptions and  Maturities		Revenue Bond Issuances		Revenue Bond Redemptions and Maturities		Other Long-Term Debt Issuances		Other  Long-Term Debt Redemptions
					(in millions)
Southern Company	$	500	$	—	$	—	$	—	$	—	$	—
Georgia Power	850		1,250		89		89		—		—
Gulf Power	90		90		—		—		—		—
Mississippi Power	—		—		31		83		475		125
Southern Power	300		—		—		—		23		—
Other	—		50		—		—		—		—
Total	$	1,740	$	1,390	$	120	$	172	$	498	$	125

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

In August 2013, Southern Company issued $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes due September 1, 2018. The proceeds were used to pay a portion of Southern Company’s outstanding short-term indebtedness and for other general corporate purposes.

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

In 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 90-day 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 90-day 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 September 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at inception of $83 million with an annual interest rate of

39

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

4.9%.

Subsequent to September 30, 2013, Georgia Power announced the redemption in November 2013 of $100 million aggregate principal amount of its Series 2008C 8.20% Senior Notes due November 1, 2048 and reclassified the outstanding principal balance to securities due within one year at September 30, 2013.

Also subsequent to September 30, 2013, Georgia Power announced the redemptions in November 2013 of $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Third Series 1994 and $49.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1997, which were issued for the benefit of Georgia Power.

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.

40

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 completed the following actions in the second and third quarters of 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 estimating process and schedule;

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

• applied appropriate performance management actions.

Mississippi Power's management has continued to refine and enhance the Kemper IGCC project cost and schedule estimation methodologies and related documentation throughout the second and third quarters of 2013. Mississippi Power’s management’s assessment as to the effectiveness of these refinements and enhancements is expected to be complete at the end of the fourth quarter 2013.

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.

41

(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 third 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 third quarter 2013 that have materially affected or are reasonably likely to materially affect Mississippi Power's internal control over financial reporting.

42

ALABAMA POWER COMPANY

43

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,438		$	1,476		$	3,800		$	3,822
Wholesale revenues, non-affiliates	66			79			186			210
Wholesale revenues, affiliates	47			31			163			51
Other revenues	53			51			155			147
Total operating revenues	1,604			1,637			4,304			4,230
Operating Expenses:
Fuel	467			469			1,240			1,118
Purchased power, non-affiliates	36			31			84			63
Purchased power, affiliates	30			41			102			147
Other operations and maintenance	316			307			965			944
Depreciation and amortization	170			161			487			478
Taxes other than income taxes	85			84			262			255
Total operating expenses	1,104			1,093			3,140			3,005
Operating Income	500			544			1,164			1,225
Other Income and (Expense):
Allowance for equity funds used during construction	7			4			23			13
Interest expense, net of amounts capitalized	(65		)	(71		)	(196		)	(217		)
Other income (expense), net	—			(3		)	1			(6		)
Total other income and (expense)	(58		)	(70		)	(172		)	(210		)
Earnings Before Income Taxes	442			474			992			1,015
Income taxes	174			184			390			394
Net Income	268			290			602			621
Dividends on Preferred and Preference Stock	10			10			30			30
Net Income After Dividends on Preferred and Preference Stock	$	258		$	280		$	572		$	591

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2013		2012			2013		2012
	(in millions)					(in millions)
Net Income	$	268	$	290		$	602	$	621
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(2), $- and $(6), respectively	—		(2		)	—		(9		)
Reclassification adjustment for amounts included in net income, net of tax of $1, $-, $1, and $-, respectively	—		—			1		—
Total other comprehensive income (loss)	—		(2		)	1		(9		)
Comprehensive Income	$	268	$	288		$	603	$	612

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

44

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2013			2012
	(in millions)
Operating Activities:
Net income	$	602		$	621
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	616			574
Deferred income taxes	200			132
Allowance for equity funds used during construction	(23		)	(13		)
Pension, postretirement, and other employee benefits	17			10
Stock based compensation expense	8			7
Other, net	(24		)	(3		)
Changes in certain current assets and liabilities —
-Receivables	(98		)	(83		)
-Fossil fuel stock	173			(93		)
-Materials and supplies	16			(5		)
-Other current assets	(18		)	(1		)
-Accounts payable	(109		)	(167		)
-Accrued taxes	105			146
-Accrued compensation	(36		)	(27		)
-Retail fuel cost over recovery	42			2
-Other current liabilities	(2		)	(15		)
Net cash provided from operating activities	1,469			1,085
Investing Activities:
Property additions	(779		)	(616		)
Nuclear decommissioning trust fund purchases	(162		)	(128		)
Nuclear decommissioning trust fund sales	162			128
Cost of removal, net of salvage	(29		)	(17		)
Change in construction payables	12			(2		)
Other investing activities	35			(11		)
Net cash used for investing activities	(761		)	(646		)
Financing Activities:
Proceeds —
Capital contributions from parent company	18			22
Senior notes issuances	—			250
Redemptions —
Pollution control revenue bonds	—			(1		)
Senior notes	—			(250		)
Payment of preferred and preference stock dividends	(30		)	(30		)
Payment of common stock dividends	(397		)	(404		)
Other financing activities	—			(4		)
Net cash used for financing activities	(409		)	(417		)
Net Change in Cash and Cash Equivalents	299			22
Cash and Cash Equivalents at Beginning of Period	137			344
Cash and Cash Equivalents at End of Period	$	436		$	366
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $8 and $5 capitalized for 2013 and 2012, respectively)	$	182		$	203
Income taxes, net	154			172
Noncash transactions—accrued property additions at end of period	43			16

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

45

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2013			At December 31, 2012
	(in millions)
Current Assets:
Cash and cash equivalents	$	436		$	137
Receivables —
Customer accounts receivable	417			321
Unbilled revenues	133			138
Under recovered regulatory clause revenues	4			23
Other accounts and notes receivable	62			42
Affiliated companies	45			55
Accumulated provision for uncollectible accounts	(9		)	(8		)
Fossil fuel stock, at average cost	302			475
Materials and supplies, at average cost	370			395
Vacation pay	60			61
Prepaid expenses	74			81
Other regulatory assets, current	14			24
Other current assets	3			13
Total current assets	1,911			1,757
Property, Plant, and Equipment:
In service	21,916			21,407
Less accumulated provision for depreciation	8,016			7,761
Plant in service, net of depreciation	13,900			13,646
Nuclear fuel, at amortized cost	357			354
Construction work in progress	638			438
Total property, plant, and equipment	14,895			14,438
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	54			53
Nuclear decommissioning trusts, at fair value	673			605
Miscellaneous property and investments	78			78
Total other property and investments	805			736
Deferred Charges and Other Assets:
Deferred charges related to income taxes	521			525
Deferred under recovered regulatory clause revenues	30			11
Other regulatory assets, deferred	1,056			1,083
Other deferred charges and assets	134			162
Total deferred charges and other assets	1,741			1,781
Total Assets	$	19,352		$	18,712

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

46

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2013			At December 31, 2012
	(in millions)
Current Liabilities:
Securities due within one year	$	250		$	250
Accounts payable —
Affiliated	192			191
Other	225			318
Customer deposits	85			85
Accrued taxes —
Accrued income taxes	68			5
Other accrued taxes	108			33
Accrued interest	63			62
Accrued vacation pay	50			50
Accrued compensation	61			94
Other regulatory liabilities, current	45			3
Other current liabilities	42			52
Total current liabilities	1,189			1,143
Long-term Debt	5,934			5,929
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,596			3,404
Deferred credits related to income taxes	76			79
Accumulated deferred investment tax credits	135			141
Employee benefit obligations	323			321
Asset retirement obligations	720			589
Other cost of removal obligations	822			759
Other regulatory liabilities, deferred	211			183
Other deferred credits and liabilities	59			81
Total deferred credits and other liabilities	5,942			5,557
Total Liabilities	13,065			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	2,255			2,227
Retained earnings	2,151			1,976
Accumulated other comprehensive loss	(26		)	(27		)
Total common stockholder's equity	5,602			5,398
Total Liabilities and Stockholder's Equity	$	19,352		$	18,712

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

47

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2013 vs. THIRD 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(22)	(7.9)	$(19)	(3.2)

Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2013 was $258 million compared to $280 million for the corresponding period in 2012. The decrease in net income was related to less favorable weather in the third quarter 2013 as compared to the corresponding period in 2012, a decrease in revenues related to net investment under Rate Certificated New Plant Environmental (Rate CNP Environmental), and increases in other operations and maintenance expenses, partially offset by 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 $572 million compared to $591 million for the corresponding period in 2012. The decrease in net income was related to a decrease in revenues related to net investment under Rate CNP Environmental and increases in other operations and maintenance expenses, partially offset by a decrease in interest expense.

Retail Revenues

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(38)	(2.6)	$(22)	(0.6)

In the third quarter 2013, retail revenues were $1.44 billion compared to $1.48 billion for the corresponding period in 2012. For year-to-date 2013, retail revenues were $3.80 billion compared to $3.82 billion for the corresponding period in 2012.

48

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	Third Quarter 2013				Year-to-Date 2013
	(in millions)			(% change)	(in millions)			(% change)
Retail – prior year	$	1,476			$	3,822
Estimated change in –
Rates and pricing	(1		)	—	(12		)	(0.3)
Sales growth	—			—	1			—
Weather	(16		)	(1.1)	(4		)	(0.1)
Fuel and other cost recovery	(21		)	(1.5)	(7		)	(0.2)
Retail – current year	$	1,438		(2.6)%	$	3,800		(0.6)%

Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2013 when compared to the corresponding periods in 2012. For the third quarter 2013, the decrease was not material. For year-to-date 2013, the decrease was primarily 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 were not material in the third quarter 2013 and year-to-date 2013 when compared to the corresponding periods in 2012. Industrial KWH energy sales increased 2.7% in the third quarter 2013 and 2.2% for year-to-date 2013 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, forest products, stone, clay, and glass, and chemicals sectors, partially offset by decreases in pipelines and military sectors. Weather-adjusted residential KWH energy sales decreased 0.4% in the third quarter 2013 and 0.9% for year-to-date 2013 as a result of decreased customer usage. Weather-adjusted commercial KWH energy sales increased 0.9% in the third quarter 2013 and 0.3% for year-to-date 2013 as a result of increased customer usage.

Revenues resulting from changes in weather decreased in the third quarter 2013 and year-to-date 2013 due to less favorable weather experienced in Alabama Power's service territory compared to the corresponding periods in 2012. For the third quarter 2013, the resulting decreases were 2.1% and 0.7% for residential and commercial sales revenue, respectively. For year-to-date 2013, residential sales revenue slightly increased 0.5% and commercial sales revenue decreased 1.0%.

Fuel and other cost recovery revenues decreased in the third quarter 2013 and year-to-date 2013 when compared to the corresponding periods in 2012 primarily due to an increase in hydro generation resulting from greater rainfall and an increase in affiliated sales. 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.

Wholesale Revenues – Non-Affiliates

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(16.5)	$(24)	(11.4)

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

In the third quarter 2013, wholesale revenues from sales to non-affiliates were $66 million compared to $79 million

49

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

for the corresponding period in 2012. The decrease was primarily due to a 15.2% decrease in KWH sales and a 1.7% decrease in the price of energy. For year-to-date 2013, wholesale revenues from sales to non-affiliates were $186 million compared to $210 million for the corresponding period in 2012. The decrease was primarily due to a 10.8% decrease in KWH sales.

Wholesale Revenues – Affiliates

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$16	51.6	$112	219.6

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

In the third quarter 2013, wholesale revenues from sales to affiliates were $47 million compared to $31 million for the corresponding period in 2012. The increase was primarily due to an 82.2% increase in KWH sales, partially offset by a 15.2% decrease in the price of energy.

For year-to-date 2013, wholesale revenues from sales to affiliates were $163 million compared to $51 million for the corresponding period in 2012. The increase was due to a 230.3% increase in KWH sales, partially offset by a 2.7% decrease in the price of energy.

Fuel and Purchased Power Expenses

	Third Quarter 2013 vs. Third Quarter 2012				Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(2	)	(0.4)	$	122		10.9
Purchased power – non-affiliates	5			16.1	21			33.3
Purchased power – affiliates	(11		)	(26.8)	(45		)	(30.6)
Total fuel and purchased power expenses	$	(8	)		$	98

In the third quarter 2013, total fuel and purchased power expenses were $533 million compared to $541 million for the corresponding period in 2012. The decrease was primarily due to a $14 million decrease related to the volume of KWHs purchased and a $2 million decrease associated with a decrease in the volume of KWHs generated, partially offset by a $4 million increase in the average cost of purchased power and a $4 million increase in the average cost of fuel.

For year-to-date 2013, total fuel and purchased power expenses were $1.43 billion compared to $1.33 billion for the corresponding period in 2012. The increase was primarily due to a $92 million increase associated with an increase in the volume of KWHs generated, a $34 million increase in the average cost of fuel, and a $27 million increase in the average cost of purchased power, partially offset by a $55 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.

50

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2013	Third Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (billions of KWHs)	18	17	49	44
Total purchased power (billions of KWHs)	1	1	3	5
Sources of generation (percent) —
Coal	57	59	53	52
Nuclear	21	22	22	24
Gas	16	17	16	19
Hydro	6	2	9	5
Cost of fuel, generated (cents per net KWH) —
Coal	3.41	3.40	3.37	3.38
Nuclear	0.84	0.82	0.83	0.79
Gas	3.27	3.17	3.38	2.98
Average cost of fuel, generated (cents per net KWH)(a)	2.80	2.77	2.76	2.63
Average cost of purchased power (cents per net KWH)(b)	6.44	6.04	5.44	4.67

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

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

Fuel

In the third quarter 2013, fuel expense was $467 million compared to $469 million for the corresponding period in 2012. The decrease was primarily due to a 221.1% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall. This decrease was partially offset by a 3.2% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.

For year-to-date 2013, fuel expense was $1.24 billion compared to $1.12 billion for the corresponding period in 2012. The increase was primarily due to a 13.4% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 13.3% increase in KWHs generated by coal. This increase was partially offset by a 118.5% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

Purchased Power – Non-Affiliates

In the third quarter 2013, purchased power expense from non-affiliates was $36 million compared to $31 million for the corresponding period in 2012. The increase was related to a 46.5% increase in the amount of energy purchased, partially offset by a 28.9% decrease in the average cost per KWH.

For year-to-date 2013, purchased power expense from non-affiliates was $84 million compared to $63 million for the corresponding period in 2012. The increase was related to a 75.0% increase in the amount of energy purchased, partially offset by a 30.3% 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 third quarter 2013, purchased power expense from affiliates was $30 million compared to $41 million for the corresponding period in 2012. The decrease was related to a 45.7% decrease in the amount of energy purchased,

51

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

partially offset by a 37.4% increase in the average cost per KWH.

For year-to-date 2013, purchased power expense from affiliates was $102 million compared to $147 million for the corresponding period in 2012. The decrease was related to a 54.2% decrease in the amount of energy purchased, partially offset by a 52.6% 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$9	2.9	$21	2.2

In the third quarter 2013, other operations and maintenance expenses were $316 million compared to $307 million for the corresponding period in 2012. Distribution expenses increased $5 million due to increases in labor and overhead line maintenance expenses. Administrative and general expenses increased $3 million primarily due to increases in pensions and other employee benefit-related expenses, other general expenses, and annual hydroelectric FERC fees.

For year-to-date 2013, other operations and maintenance expenses were $965 million compared to $944 million for the corresponding period in 2012. Distribution expenses increased $10 million due to increases in labor and overhead line maintenance expenses. Nuclear production expenses increased $7 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 on the amortization of nuclear outage expenses. Administrative and general expenses increased $5 million primarily due to employee medical and pension expenses, partially offset by a decrease in affiliated service companies’ expenses.

Depreciation and Amortization

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$9	5.6	$9	1.9

In the third quarter 2013, depreciation and amortization was $170 million compared to $161 million for the corresponding period in 2012. For year-to-date 2013, depreciation and amortization was $487 million compared to $478 million for the corresponding period in 2012. These increases were primarily due to additions to property, plant, and equipment related to distribution and transmission, as well as the amortization of software and an increase in depreciation related to environmental assets, which is offset by revenues associated with Rate CNP Environmental. These increases were offset by 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 of 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.

52

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$3	75.0	$10	76.9

In the third quarter 2013, AFUDC equity was $7 million compared to $4 million for the corresponding period in 2012. The increase was primarily due to an increase in capital expenditures for environmental, steam generating facilities, and transmission.

For year-to-date 2013, AFUDC equity was $23 million compared to $13 million for the corresponding period in 2012. The increase was primarily due to an increase in capital expenditures for environmental, steam generating facilities, nuclear fuel, and transmission.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(8.5)	$(21)	(9.7)

In the third quarter 2013, interest expense, net of amounts capitalized was $65 million compared to $71 million for the corresponding period in 2012.For year-to-date 2013, interest expense, net of amounts capitalized was $196 million compared to $217 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.

Other Income (Expense), Net

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$3	100.0	$7	116.7

In the third quarter 2013, other income (expense), net was less than $1 million compared to $(3) million for the corresponding period in 2012. For year-to-date 2013, other income (expense), net was $1 million compared to $(6) million for the corresponding period in 2012. The changes were primarily due to increases in non-operating income related to gains on sales of non-utility property.

Income Taxes

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(5.4)	$(4)	(1.0)

In the third quarter 2013, income taxes were $174 million compared to $184 million for the corresponding period in 2012. For year-to-date 2013, income taxes were $390 million compared to $394 million for the corresponding period in 2012. These decreases were primarily due to lower pre-tax earnings.

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,

53

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

New Source Review Actions

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – New Source Review Actions" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K for additional information. On September 19, 2013, a three-judge panel of the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment of the U.S. District Court for the Northern District of Alabama in favor of Alabama Power, which was based on the exclusion of the testimony of certain of the EPA's experts, and remanded the case back to the U.S. District Court for the Northern District of Alabama for further proceedings. On October 31, 2013, Alabama Power filed with the U.S. Court of Appeals for the Eleventh Circuit a petition for rehearing. In February 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the 2011 judgment and recusal of the judge in the case involving Alabama Power, which remains pending. The ultimate outcome of these matters 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 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 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 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.

On March 6, 2013, the U.S. Court of Appeals for the Eleventh Circuit upheld the EPA's 2008 approval of the State 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 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 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.

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 and, on October 31, 2013, further extended the deadline until November 20, 2013.

The ultimate impact of these proposed regulations will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of the management and disposal of coal combustion byproducts. On September 30, 2013, the U.S. District Court for the District of Columbia issued an order granting partial summary judgment to the environmental groups and other parties, ruling that the EPA has a statutory obligation to review and revise, as necessary, the federal solid waste regulations applicable to coal combustion byproducts and, on October 29, 2013, directed the EPA to provide a proposed schedule to complete the

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

rulemaking. The impact of this order depends on further judicial and regulatory action and, therefore, 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 – 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.

On September 20, 2013, the EPA proposed revised regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel-fired steam electric generating units. A Presidential memorandum issued on June 25, 2013 also directed the EPA 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 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 market-based contracts. 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. On August 13, 2013, the Alabama PSC voted to issue a report on Rate RSE that found that Alabama Power's Rate RSE mechanism continues to be just and reasonable to customers and Alabama Power, but recommended Alabama Power modify Rate RSE as follows:

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ALABAMA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

• Eliminate the provision of Rate RSE establishing an allowed range of ROE, which is currently 13.0% to 14.5%, with an adjusting point of 13.75%.

• Eliminate the provision of Rate RSE limiting Alabama Power's capital structure to an allowed equity ratio of 45%.

• Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the current Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

• Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

Substantially all other provisions of Rate RSE would remain unchanged.

On August 21, 2013, Alabama Power filed its consent to these recommendations with the Alabama PSC. The changes are effective for calendar year 2014.

Rate CNP

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – 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 September 30, 2013 was $22 million as compared to $9 million at December 31, 2012. This under recovered balance at September 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 September 30, 2013 was $12 million as compared to $21 million at December 31, 2012. This under recovered balance at September 30, 2013 consists of $4 million in under recovered regulatory clause revenues and $8 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.

On August 13, 2013, the Alabama PSC approved Alabama Power's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets currently being recovered through Rate RSE. The revenue impact as a result of this revision is estimated to be $50 million in 2014; however, this petition was 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. Any unrecovered amounts associated with 2014 environmental compliance costs will be reflected in the 2015 Rate CNP Environmental filing. 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.

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 additional information regarding Alabama Power's energy cost recovery. Alabama Power's over recovered fuel costs at September 30, 2013 totaled $43 million as compared to an under recovered balance of $4 million at December 31, 2012. The over recovered fuel costs at September 30, 2013 are included in other regulatory liabilities, current and the under

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 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 13, 2013, the Alabama PSC approved Alabama Power's petition requesting authorization to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures to be deferred and amortized are estimated to total approximately $70 million. This petition was 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.

Nuclear Decommissioning

See Note 1 to the financial statements of Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Nuclear Decommissioning" and "Asset Retirement Obligations" herein for additional information. In September 2013, Alabama Power received a 2013 decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in the asset retirement obligation liability of approximately $102 million.

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.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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

Net cash provided from operating activities totaled $1.5 billion for the first nine months of 2013, an increase of $384 million as compared to the first nine months of 2012. The increase in net cash provided from operating activities was primarily due to a decrease in fossil fuel stock, the timing of income tax payments and refunds, and an increase in accounts payable as compared to the first nine months of 2012. Net cash used for investing activities totaled $761 million for the first nine months of 2013 primarily due to gross property additions related to distribution, steam generation, and transmission equipment. Net cash used for financing activities totaled $409 million for the first nine 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.

Significant balance sheet changes for the first nine months of 2013 include increases of $457 million in property, plant, and equipment, primarily due to additions to distribution, steam, and transmission facilities, $299 million in cash and cash equivalents due to an increase in temporary cash investments, $192 million in accumulated deferred income taxes due to accelerated tax deductions associated with property, plant, and equipment, and $131 million in asset retirement obligations due to updated nuclear decommissioning cost estimates, and a decrease of $173 million in fossil fuel stock, at average cost, primarily 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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

information. Approximately $250 million will be required through September 30, 2014 to fund maturities of long-term debt.

Alabama Power’s updated construction program for 2014 and 2015 includes anticipated costs for compliance with the MATS rule but does not include potential incremental compliance cost estimates for proposed water and coal combustion byproducts rules. Alabama Power's updated base level construction program and the potential incremental environmental compliance estimates for the proposed water and coal combustion byproducts rules (based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) for 2014 and 2015 are as follows:

	2014		2015
Construction program:	(in millions)
Base capital	$	1,230	$	1,210
Existing environmental statutes and regulations, including MATS rule	501		443
Total construction program base level capital investment	$	1,731	$	1,653
Potential incremental environmental compliance investment:
Proposed water and coal combustion byproducts rules	$	14	$	127

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

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

Sources of Capital

Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past. Alabama Power has primarily utilized funds from operating cash flows, short-term debt, security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon 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.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, 2013, Alabama Power had approximately $436 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2013 were as follows:

Expires(a)												Executable Term Loans				Due Within One Year
2013		2014		2015		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)								(in millions)				(in millions)				(in millions)
$	1	$	268	$	35	$	1,000	$	1,304	$	1,304	$	53	$	—	$	53	$	146

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

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

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 September 30, 2013 was approximately $793 million. In addition, at September 30, 2013, Alabama Power had $200 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months. In addition, Alabama Power has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs.

As reflected in the table above, during the first nine 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 September 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	$—	—%	$2	0.2%	$53

(a) Average and maximum amounts are based upon daily balances during the three-month period ended September 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 September 30, 2013, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $290 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 third 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 third 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 nine months ended September 30, 2013 were as follows:

	Third Quarter 2013 Changes	Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$(11)	$(13)
Contracts realized or settled	4	10
Current period changes(a)	(5)	(9)
Contracts outstanding at the end of the period, assets (liabilities), net	$(12)	$(12)

(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

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 nine months ended September 30, 2013 were as follows:

	Third Quarter 2013 Changes	Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$(1)	$2
Natural gas options	—	(1)
Total changes	$(1)	$1

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

	September 30, 2013	June 30, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	62	60	45
Commodity – Natural gas options	6	8	12
Total hedge volume	68	68	57

The weighted average swap contract cost above market prices was approximately $0.19 per mmBtu as of September 30, 2013, $0.18 per mmBtu as of June 30, 2013 and $0.30 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 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 nine months ended September 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 September 30, 2013 were as follows:

	September 30, 2013 Fair Value Measurements
	Total Fair Value			Maturity
				Year 1			Years 2&3
	(in millions)
Level 1	$	—		$	—		$	—
Level 2	(12		)	(7		)	(5		)
Level 3	—			—			—
Fair value of contracts outstanding at end of period	$	(12	)	$	(7	)	$	(5	)

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

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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 nine months ended September 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 September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	2,314		$	2,335		$	5,922		$	5,786
Wholesale revenues, non-affiliates	77			73			212			214
Wholesale revenues, affiliates	3			5			14			14
Other revenues	90			85			260			249
Total operating revenues	2,484			2,498			6,408			6,263
Operating Expenses:
Fuel	691			630			1,767			1,642
Purchased power, non-affiliates	64			79			175			266
Purchased power, affiliates	152			181			503			469
Other operations and maintenance	402			398			1,230			1,243
Depreciation and amortization	201			186			605			559
Taxes other than income taxes	102			100			292			281
Total operating expenses	1,612			1,574			4,572			4,460
Operating Income	872			924			1,836			1,803
Other Income and (Expense):
Allowance for equity funds used during construction	11			15			24			41
Interest expense, net of amounts capitalized	(92		)	(95		)	(279		)	(276		)
Other income (expense), net	(1		)	(1		)	(2		)	(10		)
Total other income and (expense)	(82		)	(81		)	(257		)	(245		)
Earnings Before Income Taxes	790			843			1,579			1,558
Income taxes	299			314			600			558
Net Income	491			529			979			1,000
Dividends on Preferred and Preference Stock	4			4			13			13
Net Income After Dividends on Preferred and Preference Stock	$	487		$	525		$	966		$	987

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)				(in millions)
Net Income	$	491	$	529	$	979	$	1,000
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1 and $1, respectively	1		1		2		2
Total other comprehensive income (loss)	1		1		2		2
Comprehensive Income	$	492	$	530	$	981	$	1,002

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

66

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2013			2012
	(in millions)
Operating Activities:
Net income	$	979		$	1,000
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	734			684
Deferred income taxes	354			243
Allowance for equity funds used during construction	(24		)	(41		)
Retail fuel cost over recovery—long-term	(123		)	118
Deferred expenses	(34		)	(20		)
Pension, postretirement, and other employee benefits	58			23
Other, net	28			—
Changes in certain current assets and liabilities —
-Receivables	(191		)	(23		)
-Fossil fuel stock	213			(126		)
-Prepaid income taxes	11			40
-Other current assets	38			4
-Accounts payable	(5		)	(57		)
-Accrued taxes	131			40
-Accrued compensation	(53		)	(43		)
-Retail fuel cost over recovery—short-term	7			81
-Other current liabilities	5			48
Net cash provided from operating activities	2,128			1,971
Investing Activities:
Property additions	(1,165		)	(1,291		)
Investment of restricted cash	(89		)	(234		)
Distribution of restricted cash	89			234
Nuclear decommissioning trust fund purchases	(582		)	(630		)
Nuclear decommissioning trust fund sales	580			628
Cost of removal, net of salvage	(42		)	(42		)
Change in construction payables, net of joint owner portion	(28		)	(141		)
Other investing activities	(14		)	9
Net cash used for investing activities	(1,251		)	(1,467		)
Financing Activities:
Increase (decrease) in notes payable, net	211			(513		)
Proceeds —
Capital contributions from parent company	30			29
Pollution control revenue bonds issuances	89			234
Senior notes issuances	850			1,900
Redemptions —
Pollution control revenue bonds	(89		)	(234		)
Senior notes	(1,250		)	(550		)
Other long-term debt	—			(250		)
Payment of preferred and preference stock dividends	(13		)	(13		)
Payment of common stock dividends	(680		)	(681		)
Other financing activities	(17		)	(14		)
Net cash used for financing activities	(869		)	(92		)
Net Change in Cash and Cash Equivalents	8			412
Cash and Cash Equivalents at Beginning of Period	45			13
Cash and Cash Equivalents at End of Period	$	53		$	425
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $10 and $17 capitalized for 2013 and 2012, respectively)	$	247		$	237
Income taxes, net	109			186
Noncash transactions—accrued property additions at end of period	230			253

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

67

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2013			At December 31, 2012
	(in millions)
Current Assets:
Cash and cash equivalents	$	53		$	45
Receivables —
Customer accounts receivable	657			484
Unbilled revenues	239			217
Joint owner accounts receivable	54			51
Other accounts and notes receivable	81			68
Affiliated companies	23			23
Accumulated provision for uncollectible accounts	(8		)	(6		)
Fossil fuel stock, at average cost	779			992
Materials and supplies, at average cost	422			452
Vacation pay	86			85
Prepaid income taxes	114			164
Other regulatory assets, current	43			72
Other current assets	75			104
Total current assets	2,618			2,751
Property, Plant, and Equipment:
In service	29,762			29,244
Less accumulated provision for depreciation	10,842			10,431
Plant in service, net of depreciation	18,920			18,813
Other utility plant, net	252			263
Nuclear fuel, at amortized cost	475			497
Construction work in progress	3,399			2,893
Total property, plant, and equipment	23,046			22,466
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	46			45
Nuclear decommissioning trusts, at fair value	724			698
Miscellaneous property and investments	43			44
Total other property and investments	813			787
Deferred Charges and Other Assets:
Deferred charges related to income taxes	713			733
Other regulatory assets, deferred	1,773			1,798
Other deferred charges and assets	244			268
Total deferred charges and other assets	2,730			2,799
Total Assets	$	29,207		$	28,803

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

68

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2013			At December 31, 2012
	(in millions)
Current Liabilities:
Securities due within one year	$	530		$	1,680
Notes payable	211			2
Accounts payable —
Affiliated	428			417
Other	428			436
Customer deposits	243			237
Accrued taxes —
Accrued income taxes	161			6
Other accrued taxes	283			260
Accrued interest	113			100
Accrued vacation pay	60			61
Accrued compensation	64			113
Liabilities from risk management activities	19			30
Other regulatory liabilities, current	18			73
Over recovered regulatory clause revenues, current	81			107
Other current liabilities	109			146
Total current liabilities	2,748			3,668
Long-term Debt	8,739			7,994
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,139			4,861
Deferred credits related to income taxes	112			115
Accumulated deferred investment tax credits	205			208
Employee benefit obligations	976			950
Asset retirement obligations	1,182			1,097
Other cost of removal obligations	64			63
Other deferred credits and liabilities	177			308
Total deferred credits and other liabilities	7,855			7,602
Total Liabilities	19,342			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	5,625			5,585
Retained earnings	3,581			3,297
Accumulated other comprehensive loss	(5		)	(7		)
Total common stockholder's equity	9,599			9,273
Total Liabilities and Stockholder's Equity	$	29,207		$	28,803

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

69

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2013 vs. THIRD 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 has negatively impacted Georgia Power's 2013 actual performance on its peak season equivalent forced outage rate, one of its key performance indicators, as compared to the target.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(38)	(7.2)	$(21)	(2.1)

Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2013 was $487 million compared to $525 million for the corresponding period in 2012. The decrease was primarily due to less favorable weather in the third quarter 2013 as compared to the corresponding period in 2012 and an increase in depreciation and amortization, partially offset by an increase related to retail revenue rate effects and lower income taxes.

Georgia Power's net income after dividends on preferred and preference stock for year-to-date 2013 was $966 million compared to $987 million for the corresponding period in 2012. The decrease was primarily due to less favorable weather year-to-date 2013 as compared to the corresponding period in 2012, higher income taxes, and an increase in depreciation and amortization, partially offset by an increase related to retail revenue rate effects and lower non-fuel operations and maintenance expenses.

70

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(21)	(0.9)	$136	2.4

In the third quarter 2013, retail revenues were $2.31 billion compared to $2.34 billion for the corresponding period in 2012. For year-to-date 2013, retail revenues were $5.92 billion compared to $5.79 billion for the corresponding period in 2012.

Details of the changes in retail revenues were as follows:

	Third Quarter 2013				Year-to-Date 2013
	(in millions)			(% change)	(in millions)			(% change)
Retail – prior year	$	2,335			$	5,786
Estimated change in –
Rates and pricing	30			1.3	136			2.4
Sales growth (decline)	5			0.2	(19		)	(0.3)
Weather	(72		)	(3.1)	(75		)	(1.3)
Fuel cost recovery	16			0.7	94			1.6
Retail – current year	$	2,314		(0.9)%	$	5,922		2.4%

Revenues associated with changes in rates and pricing increased in the third quarter 2013 when compared to the corresponding period in 2012 primarily due to base tariff increases effective January 1, 2013, as approved by the Georgia PSC, related to placing a new generating unit at Plant McDonough-Atkinson in service and the financing costs related to the construction of Plant Vogtle Units 3 and 4, partially offset by lower contributions from market-driven rates from commercial and industrial customers.

Revenues associated with changes in rates and pricing increased year-to-date 2013 when compared to the corresponding period 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 and the financing costs related to the construction of Plant Vogtle Units 3 and 4, as well as higher contributions from market-driven rates from commercial and industrial customers.

Revenues attributable to changes in sales increased in the third quarter and decreased year-to-date 2013 when compared to the corresponding periods in 2012. Weather-adjusted residential KWH sales decreased 0.6%, while weather-adjusted commercial and industrial KWH sales increased 1.3% and 2.6%, respectively, in the third quarter 2013 when compared to the corresponding period in 2012. For year-to-date 2013, weather-adjusted residential, commercial, and industrial KWH sales decreased 0.5%, 0.2%, and 0.2%, respectively, when compared to the corresponding period in 2012. Residential usage continues to be impacted by economic uncertainty, modest economic growth, and energy efficiency efforts. In the third quarter 2013, increased demand in the office space and healthcare sectors was the main contributor to the increase in weather-adjusted commercial KWH sales and increased demand in the paper sector was the main contributor to the increase in weather-adjusted industrial KWH sales.

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 1.1%, weather-adjusted commercial KWH sales increased 0.3%, and weather-adjusted industrial KWH sales decreased 0.3% when compared to the corresponding period in 2012.

71

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $16 million and $94 million in the third 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.

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

	Third Quarter 2013 vs. Third Quarter 2012					Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	61		9.7		$	125		7.6
Purchased power – non-affiliates	(15		)	(19.0	)	(91		)	(34.2	)
Purchased power – affiliates	(29		)	(16.0	)	34			7.2
Total fuel and purchased power expenses	$	17				$	68

In the third quarter 2013, total fuel and purchased power expenses were $907 million compared to $890 million in the corresponding period in 2012. The increase in the third quarter 2013 was primarily due to a $77 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $60 million decrease primarily in the volume of KWHs purchased as a result of lower customer demand.

For year-to-date 2013, total fuel and purchased power expenses were $2.45 billion compared to $2.38 billion for the corresponding period in 2012. The increase in year-to-date 2013 was primarily due to a $230 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $162 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.

72

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2013	Third Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (billions of KWHs)	19	17	50	46
Total purchased power (billions of KWHs)	5	8	17	22
Sources of generation (percent) —
Coal	42	45	35	44
Nuclear	22	23	23	26
Gas	34	32	39	29
Hydro	2	—	3	1
Cost of fuel, generated (cents per net KWH) —
Coal	4.89	4.56	4.99	4.74
Nuclear	0.91	0.89	0.91	0.86
Gas	3.34	3.00	3.34	2.94
Average cost of fuel, generated (cents per net KWH)	3.47	3.21	3.37	3.19
Average cost of purchased power (cents per net KWH)(a)	5.00	4.45	4.80	4.18

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

Fuel

In the third quarter 2013, fuel expense was $691 million compared to $630 million in the corresponding period in 2012. The increase was primarily due to a 9.0% increase in the volume of KWHs generated as a result of higher prices for purchased power and an 8.1% increase in the average cost of fuel per KWH generated for all types of generation, partially offset by a 709.7% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

For year-to-date 2013, fuel expense was $1.77 billion compared to $1.64 billion in the corresponding period in 2012. The increase was primarily due to a 7.2% increase in the volume of KWHs generated as a result of higher prices for purchased power and a 5.6% increase in the average cost of fuel per KWH generated for all types of generation, partially offset by a 242.3% increase in the volume of KWHs generated by hydro facilities resulting from greater rainfall.

Purchased Power – Non-Affiliates

In the third quarter 2013, purchased power expense from non-affiliates was $64 million compared to $79 million in the corresponding period in 2012. The decrease was due to a 43.2% 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 22.0% 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 $175 million compared to $266 million in the corresponding period in 2012. The decrease was due to a 56.5% 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 42.6% in the average cost per KWH purchased primarily due to higher fuel prices.

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

73

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Affiliates

In the third quarter 2013, purchased power expense from affiliates was $152 million compared to $181 million in the corresponding period in 2012. The decrease was due to a 29.7% decrease in the volume of KWHs purchased, as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources, partially offset by an 11.2% increase in the average cost per KWH purchased, reflecting higher fuel prices.

For year-to-date 2013, purchased power expense from affiliates was $503 million compared to $469 million in the corresponding period in 2012. The increase was due to a 15.1% increase in the average cost per KWH purchased, reflecting higher fuel prices, partially offset by a 14.4% 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$4	1.0	$(13)	(1.0)

In the third quarter 2013, other operations and maintenance expenses were $402 million compared to $398 million in the corresponding period in 2012. The increase was not material.

For year-to-date 2013, other operations and maintenance expenses were $1.23 billion compared to $1.24 billion in the corresponding period in 2012. The decrease was primarily due to decreases of $31 million in fossil generating expenses and $5 million in transmission and distribution line maintenance due to cost containment and outage timing to offset the effect of economic conditions and less favorable weather in the second and third quarters 2013, partially offset by an increase of $23 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$15	8.1	$46	8.2

In the third quarter 2013, depreciation and amortization was $201 million compared to $186 million in the corresponding period in 2012. The increase was primarily due to an increase of $15 million in depreciation on additional plant in service primarily due to the completion of Plant McDonough-Atkinson Unit 6 in October 2012 and depreciation and amortization resulting from certain unit retirement decisions (with respect to the portion of such units dedicated to wholesale service).

For year-to-date 2013, depreciation and amortization was $605 million compared to $559 million in the corresponding period in 2012. The increase was primarily due to an increase of $51 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 depreciation and amortization resulting from certain unit retirement decisions (with respect to the portion of such units dedicated to wholesale service). The increase was partially offset by a net reduction in amortization primarily related to 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.

74

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$2	2.0	$11	3.9

In the third quarter 2013, taxes other than income taxes were $102 million compared to $100 million in the corresponding period in 2012. The increase was not material.

For year-to-date 2013, taxes other than income taxes were $292 million compared to $281 million in the corresponding period in 2012. The increase was primarily due to a $9 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(26.7)	$(17)	(41.5)

In the third quarter 2013, AFUDC equity was $11 million compared to $15 million in the corresponding period in 2012. For year-to-date 2013, AFUDC equity was $24 million compared to $41 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.

Income Taxes

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(15)	(4.8)	$42	7.5

In the third quarter 2013, income taxes were $299 million compared to $314 million in the corresponding period in 2012. The decrease was due to lower pre-tax earnings, partially offset by a decrease in non-taxable AFUDC equity.

For year-to-date 2013, income taxes were $600 million compared to $558 million in the corresponding period in 2012. The increase was primarily due to a decrease in state income tax credits, higher pre-tax earnings, 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.

75

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

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

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 case is now concluded.

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 additional 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 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 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 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

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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 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.

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 and, on October 31, 2013, further extended the deadline until November 20, 2013.

The ultimate impact of these proposed regulations will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of the management and disposal of coal combustion byproducts. On September 30, 2013, the U.S. District Court for the District of Columbia issued an order granting partial summary judgment to the environmental groups and other parties, ruling that the EPA has a statutory obligation to review and revise, as necessary, the federal solid waste regulations applicable to coal combustion byproducts and, on October 29, 2013, directed the EPA to provide a proposed schedule to complete the rulemaking. The impact of this order depends on further judicial and regulatory action and, therefore, 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 – 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.

On September 20, 2013, the EPA proposed revised regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel-fired steam electric generating units. A Presidential memorandum issued on June 25, 2013 also directed the EPA 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 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

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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 market-based contracts. 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 September 30, 2013, Georgia Power's fuel cost over recovery balance totaled $114 million and is included in current liabilities and other deferred credits and 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.

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 was 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.

Hearings on Georgia Power’s testimony were held in October 2013. In testimony filed on October 18, 2013 and October 22, 2013, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period and a 10.0% ROE that would result in excess revenues of $165 million. However, the Georgia PSC Staff also

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proposed no change to Georgia Power’s current retail base rates through 2014. The excess earnings in 2014 would be used to reduce rate increases in 2015 and 2016. The Georgia PSC Staff further proposed reducing the allowed ROE range to 50 basis points above and below the authorized ROE with one-third of any earnings above the range used to reduce future ECCR tariff increases and the remaining two-thirds applied to rate reductions. Georgia Power disagrees with the Georgia PSC Staff's positions. Hearings on the Georgia PSC Staff and intervenor testimony and Georgia Power's rebuttal hearings will be held in November 2013.

The Georgia PSC is scheduled to issue a final order in this matter in 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 September 30, 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 IRP in order to comply with the State of Georgia's Multi-Pollutant Rule.

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, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division on September 10, 2013 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. See Note 1 to the financial statements of Georgia Power under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the fuel switch at SEGCO's generating units.

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

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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 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.

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, and subsequently has requested Georgia PSC approval. During 2013, Georgia Power has executed four PPAs to purchase a total of 169 MWs of biomass capacity and energy from four facilities in Georgia that will commence in 2015 and end in 2035. On May 21, 2013, the Georgia PSC approved two of the biomass PPAs. The two wind PPAs and the two Georgia PSC-approved biomass PPAs result in contractual obligations of approximately $13 million in 2015, $47 million in 2016, $49 million in 2017, and $1.29 billion thereafter. If approved by the Georgia PSC, the additional biomass PPAs will result in contractual obligations of approximately $1 million in 2015, $11 million in 2016, $12 million in 2017, and $249 million thereafter. The four biomass PPAs are contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.

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. On November 1, 2013, Georgia Power filed to increase the NCCR tariff by approximately $65 million effective January 1, 2014. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2013, approximately $41 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. The deadline for any further appeals expired without the petitioners seeking review.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, Georgia Power's eighth VCM report requested

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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.

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 (February 2014 VCM report). The stipulation was approved by the Georgia PSC on September 3, 2013. As required by the stipulation, Georgia Power filed an abbreviated status update with the Georgia PSC on September 3, 2013, which reflected approximately $2.4 billion of total construction capital costs incurred through June 30, 2013. After the February 2014 VCM report, Georgia Power expects to resume filing semi-annual VCM reports in August 2014. On October 15, 2013, the Georgia PSC voted to approve Georgia Power's eighth VCM report, reflecting construction capital costs incurred, which through December 31, 2012 totaled approximately $2.2 billion.

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. On August 30, 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit on September 27, 2013. While litigation has commenced and Georgia Power intends to vigorously defend its positions, Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

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

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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.

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 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 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 and June 6, 2013, the NRC issued orders relating to hardened vents for certain classes of containment structures, including the ones in use at Plant Hatch. Georgia Power is continuing to analyze the impact of these orders. The ultimate outcome of this matter cannot be determined at this time; however, management does not currently anticipate that the compliance costs associated with these orders would have a material impact on Georgia Power'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 4, 2013. Plant Bowen Unit 2 (approximately 700 MWs) remains offline pending completion of the 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

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

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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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at September 30, 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 $2.13 billion for the first nine months of 2013 compared to $1.97 billion for the corresponding period in 2012. The increase was primarily due to higher retail operating revenues, lower fuel inventory additions, and lower income tax payments in 2013, partially offset by fuel cost recovery. Net cash used for investing activities totaled $1.25 billion for the first nine months of 2013 compared to $1.47 billion used in the corresponding period in 2012. The decrease was primarily due to lower cash payments for construction expenditures in 2013. Net cash used for financing activities totaled $869 million for the first nine months of 2013 compared to $92 million in the corresponding period in 2012. The increase in cash used for financing activities 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 nine months of 2013 include increases of $580 million in total property, plant, and equipment and $178 million in accrued taxes and decreases of $213 million in fossil fuel stock and $196 million in total 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 $635 million will be required through September 30, 2014 to fund maturities and announced redemptions 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.

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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 – 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, 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. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. The conditional commitment will expire on December 31, 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 September 30, 2013, Georgia Power had approximately $53 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2013 were as follows:

Expires(a)
	2016		2018		Total		Unused
(in millions)					(in millions)
	$	150	$	1,600	$	1,750	$	1,736

(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 September 30, 2013 was approximately $862 million. In addition, at September 30, 2013, Georgia Power had $242 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.

As reflected in the table above, during the first nine 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.

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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.

Details of short-term borrowings were as follows:

	Short-term Debt at September 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	$	211	0.2%	$	97	0.2%	$	270

(a) Average and maximum amounts are based upon daily balances during the three-month period ended September 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 September 30, 2013 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	88
Below BBB- and/or Baa3	1,339

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 third 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, 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.

85

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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 third 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 nine months ended September 30, 2013 were as follows:

	Third Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(29	)	$	(34	)
Contracts realized or settled	7			22
Current period changes(a)	(5		)	(15		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(27	)	$	(27	)

(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 nine months ended September 30, 2013 were as follows:

	Third Quarter 2013 Changes		Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$	1	$	5
Natural gas options	1		2
Total changes	$	2	$	7

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

	September 30, 2013	June 30, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	9	10	12
Commodity – Natural gas options	58	68	93
Total hedge volume	67	78	105

The weighted average swap contract cost above market prices was approximately $0.92 per mmBtu as of September 30, 2013, $0.94 per mmBtu as of June 30, 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.

86

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 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 September 30, 2013 were as follows:

	September 30, 2013 Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3
				(in millions)
Level 1	$	—		$	—		$	—
Level 2	(27		)	(18		)	(9		)
Level 3	—			—			—
Fair value of contracts outstanding at end of period	$	(27	)	$	(18	)	$	(9	)

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 these sales 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 (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 1997.

In August 2013, Georgia Power issued $200 million aggregate principal amount of Series 2013C Floating Rate Senior Notes due August 15, 2016. The proceeds were used to repay at maturity a portion of $100 million aggregate principal amount outstanding of Georgia Power's Series Q 4.90% Senior Notes due September 15, 2013 and a

87

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

portion of $500 million aggregate principal amount outstanding of Georgia Power's Series 2010D 1.30% Senior Notes due September 15, 2013.

In August 2013, the Development Authority of Bartow County issued $71.7 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013 due August 1, 2043 for the benefit of Georgia Power. The proceeds were used to redeem, in September 2013, $24.9 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1996 and $46.8 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1998.

Subsequent to September 30, 2013, Georgia Power announced the redemption in November 2013 of $100 million aggregate principal amount of its Series 2008C 8.20% Senior Notes due November 1, 2048 and reclassified the outstanding principal balance to securities due within one year at September 30, 2013.

Also subsequent to September 30, 2013, Georgia Power announced the redemptions in November 2013 of $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Third Series 1994 and $49.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1997, which were issued for the benefit of Georgia Power.

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.

88

GULF POWER COMPANY

89

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	335,916		$	347,435		$	901,343		$	880,833
Wholesale revenues, non-affiliates	29,431			27,462			82,533			83,309
Wholesale revenues, affiliates	16,701			30,113			65,206			95,179
Other revenues	17,313			16,809			47,726			48,951
Total operating revenues	399,361			421,819			1,096,808			1,108,272
Operating Expenses:
Fuel	136,216			160,749			397,409			423,057
Purchased power, non-affiliates	17,180			18,380			41,369			41,690
Purchased power, affiliates	15,829			10,785			30,075			18,508
Other operations and maintenance	76,964			74,781			232,472			229,790
Depreciation and amortization	37,345			36,169			111,479			104,649
Taxes other than income taxes	28,051			27,142			75,437			76,202
Total operating expenses	311,585			328,006			888,241			893,896
Operating Income	87,776			93,813			208,567			214,376
Other Income and (Expense):
Allowance for equity funds used during construction	1,663			1,015			4,318			3,988
Interest expense, net of amounts capitalized	(13,988		)	(14,637		)	(42,650		)	(45,703		)
Other income (expense), net	(337		)	(557		)	(2,704		)	(454		)
Total other income and (expense)	(12,662		)	(14,179		)	(41,036		)	(42,169		)
Earnings Before Income Taxes	75,114			79,634			167,531			172,207
Income taxes	28,109			30,329			62,950			64,172
Net Income	47,005			49,305			104,581			108,035
Dividends on Preference Stock	2,251			1,551			5,453			4,652
Net Income After Dividends on Preference Stock	$	44,754		$	47,754		$	99,128		$	103,383

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Net Income	$	47,005	$	49,305	$	104,581	$	108,035
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $58, $90, $238 and $270, respectively	93		143		379		429
Total other comprehensive income (loss)	93		143		379		429
Comprehensive Income	$	47,098	$	49,448	$	104,960	$	108,464

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2013			2012
	(in thousands)
Operating Activities:
Net income	$	104,581		$	108,035
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	116,626			109,132
Deferred income taxes	55,911			132,367
Allowance for equity funds used during construction	(4,318		)	(3,988		)
Pension, postretirement, and other employee benefits	9,279			4,361
Stock based compensation expense	1,389			1,346
Other, net	2,509			3,839
Changes in certain current assets and liabilities —
-Receivables	(49,690		)	(10,995		)
-Prepayments	2,568			3,066
-Fossil fuel stock	24,475			14,055
-Materials and supplies	(2,683		)	(3,859		)
-Prepaid income taxes	23,515			28,108
-Accounts payable	(9,132		)	(453		)
-Accrued taxes	20,648			18,566
-Accrued compensation	(5,974		)	(4,263		)
-Over recovered regulatory clause revenues	(17,092		)	7,387
-Other current liabilities	5,258			(925		)
Net cash provided from operating activities	277,870			405,779
Investing Activities:
Property additions	(205,161		)	(239,705		)
Cost of removal, net of salvage	(12,563		)	(20,931		)
Change in construction payables	6,752			(542		)
Payments pursuant to long-term service agreements	(3,843		)	(6,184		)
Other investing activities	306			627
Net cash used for investing activities	(214,509		)	(266,735		)
Financing Activities:
Decrease in notes payable, net	(65,077		)	(91,699		)
Proceeds —
Common stock issued to parent	40,000			40,000
Capital contributions from parent company	1,936			1,569
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	(90,000		)	(91,363		)
Payment of preference stock dividends	(4,753		)	(4,652		)
Payment of common stock dividends	(86,550		)	(86,850		)
Other financing activities	(3,209		)	(468		)
Net cash used for financing activities	(67,653		)	(133,463		)
Net Change in Cash and Cash Equivalents	(4,292		)	5,581
Cash and Cash Equivalents at Beginning of Period	32,167			17,328
Cash and Cash Equivalents at End of Period	$	27,875		$	22,909
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $2,291 and $1,846 capitalized for 2013 and 2012, respectively)	$	33,433		$	38,806
Income taxes, net	(17,064		)	(101,825		)
Noncash transactions — accrued property additions at end of period	30,846			25,115

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2013			At December 31, 2012
	(in thousands)
Current Assets:
Cash and cash equivalents	$	27,875		$	32,167
Receivables —
Customer accounts receivable	83,132			58,449
Unbilled revenues	61,322			53,363
Under recovered regulatory clause revenues	33,759			6,138
Other accounts and notes receivable	9,613			11,859
Affiliated companies	783			13,624
Accumulated provision for uncollectible accounts	(1,172		)	(1,490		)
Fossil fuel stock, at average cost	130,044			153,710
Materials and supplies, at average cost	56,048			53,365
Other regulatory assets, current	26,465			30,576
Prepaid expenses	18,881			62,877
Other current assets	2,271			2,690
Total current assets	449,021			477,328
Property, Plant, and Equipment:
In service	4,323,305			4,260,844
Less accumulated provision for depreciation	1,196,883			1,168,055
Plant in service, net of depreciation	3,126,422			3,092,789
Construction work in progress	247,290			136,062
Total property, plant, and equipment	3,373,712			3,228,851
Other Property and Investments	15,442			15,737
Deferred Charges and Other Assets:
Deferred charges related to income taxes	51,715			50,139
Other regulatory assets, deferred	386,960			372,294
Other deferred charges and assets	36,563			33,053
Total deferred charges and other assets	475,238			455,486
Total Assets	$	4,313,413		$	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 September 30, 2013			At December 31, 2012
	(in thousands)
Current Liabilities:
Securities due within one year	$	—		$	60,000
Notes payable	58,693			127,002
Accounts payable —
Affiliated	81,588			66,161
Other	40,711			54,551
Customer deposits	34,783			34,749
Accrued taxes —
Accrued income taxes	21,136			45
Other accrued taxes	27,705			7,036
Accrued interest	17,742			12,364
Accrued compensation	8,991			14,966
Other regulatory liabilities, current	14,316			25,887
Liabilities from risk management activities	13,130			16,529
Other current liabilities	21,888			19,930
Total current liabilities	340,683			439,220
Long-term Debt	1,246,022			1,185,870
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	689,840			648,952
Accumulated deferred investment tax credits	4,393			5,408
Employee benefit obligations	128,631			126,871
Other cost of removal obligations	224,977			213,413
Other regulatory liabilities, deferred	47,090			47,863
Deferred capacity expense	169,504			137,568
Other deferred credits and liabilities	78,705			93,497
Total deferred credits and other liabilities	1,343,140			1,273,572
Total Liabilities	2,929,845			2,898,662
Preference Stock	146,535			97,998
Common Stockholder's Equity:
Common stock, without par value—
Authorized — 20,000,000 shares
Outstanding — September 30, 2013: 4,942,717 shares
— December 31, 2012: 4,542,717 shares	433,060			393,060
Paid-in capital	551,232			547,798
Retained earnings	253,943			241,465
Accumulated other comprehensive loss	(1,202		)	(1,581		)
Total common stockholder's equity	1,237,033			1,180,742
Total Liabilities and Stockholder's Equity	$	4,313,413		$	4,177,402

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

93

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2013 vs. THIRD 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(3.0)	(6.3)	$(4.3)	(4.1)

Gulf Power's net income after dividends on preference stock for the third quarter 2013 was $44.7 million compared to $47.7 million for the corresponding period in 2012. The decrease was primarily due to lower retail revenues and increases in operations and maintenance expenses.

Gulf Power's net income after dividends on preference stock for year-to-date 2013 was $99.1 million compared to $103.4 million for the corresponding period in 2012. The decrease was primarily due to an increase in depreciation, partially offset by a decrease in interest expense, net of amounts capitalized.

Retail Revenues

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(11.5)	(3.3)	$20.5	2.3

In the third quarter 2013, retail revenues were $335.9 million compared to $347.4 million for the corresponding period in 2012. For year-to-date 2013,retail revenues were $901.3 million compared to $880.8 million for the corresponding period in 2012.

94

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	Third Quarter 2013				Year-to-Date 2013
	(in millions)			(% change)	(in millions)			(% change)
Retail – prior year	$	347.4			$	880.8
Estimated change in –
Rates and pricing	(2.5		)	(0.7)	3.7			0.4
Sales growth (decline)	0.2			0.1	(1.4		)	(0.1)
Weather	(1.3		)	(0.4)	(2.4		)	(0.3)
Fuel and other cost recovery	(7.9		)	(2.3)	20.6			2.3
Retail – current year	$	335.9		(3.3)%	$	901.3		2.3%

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 decreased in the third quarter 2013 when compared to the corresponding period in 2012. The decrease was primarily due to lower revenues associated with decreases in environmental and energy conservation cost recovery clause rates.

Revenues associated with changes in rates and pricing increased year-to-date 2013 when compared to the corresponding period in 2012. The increase was primarily due to the retail base rate increase effective April 2012, partially offset by lower revenues associated with decreases in environmental and energy conservation cost recovery clause rates.

Revenues attributable to changes in sales increased in the third quarter 2013 when compared to the corresponding period in 2012. Weather-adjusted KWH energy sales to residential and commercial customers increased 0.8% primarily due to customer growth. KWH energy sales to industrial customers increased 0.3% due to decreased 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 0.5% primarily due to customer growth. Weather-adjusted KWH energy sales to commercial customers increased 0.2% primarily due to customer growth, partially offset by a decrease in customer usage. KWH energy sales to industrial customers decreased 2.6%, primarily due to changes in customers' operations.

Fuel and other cost recovery revenues decreased in the third quarter 2013 when compared to the corresponding period in 2012 primarily due to lower revenues associated with recoverable fuel costs, which were reduced by a payment received pursuant to the resolution of a contract dispute.

Fuel and other cost recovery revenues increased year-to-date 2013 when compared to the corresponding period in 2012 primarily due to higher recoverable fuel and energy conservation costs. Recoverable fuel costs increased primarily due to lower revenues from energy sales to affiliates, which are included in the determination of recoverable fuel costs. The increase was partially offset by a payment received pursuant to the resolution of a contract dispute. Energy conservation revenues increased due to higher expenses associated with energy conservation programs. 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 –

95

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

"PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery" herein for additional information including the resolution of a contract dispute.

Wholesale Revenues – Non-Affiliates

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$2.0	7.2	$(0.8)	(0.9)

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 third quarter 2013, wholesale revenues from sales to non-affiliates were $29.4 million compared to $27.4 million for the corresponding period in 2012. The increase was primarily due to higher energy revenues related to a 22.7% increase in KWH sales to unit power customers to serve their loads.

For year-to-date 2013, wholesale revenues from sales to non-affiliates were $82.5 million compared to $83.3 million for the corresponding period in 2012. The decrease was not material.

Wholesale Revenues – Affiliates

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(13.4)	(44.5)	$(30.0)	(31.5)

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

In the third quarter 2013, wholesale revenues from sales to affiliates were $16.7 million compared to $30.1 million for the corresponding period in 2012. The decrease was primarily due to lower energy revenues related to a 46.4% decrease in KWH sales that resulted from less Gulf Power generation being dispatched to serve affiliated companies' demand in the third quarter 2013 compared to the corresponding period in 2012. This decrease was partially offset by a 3.6% increase in the price of energy sold to affiliates in the third quarter 2013.

For year-to-date 2013, wholesale revenues from sales to affiliates were $65.2 million compared to $95.2 million for the corresponding period in 2012. The decrease was primarily due to lower energy revenues related to a 41.2% decrease in KWH sales that resulted from less Gulf Power generation being 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 16.6% increase in the price of energy sold to affiliates for year-to-date 2013.

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Fuel and Purchased Power Expenses

	Third Quarter 2013 vs. Third Quarter 2012				Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(24.6	)	(15.3)	$	(25.7	)	(6.1)
Purchased power – non-affiliates	(1.1		)	(6.5)	(0.3		)	(0.8)
Purchased power – affiliates	5.0			46.8	11.6			62.5
Total fuel and purchased power expenses	$	(20.7	)		$	(14.4	)

In the third quarter 2013, total fuel and purchased power expenses were $169.2 million compared to $189.9 million for the corresponding period in 2012. The decrease was primarily due to a payment received pursuant to the resolution of a contract dispute. The remaining decrease was attributable to a 7.5% decrease in the volume of fuel and purchased power KWHs generated and purchased, partially offset by an increase of 8.1% in the average cost of fuel and purchased power.

For year-to-date 2013, total fuel and purchased power expenses were $468.9 million compared to $483.3 million for the corresponding period in 2012. The decrease was primarily due to a payment received pursuant to the resolution of a contract dispute. The remaining decrease was attributable to a 10.8% decrease in the volume of fuel and purchased power KWHs generated and purchased, partially offset by an increase of 13.6% in the average cost of fuel and purchased power.

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

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

	Third Quarter 2013	Third Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (millions of KWHs)	2,692	2,642	6,978	7,633
Total purchased power (millions of KWHs)	1,593	1,992	4,602	5,352
Sources of generation (percent) –
Coal	64	63	62	61
Gas	36	37	38	39
Cost of fuel, generated (cents per net KWH) –
Coal(a)	3.33	4.56	4.09	4.41
Gas	4.17	4.39	4.05	4.00
Average cost of fuel, generated (cents per net KWH)(a)	3.64	4.50	4.07	4.25
Average cost of purchased power (cents per net KWH)(b)	4.48	3.57	4.01	2.97

(a) Includes the effect of a payment received pursuant to the resolution of a contract dispute.

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

Fuel

In the third quarter 2013, fuel expense was $136.2 million compared to $160.8 million for the corresponding period in 2012. For year-to-date 2013, fuel expense was $397.4 million compared to $423.1 million for the corresponding period in 2012. The decreases were primarily due to a payment received pursuant to the resolution of a contract

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dispute. For the third quarter and year-to-date 2013, the average cost of fuel increased (decreased) (2.2%) and 2.8%, respectively, while the volume of KWHs generated increased (decreased) 1.9% and (8.6%), respectively.

Purchased Power – Non-Affiliates

In the third quarter 2013, purchased power expense from non-affiliates was $17.2 million compared to $18.3 million for the corresponding period in 2012. The decrease was primarily due to a 27.4% decrease in the volume of KWHs purchased, partially offset by a 30.2% increase in the average cost per KWH purchased.

For year-to-date 2013, purchased power expense from non-affiliates was $41.4 million compared to $41.7 million for the corresponding period in 2012. The decrease was not material.

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

Purchased Power – Affiliates

In the third quarter 2013, purchased power expense from affiliates was $15.8 million compared to $10.8 million for the corresponding period in 2012. The increase reflects an increase of $5.0 million in energy costs due to a 132.0% increase in the volume of KWHs purchased, partially offset by a 44.7% decrease in the average cost per KWH purchased.

For year-to-date 2013, purchased power expense from affiliates was $30.1 million compared to $18.5 million for the corresponding period in 2012. The increase reflects an increase of $12.1 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 176.3% increase in the volume of KWHs purchased, partially offset by a 45.9% decrease in the 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$2.2	2.9	$2.7	1.2

In the third quarter 2013, other operations and maintenance expenses were $76.9 million compared to $74.7 million for the corresponding period in 2012. The increase was primarily due to increases of $4.7 million in labor and benefit-related expenses and $1.1 million in transmission service related to a third party PPA, partially offset by a decrease of $3.9 million in routine and planned maintenance expense primarily at generation facilities.

For year-to-date 2013, other operations and maintenance expenses were $232.5 million compared to $229.8 million for the corresponding period in 2012. The increase was primarily due to increases of $7.3 million in labor and benefit-related expenses and $4.1 million in transmission service related to a third party PPA, partially offset by a decrease of $8.8 million in routine and planned maintenance expense primarily at generation facilities.

The increased expense from transmission service did not have a significant impact on earnings since the expense was offset by purchased power capacity revenues through Gulf Power’s purchased power capacity recovery clause. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Purchased Power Capacity Recovery" herein for additional information.

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Depreciation and Amortization

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$1.1	3.3	$6.9	6.5

In the third quarter 2013, depreciation and amortization was $37.3 million compared to $36.2 million for the corresponding period in 2012. For year-to-date 2013, depreciation and amortization was $111.5 million compared to $104.6 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.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(0.7)	(4.4)	$(3.1)	(6.7)

In the third quarter 2013, interest expense, net of amounts capitalized was $14.0 million compared to $14.7 million for the corresponding period in 2012. For year-to-date 2013, interest expense, net of amounts capitalized was $42.6 million compared to $45.7 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(2.2)	(7.3)	$(1.2)	(1.9)

In the third quarter 2013, income taxes were $28.1 million compared to $30.3 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 $63.0 million compared to $64.2 million for the corresponding period in 2012. The decrease was primarily due to lower pre-tax earnings, partially offset by a decrease in state income tax credits, as well as a settlement with the IRS related to the production activities deduction. 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 case is now concluded.

Environmental Statutes and Regulations

Air Quality

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

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 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 Gulf Power's service territory were designated as nonattainment under this rule. The EPA has deferred designation of attainment and

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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.

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 and, on October 31, 2013, further extended the deadline until November 20, 2013.

The ultimate impact of these proposed regulations will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of the management and disposal of coal combustion byproducts. On September 30, 2013, the U.S. District Court for the District of Columbia issued an order granting partial summary judgment to the environmental groups and other parties, ruling that the EPA has a statutory obligation to review and revise, as necessary, the federal solid waste regulations applicable to coal combustion byproducts and, on October 29, 2013, directed the EPA to provide a proposed schedule to complete the rulemaking. The impact of this order depends on further judicial and regulatory action and, therefore, 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 – 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.

On September 20, 2013, the EPA proposed revised regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel-fired steam electric generating units. A Presidential memorandum issued on June 25, 2013 also directed the EPA 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 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 market-based contracts. 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.

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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.

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.

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.

On November 4, 2013, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2014. The net effect of the approved changes is a $65.2 million increase in annual revenue for 2014.

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 September 30, 2013 totaled $10.0 million which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. The under recovered fuel cost balance included approximately $26.6 million received during the third quarter 2013 as a result of a payment from one of Gulf Power's fuel vendors pursuant 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

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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.

Under recovered purchased power capacity costs at September 30, 2013 totaled $6.4 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.

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 September 30, 2013 totaled $7.9 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.

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 September 30, 2013 totaled $5.7 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.

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.

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

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

Net cash provided from operating activities totaled $277.9 million for the first nine months of 2013 compared to $405.8 million for the corresponding period in 2012. The $127.9 million decrease was primarily related to a decrease in cash flows associated with deferred income taxes and the recovery of fuel costs which moved from an over recovered to an under recovered position. Net cash used for investing activities totaled $214.5 million in the first nine months of 2013 primarily due to property additions to utility plant and costs of removal. Net cash used for financing activities totaled $67.7 million for the first nine months of 2013, primarily due to the payment of common stock dividends and the repayment of short-term debt, partially offset by issuances of common and preference stock. 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 nine months of 2013 include a net increase of $144.9 million in property, plant, and equipment. Increases of $60.2 million in long-term debt, $48.5 million in preference stock, and $40.0 million in common stock due to the issuance of common stock to Southern Company were used to partially offset decreases of $68.3 million in notes payable and $60.0 million in securities due within one year. Accumulated deferred income tax liabilities also increased $40.9 million due to accelerated depreciation deductions.

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. There are no requirements through September 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; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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Sources of Capital

Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, 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.

At September 30, 2013, Gulf Power had approximately $27.9 million of cash and cash equivalents. Committed credit arrangements with banks at September 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 September 30, 2013 was approximately $69 million. In addition, at September 30, 2013, Gulf Power had $13.0 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months. Gulf Power also has substantial cash flows from operating activities and access to the capital markets to meet liquidity needs.

During the first nine months of 2013, Gulf Power entered into, amended, or renewed certain of its credit arrangements, the amounts of which are reflected in the table above. 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at September 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	$	59	0.2%	$	66	0.2%	$	131
Short-term bank debt	—		—%	5		1.2%	125
Total	$	59	0.2%	$	71	0.3%

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

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 September 30, 2013 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	92
Below BBB- and/or Baa3	457

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 third 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, 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 third quarter 2013 when compared with the December 31, 2012 reporting period.

106

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(21	)	$	(23	)
Contracts realized or settled	6			11
Current period changes(a)	(7		)	(10		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(22	)	$	(22	)

(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 nine months ended September 30, 2013 were as follows: 

	Third Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Natural gas swaps	$	(1	)	$	1
Natural gas options	—			—
Other energy-related derivatives	—			—
Total changes	$	(1	)	$	1

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

	September 30, 2013	June 30, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	85	79	71
Commodity – Natural gas options	—	—	—
Total hedge volume	85	79	71

The weighted average swap contract cost above market prices was approximately $0.26 per mmBtu as of September 30, 2013, $0.26 per mmBtu as of June 30, 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 nine months ended September 30, 2013 and 2012 for energy-related derivative contracts that are not hedges were not material.

107

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2013 were as follows:

	September 30, 2013 Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2	(22		)	(11		)	(9		)	(2		)
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(22	)	$	(11	)	$	(9	)	$	(2	)

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 90-day 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. Gulf Power also 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 90-day 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.

108

MISSISSIPPI POWER COMPANY

109

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	230,710		$	220,296		$	613,274		$	578,744
Wholesale revenues, non-affiliates	82,937			77,017			219,984			195,364
Wholesale revenues, affiliates	6,999			4,232			31,242			13,596
Other revenues	4,560			3,874			13,075			12,513
Total operating revenues	325,206			305,419			877,575			800,217
Operating Expenses:
Fuel	138,148			127,576			384,905			321,664
Purchased power, non-affiliates	2,077			1,357			5,222			4,434
Purchased power, affiliates	14,691			15,683			28,302			35,386
Other operations and maintenance	56,907			53,541			166,175			168,937
Depreciation and amortization	22,202			21,136			67,644			66,134
Taxes other than income taxes	21,071			19,975			60,760			60,312
Estimated loss on Kemper IGCC	150,000			—			1,062,000			—
Total operating expenses	405,096			239,268			1,775,008			656,867
Operating Income (Loss)	(79,890		)	66,151			(897,433		)	143,350
Other Income and (Expense):
Allowance for equity funds used during construction	32,624			17,763			87,740			43,460
Interest expense, net of amounts capitalized	(8,728		)	(9,735		)	(29,526		)	(30,563		)
Other income (expense), net	(375		)	2,584			(4,184		)	2,303
Total other income and (expense)	23,521			10,612			54,030			15,200
Earnings (Loss) Before Income Taxes	(56,369		)	76,763			(843,403		)	158,550
Income taxes (benefit)	(32,687		)	21,705			(355,156		)	42,344
Net Income (Loss)	(23,682		)	55,058			(488,247		)	116,206
Dividends on Preferred Stock	433			433			1,299			1,299
Net Income (Loss) After Dividends on Preferred Stock	$	(24,115	)	$	54,625		$	(489,546	)	$	114,907

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2013			2012		2013			2012
	(in thousands)					(in thousands)
Net Income (Loss)	$	(23,682	)	$	55,058	$	(488,247	)	$	116,206
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $- and $(296), respectively	—			1		—			(477		)
Reclassification adjustment for amounts included in net income, net of tax of $131, $131, $394 and $279, respectively	212			212		637			450
Total other comprehensive income (loss)	212			213		637			(27		)
Comprehensive Income (Loss)	$	(23,470	)	$	55,271	$	(487,610	)	$	116,179

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

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2013			2012
	(in thousands)
Operating Activities:
Net income (loss)	$	(488,247	)	$	116,206
Adjustments to reconcile net income (loss)   to net cash provided from (used for) operating activities —
Depreciation and amortization, total	68,436			65,902
Deferred income taxes	(391,143		)	8,527
Investment tax credits received	45,228			38,811
Allowance for equity funds used during construction	(87,740		)	(43,460		)
Pension, postretirement, and other employee benefits	12,876			6,700
Hedge settlements	—			(15,983		)
Stock based compensation expense	2,029			1,718
Regulatory assets associated with Kemper IGCC	(23,545		)	(11,921		)
Estimated loss on Kemper IGCC	1,062,000			—
Kemper regulatory deferral	61,997			—
Other, net	8,792			7,086
Changes in certain current assets and liabilities —
-Receivables	(40,003		)	(17,622		)
-Fossil fuel stock	59,608			(19,888		)
-Materials and supplies	(8,029		)	(2,683		)
-Prepaid income taxes	33,793			2,517
-Other current assets	(1,710		)	(14,652		)
-Accounts payable	17,397			13,581
-Accrued taxes	(2,334		)	2,361
-Accrued interest	15,153			16,015
-Accrued compensation	(8,543		)	(4,830		)
-Over recovered regulatory clause revenues	(49,247		)	10,982
-Other current liabilities	—			(1,488		)
Net cash provided from operating activities	286,768			157,879
Investing Activities:
Property additions	(1,221,519		)	(1,169,653		)
Cost of removal, net of salvage	(5,769		)	(3,092		)
Construction payables	(6,200		)	97,360
Capital grant proceeds	4,500			10,058
Proceeds from asset sales	79,020			—
Other investing activities	(3,659		)	(12,891		)
Net cash used for investing activities	(1,153,627		)	(1,078,218		)
Financing Activities:
Proceeds —
Capital contributions from parent company	601,197			429,272
Bonds-Other	31,092			25,613
Senior notes issuances	—			600,000
Interest-bearing refundable deposit related to asset sale	—			150,000
Other long-term debt issuances	475,000			—
Redemptions —
Bonds-Other	(82,563		)	—
Capital leases	(82		)	(633		)
Other long-term debt	(125,000		)	(205,000		)
Return of paid in capital	(60,614		)	—
Payment of preferred stock dividends	(1,299		)	(1,299		)
Payment of common stock dividends	(71,956		)	(80,100		)
Other financing activities	(1,845		)	7,597
Net cash provided from financing activities	763,930			925,450
Net Change in Cash and Cash Equivalents	(102,929		)	5,111
Cash and Cash Equivalents at Beginning of Period	145,008			211,585
Cash and Cash Equivalents at End of Period	$	42,079		$	216,696
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $53,450 and $45,079, net of $37,882 and $22,131 capitalized for 2013 and 2012, respectively)	$	15,568		$	22,948
Income taxes, net	(48,307		)	(11,737		)
Noncash transactions — accrued property additions at end of period	208,663			233,262
Noncash transactions — capital lease obligation	82,915			—

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

111

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2013			At December 31, 2012
	(in thousands)
Current Assets:
Cash and cash equivalents	$	42,079		$	145,008
Receivables —
Customer accounts receivable	50,679			29,561
Unbilled revenues	38,802			32,688
Other accounts and notes receivable	5,580			7,517
Affiliated companies	39,334			27,160
Accumulated provision for uncollectible accounts	(636		)	(373		)
Fossil fuel stock, at average cost	116,955			176,378
Materials and supplies, at average cost	42,289			34,260
Other regulatory assets, current	55,375			55,302
Prepaid income taxes	96,914			129,835
Other current assets	5,270			17,170
Total current assets	492,641			654,506
Property, Plant, and Equipment:
In service	3,313,524			3,036,159
Less accumulated provision for depreciation	1,101,682			1,065,474
Plant in service, net of depreciation	2,211,842			1,970,685
Construction work in progress	2,339,396			2,393,145
Total property, plant, and equipment	4,551,238			4,363,830
Other Property and Investments	4,912			4,887
Deferred Charges and Other Assets:
Deferred charges related to income taxes	110,978			71,869
Other regulatory assets, deferred	259,906			236,225
Other deferred charges and assets	52,618			42,304
Total deferred charges and other assets	423,502			350,398
Total Assets	$	5,472,293		$	5,373,621

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

112

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2013			At December 31, 2012
	(in thousands)
Current Liabilities:
Securities due within one year	$	152,509		$	276,471
Interest-bearing refundable deposit related to asset sale	150,000			150,000
Accounts payable —
Affiliated	65,065			54,769
Other	263,913			262,992
Customer deposits	14,394			14,202
Accrued taxes —
Accrued income taxes	8,903			2,339
Other accrued taxes	61,117			69,376
Accrued interest	45,529			30,376
Accrued compensation	7,163			15,706
Other regulatory liabilities, current	11,846			5,376
Over recovered regulatory clause liabilities	28,091			77,338
Other current liabilities	24,825			31,882
Total current liabilities	833,355			990,827
Long-term Debt	2,069,938			1,564,462
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	29,086			244,958
Deferred credits related to income taxes	8,818			10,106
Accumulated deferred investment tax credits	284,496			370,554
Employee benefit obligations	161,938			157,421
Other cost of removal obligations	150,028			143,461
Other regulatory liabilities, deferred	117,804			56,984
Other deferred credits and liabilities	52,891			52,860
Total deferred credits and other liabilities	805,061			1,036,344
Total Liabilities	3,708,354			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	1,944,336			1,401,520
Retained earnings (deficit)	(242,792		)	318,710
Accumulated other comprehensive loss	(8,076		)	(8,713		)
Total common stockholder's equity	1,731,159			1,749,208
Total Liabilities and Stockholder's Equity	$	5,472,293		$	5,373,621

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

113

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2013 vs. THIRD 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 October 28, 2013, Mississippi Power revised the scheduled in-service date for the Kemper IGCC to the fourth quarter 2014 and further revised its cost estimate for the Kemper IGCC to approximately $4.02 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

114

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

IGCC that have negatively impacted 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)

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(78.7)	N/M	$(604.4)	N/M

N/M - Not meaningful

Mississippi Power's net loss after dividends on preferred stock for the third quarter 2013 was $24.1 million compared to net income after dividends on preferred stock of $54.6 million for the corresponding period in 2012. The decrease was primarily related to a $150.0 million pre-tax charge ($92.6 million after tax) for 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 AFUDC equity primarily related to the construction of the Kemper IGCC and an increase in revenues primarily due to retail and wholesale base rate increases and a retail rate increase related to the Kemper IGCC cost recovery that became effective in April 2013.

For year-to-date 2013, the net loss after dividends on preferred stock was $489.5 million compared to net income after dividends on preferred stock of $114.9 million for the corresponding period in 2012. The decrease was primarily related to $1.06 billion in pre-tax charges ($655.8 million after tax) for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of $245.3 million of DOE Grants and the Cost Cap Exceptions. These losses were partially offset by an increase in AFUDC equity primarily related to the construction of the Kemper IGCC, an increase in revenues primarily due to retail and wholesale base rate increases and a retail rate increase related to the Kemper IGCC cost recovery that became effective in April 2013, and a decrease in non-fuel operations and maintenance expenses.

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.

Retail Revenues

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$10.4	4.7	$34.6	6.0

In the third quarter 2013, retail revenues were $230.7 million compared to $220.3 million for the corresponding period in 2012. For year-to-date 2013, retail revenues were $613.3 million compared to $578.7 million for the corresponding period in 2012.

115

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	Third Quarter 2013				Year-to-Date 2013
	(in millions)			(% change)	(in millions)			(% change)
Retail – prior year	$	220.3			$	578.7
Estimated change in –
Rates and pricing	6.5			3.0	11.0			1.9
Sales growth (decline)	3.2			1.4	3.6			0.6
Weather	(3.2		)	(1.5)	(2.8		)	(0.5)
Fuel and other cost recovery	3.9			1.8	22.8			4.0
Retail – current year	$	230.7		4.7%	$	613.3		6.0%

Revenues associated with changes in rates and pricing increased in the third quarter 2013 when compared to the corresponding period in 2012 primarily due to a rate increase related to Kemper IGCC cost recovery that became effective in April 2013.

Revenues associated with changes in rates and pricing increased year-to-date 2013 when compared to the corresponding period in 2012 due to increases totaling $15.7 million related to a base rate increase and a rate increase related to Kemper IGCC cost recovery that became effective in April 2013, partially offset by a $4.7 million retail refund related to the annual PEP lookback filing.

See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Retail Regulatory Matters – Mississippi Power – Performance Evaluation Plan" herein for additional information.

Revenues attributable to changes in sales increased in the third quarter 2013 when compared to the corresponding period in 2012. KWH energy sales to industrial customers increased 8.1% due to increased usage by larger customers. Weather-adjusted KWH energy sales to residential customers increased 1.9% when compared to the corresponding period in 2012 due to an increase in the number of residential customers. Weather-adjusted KWH energy sales to commercial customers decreased 0.3% when compared to the corresponding period in 2012 due to slower commercial economic activity.

Revenues attributable to changes in sales increased for year-to-date 2013 when compared to the corresponding period in 2012. KWH energy sales to industrial customers increased 1.2% due to increased usage by larger customers. Weather-adjusted KWH energy sales to residential customers decreased 0.1% when compared to the corresponding period in 2012 due to slower residential usage growth. Weather-adjusted KWH energy sales to commercial customers were flat.

Fuel and other cost recovery revenues increased in the third 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.

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Wholesale Revenues – Non-Affiliates

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$5.9	7.7	$24.6	12.6

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 third quarter 2013, wholesale revenues from sales to non-affiliates were $82.9 million compared to $77.0 million for the corresponding period in 2012. The increase was due to a $3.8 million increase in base revenues primarily resulting from a wholesale base rate increase effective April 1, 2013 and a $2.1 million increase in energy revenues, of which $1.9 million was primarily associated with higher fuel prices in the third quarter 2013 compared to the corresponding period in 2012.

For year-to-date 2013, wholesale revenues from sales to non-affiliates were $220.0 million compared to $195.4 million for the corresponding period in 2012. The increase was due to an $11.8 million increase in base revenues primarily resulting from wholesale base rate increases effective April 1, 2012 and 2013 and a $12.8 million increase in energy revenues, of which $11.1 million was associated with higher fuel prices and $1.7 million was associated with an increase in KWH sales due to increased non-territorial sales for year-to-date 2013 compared to the corresponding period in 2012.

Wholesale Revenues – Affiliates

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$2.8	65.4	$17.6	129.8

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These 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 third quarter 2013, wholesale revenues from sales to affiliates were $7.0 million compared to $4.2 million for the corresponding period in 2012. The increase was primarily due to a $1.4 million increase in energy revenues, of which $0.6 million was associated with an increase in KWH sales and $0.8 million was associated with higher prices, and a $1.4 million increase in capacity payments from affiliates.

For year-to-date 2013, wholesale revenues from sales to affiliates were $31.2 million compared to $13.6 million for the corresponding period in 2012. The increase was primarily due to a $16.3 million increase in energy revenues, of which $9.3 million was associated with an increase in KWH sales and $7.0 million was associated with higher prices, and a $1.3 million increase in capacity payments from affiliates.

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Fuel and Purchased Power Expenses

	Third Quarter 2013 vs. Third Quarter 2012				Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	10.6		8.3	$	63.2		19.7
Purchased power – non-affiliates	0.7			53.1	0.8			17.8
Purchased power – affiliates	(1.0		)	(6.3)	(7.1		)	(20.0)
Total fuel and purchased power expenses	$	10.3			$	56.9

In the third quarter 2013, total fuel and purchased power expenses were $154.9 million compared to $144.6 million for the corresponding period in 2012. The increase was primarily due to an $11.4 million increase in the total volume of KWHs generated and purchased, partially offset by a $1.1 million decrease in the cost of fuel and purchased power.

For year-to-date 2013, total fuel and purchased power expenses were $418.4 million compared to $361.5 million for the corresponding period in 2012. The increase was primarily due to a $38.2 million increase in the total volume of KWHs generated and purchased and an $18.7 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.

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

	Third Quarter 2013	Third Quarter 2012	Year-to-Date 2013	Year-to-Date 2012
Total generation (millions of KWHs)	3,688	3,534	10,645	9,875
Total purchased power (millions of KWHs)	469	523	1,070	1,436
Sources of generation (percent) –
Coal	43	35	38	29
Gas	57	65	62	71
Cost of fuel, generated (cents per net KWH) –
Coal	5.12	5.29	5.01	5.03
Gas	3.08	3.07	3.14	2.87
Average cost of fuel, generated (cents per net KWH)	4.03	3.91	3.91	3.55
Average cost of purchased power (cents per net KWH)	3.58	3.26	3.13	2.77

Fuel

In the third quarter 2013, fuel expense was $138.2 million compared to $127.6 million for the corresponding period in 2012. The increase was primarily due to a 3.1% increase in the average cost of fuel per KWH generated and a 5.1% increase in the volume of KWHs generated resulting from increased non-territorial sales in the third quarter 2013 as compared to the corresponding period in 2012.

For year-to-date 2013, fuel expense was $384.9 million compared to $321.7 million for the corresponding period in 2012. The increase was primarily due to a 10.1% increase in the average cost of fuel per KWH generated and a 8.5% increase in the volume of KWHs generated resulting from increased non-territorial sales in 2013 as compared to the corresponding period in 2012.

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Purchased Power - Non-Affiliates

In the third quarter 2013, purchased power expense from non-affiliates was $2.1 million compared to $1.4 million for the corresponding period in 2012. The increase was primarily the result of a 9.4% increase in the volume of KWHs purchased and a 39.9% increase in the average cost per KWH purchased.

For year-to-date 2013, purchased power expense from non-affiliates was $5.2 million compared to $4.4 million for the corresponding period in 2012. The increase was primarily the result of a 14.6% increase in the average cost per KWH purchased and a 2.7% increase in the volume of KWHs purchased.

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 third quarter 2013, purchased power expense from affiliates was $14.7 million compared to $15.7 million for the corresponding period in 2012. The decrease was primarily due to a 14.2% decrease in the volume of KWHs purchased, partially offset by a 9.1% increase in the average cost per KWH purchased.

For year-to-date 2013, purchased power expense from affiliates was $28.3 million compared to $35.4 million for the corresponding period in 2012. The decrease was primarily due to a 31.4% decrease in the volume of KWHs purchased, partially offset by a 16.6% increase in the average cost per KWH purchased.

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

Other Operations and Maintenance Expenses

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$3.4	6.3	$(2.7)	(1.6)

In the third quarter 2013, other operations and maintenance expenses were $56.9 million compared to $53.5 million for the corresponding period in 2012. The increase was primarily due to a $1.7 million increase in generation maintenance expenses related to scheduled outages, a $1.0 million increase in transmission expenses related to survey costs, and a $0.5 million increase in labor expenses.

For year-to-date 2013, other operations and maintenance expenses were $166.2 million compared to $168.9 million for the corresponding period in 2012. The decrease was primarily due to a $3.2 million decrease in labor expenses, a $3.0 million decrease in generation maintenance expenses related to scheduled outages and environmental-related costs, and a $1.3 million decrease in distribution expenses related to the timing of overhead line maintenance and vegetation management costs. These decreases were partially offset by a $4.0 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.

Depreciation and Amortization

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$1.1	5.0	$1.5	2.3

In the third quarter 2013, depreciation and amortization was $22.2 million compared to $21.1 million for the corresponding period in 2012. For year-to-date 2013, depreciation and amortization was $67.6 million compared to $66.1 million for the corresponding period in 2012. The increases were primarily due to a $1.6 million increase in

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ECO Plan amortization for both periods and increases of $0.7 million and $1.3 million in amortization resulting from the plant acquisition adjustment related to the purchase of Plant Daniel Units 3 and 4 for the third quarter 2013 and year-to-date 2013, respectively. These increases were partially offset by a $0.8 million decrease in amortization resulting from a regulatory deferral associated with the capital lease related to the Kemper IGCC air separation unit for both periods.

See Note 1 to the financial statements of Mississippi Power under "Purchase of the Plant Daniel Combined Cycle Generating Units" and "Depreciation and Amortization" in Item 8 of the Form 10-K/A for additional information on the purchase of Plant Daniel Units 3 and 4. 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 additional information on the Kemper IGCC, including the Kemper IGCC air separation unit.

Taxes Other Than Income Taxes

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$1.1	5.5	$0.5	0.7

In the third quarter 2013, taxes other than income taxes were $21.1 million compared to $20.0 million for the corresponding period in 2012. The increase was primarily due to a $0.9 million increase in franchise taxes and a $0.3 million increase in payroll taxes.

For year-to-date 2013, taxes other than income taxes were $60.8 million compared to $60.3 million for the corresponding period in 2012. The increase was primarily due to a $2.6 million increase in franchise taxes, partially offset by a $1.9 million decrease in ad valorem 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$150.0	N/M	$1,062.0	N/M

N/M - Not meaningful

In the third quarter 2013 and year-to-date 2013, estimated probable losses on the Kemper IGCC of $150.0 million and $1.06 billion, 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 Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$14.8	83.7	$44.2	101.9

In the third quarter 2013, AFUDC equity was $32.6 million compared to $17.8 million for the corresponding period in 2012. For year-to-date 2013, AFUDC equity was $87.7 million compared to $43.5 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

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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.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(1.0)	(10.3)	$(1.1)	(3.4)

In the third quarter 2013, interest expense, net of amounts capitalized was $8.7 million compared to $9.7 million for the corresponding period in 2012. Amounts capitalized primarily resulting from AFUDC debt associated with the Kemper IGCC in the third quarter 2013 were $14.3 million compared to $9.7 million for the corresponding period in 2012. This increase was partially offset by a $2.4 million increase in interest expense associated with issuances of new long-term debt and a $1.0 million increase in interest expense on the regulatory liability related to the Kemper IGCC rate recovery.

For year-to-date 2013, interest expense, net of amounts capitalized was $29.5 million compared to $30.6 million for the corresponding period in 2012. Amounts capitalized primarily resulting from AFUDC debt associated with the Kemper IGCC for year-to-date 2013 were $37.9 million compared to $22.1 million for the corresponding period in 2012. The change in AFUDC debt along with a $2.2 million decrease in interest expense associated with the redemption of long-term debt in 2012 was offset by an $11.2 million increase in interest expense associated with issuances of new long-term debt, a $3.7 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 $1.9 million increase in interest expense on the regulatory liability related to the Kemper IGCC rate recovery.

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.

Other Income (Expense), Net

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(3.0)	N/M	$(6.5)	N/M

N/M - Not meaningful

In the third quarter 2013, other income (expense), net was $(0.4) million compared to $2.6 million for the corresponding period in 2012. For year-to-date 2013, other income (expense), net was $(4.2) million compared to $2.3 million for the corresponding period in 2012. These decreases were primarily due to increases in consulting fees of $1.6 million and $4.9 million for the third quarter 2013 and year-to-date 2013, respectively.

Income Taxes

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(54.4)	N/M	$(397.5)	N/M

N/M - Not meaningful

In the third quarter 2013, income taxes were $(32.7) million compared to $21.7 million for the corresponding period in 2012. For year-to-date 2013, income taxes were $(355.2) million compared to $42.3 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 on the Kemper IGCC.

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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 of the Form 10-K 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.

New Source Review Actions

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – New Source Review Actions" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K/A for additional information. On September 19, 2013, a three-judge panel of the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment of the U.S. District Court for the Northern District of Alabama in favor of Alabama Power, which was based on the exclusion of the testimony of certain of the EPA's experts, and remanded the case back to the U.S. District Court for the Northern District of Alabama for further proceedings. On October 31, 2013, Alabama Power filed with the U.S. Court of Appeals for the Eleventh Circuit a petition for rehearing. In February 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the 2011 judgment and recusal of the judge in the case involving Alabama Power (including claims related to the unit co-owned by Mississippi Power), which remains pending. The ultimate outcome of these matters 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 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 additional information regarding the EPA's MATS rule, the Cross State Air Pollution Rule, and the EPA's SO₂ rule.

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 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 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.

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 and, on October 31, 2013, further extended the deadline until November 20, 2013.

The ultimate impact of these proposed regulations will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts" of Mississippi Power in Item 7 of the Form 10-K/A for additional information regarding the EPA's proposed regulation of the management and disposal of coal combustion byproducts. On September 30, 2013, the U.S. District Court for the District of Columbia issued an order granting partial summary judgment to the environmental groups and other parties, ruling that the EPA has a statutory obligation to review and revise, as necessary, the federal solid waste regulations applicable to coal combustion byproducts and, on October 29, 2013, directed the EPA to provide a proposed schedule to complete the rulemaking. The impact of this order depends on further judicial and regulatory action and, therefore, the ultimate outcome of this matter cannot be determined at this time.

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Global Climate Issues

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

On September 20, 2013, the EPA proposed revised regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel-fired steam electric generating units. A Presidential memorandum issued on June 25, 2013 also directed the EPA 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 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 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 market-based contracts. 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

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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.

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 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.

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 September 30, 2013, total project expenditures were $278.3 million, of which Mississippi Power's portion was $139.2 million, excluding AFUDC of $6.6 million. The ultimate outcome of this matter cannot be determined at this time.

On August 13, 2013, the Mississippi PSC approved Mississippi Power’s 2013 ECO Plan filing which proposed no change in rates.

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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 March 5, 2013, the Mississippi PSC approved a $35.5 million decrease of the annual retail fuel cost recovery factor, or 4.7% of total 2012 retail revenue, effective March 19, 2013.

At September 30, 2013, the amount of over recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $21.8 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 September 30, 2013, the amount of over recovered wholesale MRA and MB fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $9.1 million and $0.6 million, respectively, compared to $19.0 million and $2.1 million, respectively, at December 31, 2012. In addition, at September 30, 2013, the amount of under recovered MRA emissions allowance cost included on Mississippi Power's Condensed Balance Sheets herein was $3.4 million compared to $0.4 million at December 31, 2012. Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel 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 June 4, 2013, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2013, which included 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – 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 September 30, 2013, the balance in the storm reserve was $59.2 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

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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. 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.

Kemper IGCC Construction Schedule and 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. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC. The Kemper IGCC was originally scheduled to be placed in service in May 2014.

On October 28, 2013, Mississippi Power revised the scheduled in-service date for the Kemper IGCC to the fourth quarter 2014 primarily as the result of lower-than-planned installation levels for piping as well as abnormally wet weather. Also on October 28, 2013, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately $4.02 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, $426 million of AFUDC, and $101 million of certain general exceptions. Additionally, Mississippi Power expects to defer $91 million of non-capital Kemper IGCC-related costs to a regulatory asset.

Mississippi Power recorded a pre-tax charge to income for an estimated probable loss of $462.0 million ($285.3 million after tax) in the first quarter 2013 as a result of additional cost pressures, including labor costs, piping and other material costs, engineering and support costs, and productivity decreases. Mississippi Power recorded a pre-tax charge to income for an estimated probable loss of $450.0 million ($277.9 million after tax) in the second quarter 2013 as a result of 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 recorded a pre-tax charge to income for an estimated probable loss of $150.0 million ($92.6 million after tax) in the third quarter 2013 primarily as a result of the schedule extension.

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. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC" for additional information.

Mississippi Power could experience further construction cost increases and/or schedule extensions 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 further schedule extensions 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

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in further cost increases and could result in the loss of certain tax benefits related to bonus depreciation. 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 September 30, 2013, Mississippi Power had incurred total costs of $3.61 billion on the Kemper IGCC. These costs include $2.94 billion for the portion of the Kemper IGCC subject to the construction cost cap, $223.9 million for the lignite mine and equipment, $91.9 million for the CO₂ pipeline facilities, $232.2 million of AFUDC, and $67.6 million of certain general exceptions. Also included in this total is $55.2 million of certain regulatory assets. Of this total, $2.41 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.14 billion), $59.1 million in other regulatory assets, and $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, subject to review of such costs by the Mississippi PSC. This includes deferred costs associated with the generation resource planning, evaluation, and screening activities. The amortization period for any such costs approved for recovery 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

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 (excluding AFUDC) 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 and is expected to be revised later in 2013 in connection with the revised in-service date); (4) the Mississippi PSC's decision on the Seven-Year Rate Plan within four months of that filing (which, given the expected revision, is now expected to occur in the first half of 2014); (5) Mississippi Power's agreement to limit the portion of prudently-

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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 of up to $1 billion 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 the second quarter 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 October 15, 2013 revised 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 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 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.

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 on January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. Amounts collected through these rates are being recorded as a regulatory liability to be used to mitigate customer rate impacts when the Kemper IGCC is placed in service. As of September 30, 2013, $62.0 million had been collected and recorded as a regulatory liability 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 contemplates the continued accrual of AFUDC through the in-service date, subject to approval by the Mississippi PSC.

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 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. 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 regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan 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 assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the

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American Taxpayer Relief Act of 2012 (ATRA), which currently requires that the Kemper IGCC be placed in service in 2014. Mississippi Power plans to amend the Seven-Year Rate Plan described above to reflect changes including the revised in-service date, the change in expected benefits relating to tax credits, and other tax matters, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. Mississippi Power does not expect these revisions to change the total customer rate impacts contemplated in the Seven-Year Rate Plan. See "Tax Incentives" and "Income Tax Matters" herein for additional information relating to tax credits and bonus depreciation.

On October 15, 2013, the Mississippi PSC issued a revised 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 the second quarter 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.

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 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.

Nitrogen Supply Agreement

On September 19, 2013, Mississippi Power entered into an agreement to sell the air separation unit for the Kemper IGCC for $79.0 million and also entered into a 20-year nitrogen supply agreement, whereby nitrogen will be supplied to Mississippi Power for the gasification process. The nitrogen supply agreement resulted in a capital lease obligation for Mississippi Power at inception of $82.9 million with an annual interest rate of 4.9%. Assets acquired under capital leases are recorded on Mississippi Power’s Condensed Balance Sheet herein as utility plant in service, and the related obligations are classified as long-term debt and securities due within one year. See FUTURE EARNINGS POTENTIAL – "Capital Requirements and Contractual Obligations" herein for additional information.

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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 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. On May 15, 2013, the IRS notified Mississippi Power that no additional tax credits under the Internal Revenue Code Section 48A Phase III were allocated to the Kemper IGCC. As a result of the schedule extension for the Kemper IGCC, the Phase I credits will be recaptured and Mississippi Power has reclassified the recaptured credits as a reduction of prepaid income taxes on Mississippi Power’s Condensed Balance Sheets herein. Through September 30, 2013, Mississippi Power had recorded tax benefits totaling $276.4 million for the remaining Phase II credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the tax credits will be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.

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

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 Mississippi Power through 2013.

On January 2, 2013, the 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.

Consequently, Mississippi Power's positive cash flow benefit is estimated to be between $70 million and $80 million in 2013.

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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.

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.

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 Estimated Construction Costs for the Kemper IGCC, 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 extended the scheduled in-service date for the Kemper IGCC to the fourth quarter 2014 and revised its cost estimate to complete construction 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, $450 million, and $150 million in the first, second, and third 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 could experience further construction cost increases and/or schedule extensions 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 further schedule extensions 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.

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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 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 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 for the nine months ended September 30, 2013 were negatively affected by the estimated probable losses relating to the Kemper IGCC, Mississippi Power's financial condition remained stable at September 30, 2013. These charges for the nine months ended September 30, 2013 have resulted in cash expenditures of $57.4 million with no recovery as of September 30, 2013 and are expected to result in future cash expenditures of $1.1 billion with no 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 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 $286.8 million for the first nine months of 2013, an increase of $128.9 million as compared to the corresponding period in 2012. The increase in cash provided from operating activities is primarily due to decreases in fossil fuel stock, increases in rate recovery related to the Kemper IGCC, and hedges settled in 2012, partially offset by an increase in fuel costs and an increase in receivables. Net cash used for investing activities totaled $1.2 billion for the first nine months of 2013 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber. Net cash provided from financing activities totaled $763.9 million for the first nine months of 2013 primarily due to the issuances of bank notes and capital contributions from Southern Company, partially offset by redemptions of long-term debt. 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 nine months of 2013 include a decrease in cash and cash equivalents of $102.9 million, a decrease in fossil fuel stock of $59.4 million, and an increase in total property, plant, and equipment of $187.4 million, primarily due to the Kemper IGCC. Prepaid income taxes, accumulated deferred income taxes, and accumulated deferred investment tax credits decreased $32.9 million, $215.9 million, and $86.1 million, respectively, primarily due to the estimated probable losses on the Kemper IGCC and the recapture of the Phase I credits. Securities due within one year and long-term debt increased $381.5 million primarily due to the issuance of $350.0 million of bank notes and the addition of the Kemper IGCC capital lease obligation relating to the nitrogen supply agreement of $80.3 million, partially offset by $82.6 million of revenue bonds paid at maturity. Total common stockholder’s equity decreased $18.0 million due to a $561.5 million decrease in retained earnings, which was primarily due to the estimated probable losses on the Kemper IGCC, partially offset by a $542.8 million increase in paid in capital. The increase in paid-in capital was primarily due to $600.0 million in capital contributions from Southern Company.

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,

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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 $152.5million will be required through September 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 $1.9 billion, $541 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 $1.6 billion in 2013 and $260 million in 2014, which is net of SMEPA's 15% proposed ownership share of the Kemper IGCC, which reflects costs of approximately $545 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 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.

Assets acquired under capital leases are recorded on the balance sheet as utility plant in service and the related obligations are classified as long-term debt and securities due within one year. On September 19, 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at inception of $82.9 million with an annual interest rate of 4.9%. The supply agreement is expected to result in additional obligations of $0.7 million in 2013, $2.5 million in 2014, $2.7 million in 2015, and $77.0 million thereafter.

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 nine months of 2013, Mississippi Power received $600 million in capital contributions from Southern Company. On October 29, 2013, Mississippi Power received $150 million in additional 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.

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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 September 30, 2013, Mississippi Power had approximately $42.1 million of cash and cash equivalents. Committed credit arrangements with banks at September 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)
$	15	$	120	$	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 September 30, 2013 was approximately $40 million.

As reflected in the table above, in the first nine 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 to capitalization 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.

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 September 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	$	—	—%	$	41	0.2%	$	148

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

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

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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 September 30, 2013, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $267 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.

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 September 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, including Mississippi Power, from stable to negative.

On August 6, 2013, Moody's downgraded the senior unsecured debt and preferred stock ratings of Mississippi Power to Baa1 from A3 and to Baa3 from Baa2, respectively. Moody's maintained the stable ratings outlook for Mississippi Power.

On August 6, 2013, Fitch affirmed the senior unsecured debt and preferred stock ratings of Mississippi Power and revised the ratings outlook for Mississippi Power from stable to negative.

Market Price Risk

Mississippi Power's market risk exposure relative to interest rate changes for the third 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, 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 third quarter 2013 when compared with the December 31, 2012 reporting period.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The changes in fair value of energy-related derivative contracts, substantially all of which are natural gas swaps accounted for as regulatory hedges, for the three and nine months ended September 30, 2013 were as follows:

	Third Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(13	)	$	(17	)
Contracts realized or settled	4			9
Current period changes(a)	(4		)	(5		)
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.

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 nine months ended September 30, 2013 were as follows:

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

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

	September 30, 2013	June 30, 2013	December 31, 2012
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	46	43	38
Commodity - Natural gas options	—	—	—
Total hedge volume	46	43	38

The weighted average swap contract cost above market prices was approximately $0.29 per mmBtu as of September 30, 2013, $0.30 per mmBtu as of June 30, 2013, and $0.44 per mmBtu as of December 31, 2012. There were no options outstanding as of the reporting periods presented. The costs associated with natural gas hedges are recovered through Mississippi Power's energy cost management clauses (ECM).

At September 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 nine months ended September 30, 2013 and 2012 for energy-related derivative contracts that are not hedges were not material.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2013 were as follows:

				September 30, 2013 Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2	(13		)	(6		)	(6		)	(1		)
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(13	)	$	(6	)	$	(6	)	$	(1	)

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. In September 2013, Mississippi Power amended the bank loan, which extended the maturity date to 2015. 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 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.

In July 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 September 2013, Mississippi Power entered into a two-year floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $125 million aggregate principal amount and proceeds were used to repay at maturity a two-year floating rate bank loan in the aggregate principal amount of $125 million.

In September 2013, the MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A of $40.07 million, Series 2012B of $21.25 million, and Series 2012C of $21.25 million were paid at maturity.

Also in September 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at inception of $82.9 million with an annual interest rate of 4.9%.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

replace these obligations with lower-cost capital if market conditions permit.

139

SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	265,752		$	239,916		$	705,828		$	558,338
Wholesale revenues, affiliates	96,795			112,705			263,624			330,443
Other revenues	2,220			2,350			5,517			5,676
Total operating revenues	364,767			354,971			974,969			894,457
Operating Expenses:
Fuel	133,464			126,109			363,466			306,738
Purchased power, non-affiliates	19,673			23,888			56,553			67,052
Purchased power, affiliates	7,011			2,650			21,158			7,904
Other operations and maintenance	41,309			40,357			154,920			128,951
Depreciation and amortization	41,094			37,612			126,152			103,541
Taxes other than income taxes	5,719			5,121			16,526			14,656
Total operating expenses	248,270			235,737			738,775			628,842
Operating Income	116,497			119,234			236,194			265,615
Other Income and (Expense):
Interest expense, net of amounts capitalized	(12,961		)	(17,210		)	(53,923		)	(44,801		)
Other income (expense), net	(791		)	(522		)	(2,739		)	(686		)
Total other income and (expense)	(13,752		)	(17,732		)	(56,662		)	(45,487		)
Earnings Before Income Taxes	102,745			101,502			179,532			220,128
Income taxes	17,592			33,126			37,265			75,834
Net Income	$	85,153		$	68,376		$	142,267		$	144,294

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Net Income	$	85,153	$	68,376	$	142,267	$	144,294
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $215, $- and $95, respectively	—		338		—		152
Reclassification adjustment for amounts included in net income, net of tax of $213, $999, $2,310 and $2,911, respectively	338		1,569		3,619		4,608
Total other comprehensive income (loss)	338		1,907		3,619		4,760
Comprehensive Income	$	85,491	$	70,283	$	145,886	$	149,054

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 STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2013			2012
	(in thousands)
Operating Activities:
Net income	$	142,267		$	144,294
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	131,955			112,013
Deferred income taxes	83,331			147,993
Investment tax credits	(25,137		)	36,308
Deferred revenues	3,136			9,299
Mark-to-market adjustments	68			(8,970		)
Other, net	894			1,168
Changes in certain current assets and liabilities —
-Receivables	(28,486		)	(20,427		)
-Fossil fuel stock	881			(6,440		)
-Materials and supplies	(5,902		)	(5,557		)
-Prepaid income taxes	(12,485		)	(5,669		)
-Other current assets	(2,017		)	(2,159		)
-Accounts payable	(4,282		)	5,668
-Accrued taxes	12,550			48,203
-Accrued interest	(8,306		)	(10,225		)
-Other current liabilities	235			808
Net cash provided from operating activities	288,702			446,307
Investing Activities:
Plant acquisition	(111,600		)	(113,651		)
Property additions	(463,873		)	(97,569		)
Change in construction payables	292			(17,557		)
Payments pursuant to long-term service agreements	(40,978		)	(52,650		)
Investment in restricted cash	(20,000		)	—
Other investing activities	(1,724		)	153
Net cash used for investing activities	(637,883		)	(281,274		)
Financing Activities:
Increase (decrease) in notes payable, net	120,798			(78,059		)
Proceeds —
Senior notes	300,000			—
Capital contributions	1,897			(681		)
Other long-term debt	22,722			4,949
Repayments — Other long-term debt	(220		)	(650		)
Payment of common stock dividends	(96,840		)	(95,250		)
Other financing activities	14,369			3,776
Net cash provided from (used for) financing activities	362,726			(165,915		)
Net Change in Cash and Cash Equivalents	13,545			(882		)
Cash and Cash Equivalents at Beginning of Period	28,592			16,943
Cash and Cash Equivalents at End of Period	$	42,137		$	16,061
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $7,682 and $16,436 capitalized for 2013 and 2012, respectively)	$	55,190		$	46,163
Income taxes, net	(6,518		)	(137,756		)
Noncash transactions — accrued property additions at end of period	36,370			21,034

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)

Assets	At September 30, 2013		At December 31, 2012
	(in thousands)
Current Assets:
Cash and cash equivalents	$	42,137	$	28,592
Receivables —
Customer accounts receivable	86,717		62,857
Other accounts receivable	1,754		3,135
Affiliated companies	44,474		38,269
Fossil fuel stock, at average cost	20,735		21,616
Materials and supplies, at average cost	52,272		46,370
Prepaid service agreements—current	80,053		80,629
Prepaid income taxes	67,729		4,498
Other prepaid expenses	7,714		5,637
Assets from risk management activities	46		375
Total current assets	403,631		291,978
Property, Plant, and Equipment:
In service	4,203,999		4,059,839
Less accumulated provision for depreciation	871,648		786,620
Plant in service, net of depreciation	3,332,351		3,273,219
Construction work in progress	494,867		24,835
Total property, plant, and equipment	3,827,218		3,298,054
Other Property and Investments:
Goodwill	1,839		1,839
Other intangible assets, net of amortization of $4,996 and $3,141 at September 30, 2013 and December 31, 2012, respectively	44,124		45,979
Total other property and investments	45,963		47,818
Deferred Charges and Other Assets:
Prepaid long-term service agreements	85,651		100,921
Other deferred charges and assets — affiliated	2,792		3,468
Other deferred charges and assets — non-affiliated	83,863		37,688
Total deferred charges and other assets	172,306		142,077
Total Assets	$	4,449,118	$	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 September 30, 2013		At December 31, 2012
	(in thousands)
Current Liabilities:
Securities due within one year	$	2,200	$	259
Notes payable — non-affiliated	191,765		70,968
Accounts payable —
Affiliated	68,677		65,832
Other	20,131		26,204
Accrued taxes —
Accrued income taxes	2,303		87
Other accrued taxes	13,362		3,031
Accrued interest	13,953		22,259
Construction holdbacks	25,000		—
Other current liabilities	21,609		8,932
Total current liabilities	359,000		197,572
Long-term Debt	1,625,830		1,306,099
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	636,530		550,685
Investment tax credits	189,152		167,130
Deferred capacity revenues — affiliated	28,048		19,514
Other deferred credits and liabilities — affiliated	1,876		2,638
Other deferred credits and liabilities — non-affiliated	8,318		5,863
Total deferred credits and other liabilities	863,924		745,830
Total Liabilities	2,848,754		2,249,501
Redeemable Noncontrolling Interest	27,065		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	1,029,443		1,027,548
Retained earnings	541,013		495,585
Accumulated other comprehensive income (loss)	2,843		(776		)
Total common stockholder's equity	1,573,299		1,522,357
Total Liabilities and Stockholder's Equity	$	4,449,118	$	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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THIRD QUARTER 2013 vs. THIRD 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 constructed an approximately 139-MW solar facility in Southern California. Commercial operation of the solar facility was declared by Campo Verde on October 25, 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$16.8	24.5	$(2.0)	(1.4)

Southern Power's net income for the third quarter 2013 was $85.2 million compared to $68.4 million for the corresponding period in 2012. The increase was primarily due to a decrease in income taxes.

Net income for year-to-date 2013 was $142.3 million compared to $144.3 million for the corresponding period in 2012. The decrease was primarily due to increases in other operations and maintenance expense, depreciation, and interest expense, partially offset by a decrease in income taxes.

Wholesale Revenues–Non-Affiliates

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$25.9	10.8	$147.5	26.4

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 third quarter 2013 were $265.8 million compared to $239.9 million for the corresponding period in 2012. The increase was due to a $16.1 million increase in capacity revenues, primarily due to an increase in capacity amounts under existing PPAs, and a $9.7 million increase in energy sales, reflecting a 29.8% 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 $705.8 million compared to $558.3 million for the corresponding period in 2012. The increase was due to an $85.7 million increase in energy sales, reflecting a 36.7% increase in the average price of energy, primarily as a result of higher natural gas prices, and a $61.8 million increase in capacity revenues. The increase in capacity revenues was 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 in late June 2012 and an increase in capacity amounts under existing PPAs.

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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(15.9)	(14.1)	$(66.8)	(20.2)

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 third quarter 2013 were $96.8 million compared to $112.7 million for the corresponding period in 2012. The decrease was the result of a $12.9 million decrease in energy sales under the IIC and a $3.0 million decrease in energy sales under existing PPAs, reflecting a 38.8% decrease in KWH sales primarily due to lower demand and higher gas prices. This decrease was partially offset by a 31.1% 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 $263.6 million compared to $330.4 million for the corresponding period in 2012. The decrease was the result of a $58.6 million decrease in energy sales under the IIC and an $8.2 million decrease in energy sales under existing PPAs, reflecting a 44.1% decrease in KWH sales primarily due to lower demand and higher gas prices. This decrease was partially offset by a 28.2% 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

	Third Quarter 2013 vs. Third Quarter 2012				Year-to-Date 2013 vs. Year-to-Date 2012
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	7.3		5.8	$	56.8		18.5
Purchased power – non-affiliates	(4.2		)	(17.6)	(10.5		)	(15.7)
Purchased power – affiliates	4.4			164.6	13.2			167.7
Total fuel and purchased power expenses	$	7.5			$	59.5

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 fuel revenues and does not have a significant impact on net income. Southern Power is responsible for the cost of

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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 third quarter 2013, total fuel and purchased power expenses were $160.1 million compared to $152.6 million for the corresponding period in 2012. Fuel and purchased power expenses increased $20.2 million primarily due to a 21.1% increase in the average cost of natural gas and a 14.2% increase in the average cost of purchased power. The increase was partially offset by a $12.7 million decrease associated with an 11.7% 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 $441.2 million compared to $381.7 million for the corresponding period in 2012. Fuel and purchased power expenses increased $112.2 million primarily due to a 38.5% increase in the average cost of natural gas and a 24.8% increase in the average cost of purchased power. The increase was partially offset by a $52.7 million decrease associated with a 14.5% 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 third quarter 2013, fuel expense was $133.4 million compared to $126.1 million for the corresponding period in 2012. The increase was primarily due to a $22.5 million increase associated with the average cost of natural gas per KWH generated, partially offset by a $15.3 million decrease associated with the volume of KWHs generated from natural gas.

For year-to-date 2013, fuel expense was $363.5 million compared to $306.7 million for the corresponding period in 2012. The increase was primarily due to a $98.8 million increase associated with the average cost of natural gas per KWH generated, partially offset by a $43.5 million decrease associated with the volume of KWHs generated from natural gas.

In the third quarter 2013, purchased power expense was $26.7 million compared to $26.5 million for the corresponding period in 2012. The increase was due to a $3.3 million increase associated with the cost of purchased power, partially offset by a $3.1 million decrease associated with the volume of KWHs purchased.

For year-to-date 2013, purchased power expense was $77.7 million compared to $75.0 million for the corresponding period in 2012. The increase was due to a $15.4 million increase associated with the cost of purchased power, partially offset by a $12.7 million decrease associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$0.9	2.4	$25.9	20.1

In the third quarter 2013, other operations and maintenance expenses were $41.3 million compared to $40.4 million for the corresponding period in 2012. The increase was not material.

For year-to-date 2013, other operations and maintenance expenses were $154.9 million compared to $129.0 million for the corresponding period in 2012. The increase was primarily due to scheduled outage costs and an increase in operating costs associated with Plant Nacogdoches placed in service in June 2012, Plant Apex placed in service in July 2012, and Plant Cleveland placed in service in December 2012.

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Depreciation and Amortization

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$3.5	9.3	$22.7	21.8

In the third quarter 2013, depreciation and amortization was $41.1 million compared to $37.6 million for the corresponding period in 2012. The increase was primarily due to an increase in plant in service, including the additions of Plants Apex and Cleveland in 2012.

For year-to-date 2013, depreciation and amortization was $126.2 million compared to $103.5 million for the corresponding period in 2012. The increase was primarily due to an increase in plant in service, including the additions of Plants Nacogdoches, Apex, and Cleveland in 2012, as well as outage related capital increases.

Taxes Other than Income Taxes

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$0.6	11.7	$1.8	12.8

In the third quarter 2013, taxes other than income taxes were $5.7 million compared to $5.1 million for the corresponding period in 2012. For year-to-date 2013, taxes other than income taxes were $16.5 million compared to $14.7 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

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(4.2)	(24.7)	$9.1	20.4

In the third quarter 2013, interest expense, net of amounts capitalized was $13.0 million compared to $17.2 million for the corresponding period in 2012. The decrease was primarily due to an increase in capitalized interest associated with the construction of Plants Campo Verde and Spectrum.

For year-to-date 2013, interest expense, net of amounts capitalized was $53.9 million compared to $44.8 million for the corresponding period in 2012. The increase was primarily due to an $8.8 million decrease in capitalized interest primarily resulting from the completion of Plants Nacogdoches and Cleveland in 2012.

Income Taxes

Third Quarter 2013 vs. Third Quarter 2012		Year-to-Date 2013 vs. Year-to-Date 2012
(change in millions)	(% change)	(change in millions)	(% change)
$(15.5)	(46.9)	$(38.5)	(50.9)

In the third quarter 2013, income taxes were $17.6 million compared to $33.1 million for the corresponding period in 2012. The decrease was primarily due to a $14.6 million increase in tax benefits recognized from investment tax credits (ITCs) related to solar plants placed in service in 2013.

For year-to-date 2013, income taxes were $37.3 million compared to $75.8 million for the corresponding period in 2012. The decrease was primarily due to a $24.7 million increase in tax benefits recognized from ITCs related to solar plants placed in service in 2013 and a $15.3 million decrease associated with lower pre-tax earnings.

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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 cost of units in the Power Pool, and operational limitations. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, 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 "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 "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 case is now concluded.

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.

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.

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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.

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 and, on October 31, 2013, further extended the deadline until November 20, 2013.

The ultimate impact of these proposed regulations will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

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

On September 20, 2013, the EPA proposed revised regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel-fired steam electric generating units. A Presidential memorandum issued on June 25, 2013 also directed the EPA 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 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.

Acquisitions

Adobe Solar, LLC

On August 27, 2013, Southern Power and TRE, through STR, entered into a purchase agreement with Sun Edison, LLC, the developer of the project, which provides for the acquisition of all of the outstanding membership interests

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of Adobe Solar, LLC (Adobe) by STR. Adobe is constructing an approximately 20-MW solar generating facility in Kern County, California. The solar facility is expected to begin commercial operation in spring 2014. Southern Power's purchase of Adobe for approximately $100 million is expected to occur in spring 2014. See Note (I) to the Condensed Financial Statements herein for additional information.

Campo Verde Solar, LLC

On April 23, 2013, Southern Power and TRE, through STR, acquired all of the outstanding membership interest of Campo Verde from First Solar, Inc., the developer of the project. Campo Verde constructed an approximately 139-MW solar photovoltaic facility in Southern California at a total cost of approximately $510 million. Commercial operation of the solar facility was declared by Campo Verde on October 25, 2013. 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 constructed an approximately 30-MW solar photovoltaic facility in North Las Vegas, Nevada. The solar facility began commercial operation on September 23, 2013 at a total estimated cost of approximately $125 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. Commercial operation of the solar facility was declared by Campo Verde on October 25, 2013.

On August 27, 2013, a subsidiary of Southern Power entered into a purchase agreement, which will result in the assumption of a PPA with Southern California Edison Company in connection with the acquisition of Adobe that is expected to occur in spring 2014. The solar facility is expected to begin commercial operation in spring 2014.

On September 3, 2013, Southern Power entered into a PPA with Cobb Electric Membership Corporation to bridge the term of a previously signed agreement for requirements service. The original agreement was scheduled to begin on January 2016. The bridge term will begin on January 1, 2014 and will terminate on December 31, 2015.

On September 19, 2013, Southern Power entered into a PPA with Duke Energy Florida, Inc. to sell 434 MWs from June 2016 through May 2021 from Plant Franklin.

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.

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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.

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 September 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 $288.7 million for the first nine months of 2013, a decrease of $157.6 million as compared to the first nine months of 2012. The decrease in cash provided from operating activities was primarily due to a decrease in bonus depreciation and cash received for ITCs primarily related to the completion of Plants Nacogdoches and Cleveland in 2012. Net cash used for investing activities totaled $637.9 million for the first nine 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 $362.7 million for the first nine months of 2013 primarily due to an increase in long-term senior notes outstanding. 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 nine months of 2013 include a $470.0 million increase in construction work in progress primarily due to the acquisition and construction of Plant Campo Verde and a $144.2 million increase in plant in service primarily due to the completion of Plant Spectrum.

Significant liability and stockholder's equity changes in the balance sheet for the first nine months of 2013 include a $120.8 million increase in notes payable to non-affiliates due to the timing of cash transactions, an $85.8 million increase in accumulated deferred income taxes primarily due to bonus depreciation, and a $22.0 million increase in accumulated deferred ITCs primarily related to Plants Campo Verde and Spectrum.

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

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debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. There are no requirements through September 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.

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 September 30, 2013 cash and cash equivalents of approximately $60 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 September 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	$	192	0.3%	$	88	0.3%	$	271

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

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

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Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	500
Below BBB- and/or Baa3	1,276

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 third quarter 2013 has not changed materially compared to 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.

154

SOUTHERN POWER 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, none of which are designated as hedges, for the three and nine months ended September 30, 2013 were as follows:

	Third Quarter 2013 Changes			Year-to-Date 2013 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	0.9		$	0.8
Contracts realized or settled	—			(1.1		)
Current period changes(a)	(0.1		)	1.1
Contracts outstanding at the end of the period, assets (liabilities), net	$	0.8		$	0.8

(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 for the three and nine months ended September 30, 2013 were immaterial. The changes are attributable to both the volume and prices of power and natural gas as follows:

	September 30, 2013			June 30, 2013		December 31, 2012
Power – net purchased or (sold)
MWHs (in thousands)	(120.9		)	—		—
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	(1.20	)	$	—	$	—
Natural gas net purchased
Commodity – million mmBtu	1.1			2.4		5.0
Commodity – weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	0.06		$	0.01	$	(0.02	)

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 nine months ended September 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. This third party hedging activity has been discontinued.

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.

155

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 September 30, 2013 were as follows:

			September 30, 2013 Fair Value Measurements
	Total		Maturity
	Fair Value		Year 1			Years 2&3		Years 4&5
	(in millions)
Level 1	$	—	$	—		$	—	$	—
Level 2	0.8		(0.8		)	0.8		0.8
Level 3	—		—			—		—
Fair value of contracts outstanding at end of period	$	0.8	$	(0.8	)	$	0.8	$	0.8

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 nine months ended September 30, 2013, Southern Power prepaid $0.4 million of long-term debt to TRE.

In March and September 2013, Southern Power issued an additional $1.7 million and $2.2 million, respectively, under a promissory note, due September 30, 2032, to TRE related to the financing of Spectrum.

In the second and third quarters of 2013, Southern Power issued an aggregate $8.7 million and $10.2 million, respectively, under a promissory note, due April 30, 2033, to TRE related to the financing of Campo Verde.

In July 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.

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.

156

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 THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS

Note		Page Number
A	Introduction	158
B	Contingencies and Regulatory Matters	159
C	Fair Value Measurements	178
D	Stockholders' Equity	183
E	Financing	184
F	Retirement Benefits	187
G	Effective Tax Rate and Unrecognized Tax Benefits	190
H	Derivatives	192
I	Acquisitions	200
J	Investments in Leveraged Leases	201
K	Segment and Related Information	202

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

157

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 September 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. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

In September 2013, Alabama Power received a 2013 decommissioning cost site study for Plant Farley. Site study cost is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning based on the 2013 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076

	(in millions)
Site study costs:
Radiated structures	$	1,362
Non-radiated structures	80
Total site study costs	$	1,442

158

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates due to changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an escalation rate of 4.5% and a trust earnings rate of 7.0%, net of fees and taxes. The next site study is expected to be conducted in 2018.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company and Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information.

Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. In September 2013, Alabama Power received a new ARO liability cost study for the decommissioning of Plant Farley based on the 2013 site study, which increased the estimated ARO liability by approximately $102 million.

As of September 30, 2013 and 2012, details of the ARO related to the decommissioning of Plant Farley included in Southern Company's and Alabama Power's Condensed Balance Sheets herein are as follows:

	2013		2012
	(in millions)
Balance at beginning of year	$	589	$	553
Liabilities incurred	—		—
Liabilities settled	—		(1		)
Accretion	29		28
Cash flow revisions	102		—
Balance at end of period	$	720	$	580

(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.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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. On September 19, 2013, a three-judge panel of the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment of the U.S. District Court for the Northern District of Alabama in favor of Alabama Power, which was based on the exclusion of the testimony of certain of the EPA's experts, and remanded the case back to the U.S. District Court for the Northern District of Alabama for further proceedings. On October 31, 2013, Alabama Power filed with the U.S. Court of Appeals for the Eleventh Circuit a petition for rehearing. In February 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the 2011 judgment and recusal of the judge in the case involving Alabama Power (including claims related to the unit co-owned by Mississippi Power), which remains pending.

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 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 2009 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 and, on May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

160

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 case is now concluded.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of September 30, 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, and the case is currently on appeal to the U.S. Court of Appeals for the Fourth Circuit.

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

161

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $52 million as of September 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. 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 the vast majority of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In 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 September 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 and licensing of an on-site dry storage facility at Plant Vogtle Units 1 and 2 is complete. The facility began operation in October 2013 and Plant Vogtle Units 1 and 2 are expected to maintain full-core discharge 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.

162

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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.

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.

Retail Regulatory Matters

Alabama Power

Rate RSE

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Rate RSE" and "Retail Regulatory Matters – Rate RSE," respectively, 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. On August 13, 2013, the Alabama PSC voted to issue a report on Rate RSE that found that Alabama Power's Rate RSE mechanism continues to be just and reasonable to customers and Alabama Power, but recommended Alabama Power modify Rate RSE as follows:

• Eliminate the provision of Rate RSE establishing an allowed range of ROE, which is currently 13.0% to 14.5%, with an adjusting point of 13.75%.

• Eliminate the provision of Rate RSE limiting Alabama Power's capital structure to an allowed equity ratio of 45%.

• Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the current Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

• Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

Substantially all other provisions of Rate RSE would remain unchanged.

On August 21, 2013, Alabama Power filed its consent to these recommendations with the Alabama PSC. The changes are effective for calendar year 2014.

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," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through Rate Certificated New

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 September 30, 2013 was $22 million as compared to $9 million at December 31, 2012. This under recovered balance at September 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 September 30, 2013 was $12 million as compared to $21 million at December 31, 2012. This under recovered balance at September 30, 2013 consists of $4 million in under recovered regulatory clause revenues and $8 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.

On August 13, 2013, the Alabama PSC approved Alabama Power's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets currently being recovered through Rate RSE. The revenue impact as a result of this revision is estimated to be $50 million in 2014; however, this petition was 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. Any unrecovered amounts associated with 2014 environmental compliance costs will be reflected in the 2015 Rate CNP Environmental filing.

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 September 30, 2013 totaled $43 million as compared to an under recovered balance of $4 million at December 31, 2012. The over recovered fuel costs at September 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 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 September 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.

Non-Nuclear Outage Accounting Order

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Rate RSE" and "Retail Regulatory Matters – Rate RSE," respectively, in Item 8 of the Form 10-K for additional information. On August 13, 2013, the Alabama PSC approved Alabama Power's petition requesting authorization to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures to be deferred and amortized are estimated to total approximately

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$70 million. This petition was made in accordance with Alabama Power's agreement with the Alabama PSC to develop a plan to keep Rate RSE factors unchanged in 2014.

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 September 30, 2013 and December 31, 2012, Georgia Power's fuel cost over recovery balance totaled $114 million and $230 million, respectively, included in current liabilities and other deferred credits and liabilities 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.

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 was 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.

Hearings on Georgia Power’s testimony were held in October 2013. In testimony filed on October 18, 2013 and October 22, 2013, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period and a 10.0% ROE that would result in excess revenues of $165 million. However, the Georgia PSC Staff also proposed no change to Georgia Power’s current retail base rates through 2014. The excess earnings in 2014 would be used to reduce rate increases in 2015 and 2016. The Georgia PSC Staff further proposed reducing the allowed ROE range to 50 basis points above and below the authorized ROE with one-third of any earnings above the range used to reduce future ECCR tariff increases and the remaining two-thirds applied to rate reductions. Georgia Power

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disagrees with the Georgia PSC Staff's positions. Hearings on the Georgia PSC Staff and intervenor testimony and Georgia Power's rebuttal hearings will be held in November 2013.

The Georgia PSC is scheduled to issue a final order in this matter in 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. On September 30, 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 IRP in order to comply with the State of Georgia's Multi-Pollutant Rule.

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, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division on September 10, 2013 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. See Note 1 to the financial statements of Georgia Power under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the fuel switch at SEGCO's generating units.

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 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.

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, and subsequently has requested Georgia PSC approval. During 2013, Georgia Power has executed four PPAs to purchase a total of 169 MWs of biomass capacity and energy from four facilities in Georgia that will commence in 2015 and end in 2035. On May 21, 2013,

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the Georgia PSC approved two of the biomass PPAs. The two wind PPAs and the two Georgia PSC-approved biomass PPAs result in contractual obligations of approximately $13 million in 2015, $47 million in 2016, $49 million in 2017, and $1.29 billion thereafter. If approved by the Georgia PSC, the additional biomass PPAs will result in contractual obligations of approximately $1 million in 2015, $11 million in 2016, $12 million in 2017, and $249 million thereafter. The four biomass PPAs are contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.

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 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. On November 1, 2013, Georgia Power filed to increase the NCCR tariff by approximately $65 million effective January 1, 2014. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2013, approximately $41 million of these 2009 and 2010 costs remained unamortized in CWIP.

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,

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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. The deadline for any further appeals expired without the petitioners seeking review.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, Georgia Power's eighth VCM report 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.

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 (February 2014 VCM report). The stipulation was approved by the Georgia PSC on September 3, 2013. As required by the stipulation, Georgia Power filed an abbreviated status update with the Georgia PSC on September 3, 2013, which reflected approximately $2.4 billion of total construction capital costs incurred through June 30, 2013. After the February 2014 VCM report, Georgia Power expects to resume filing semi-annual VCM reports in August 2014. On October 15, 2013, the Georgia PSC voted to approve Georgia Power's eighth VCM report, reflecting construction capital costs incurred, which through December 31, 2012 totaled approximately $2.2 billion.

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. On August 30, 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit on September 27, 2013. While litigation has commenced and Georgia Power intends to vigorously defend its positions, Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

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

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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 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.

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.

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.

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 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.

On November 4, 2013, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2014. The net effect of the approved changes is a $65.2 million increase in annual revenue for 2014.

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.

Under recovered fuel costs at September 30, 2013 totaled $10.0 million which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. The under recovered fuel cost balance

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included approximately $26.6 million received during the third quarter 2013 as a result of a payment from one of Gulf Power's fuel vendors pursuant 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 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.

Under recovered purchased power capacity costs at September 30, 2013 totaled $6.4 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.

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.

Under recovered environmental costs at September 30, 2013 totaled $7.9 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.

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.

Under recovered energy conservation costs at September 30, 2013 totaled $5.7 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.

Mississippi Power

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 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.

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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 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 September 30, 2013, total project expenditures were $278.3 million, of which Mississippi Power's portion was $139.2 million, excluding AFUDC of $6.6 million. The ultimate outcome of this matter cannot be determined at this time.

On August 13, 2013, the Mississippi PSC approved Mississippi Power’s 2013 ECO Plan filing which proposed no change in rates.

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.

On March 5, 2013, the Mississippi PSC approved a $35.5 million decrease of the annual retail fuel cost recovery factor, or 4.7% of total 2012 retail revenue, effective March 19, 2013.

At September 30, 2013, the amount of over recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $21.8 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 September 30, 2013, the amount of over recovered wholesale MRA and MB fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $9.1 million and $0.6 million, respectively, compared to $19.0 million and $2.1 million, respectively, at December 31, 2012. In addition, at September 30, 2013, the amount of under recovered MRA emissions allowance cost included on Mississippi Power's Condensed Balance Sheets herein was $3.4 million compared to $0.4 million at December 31, 2012. Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel 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 June 4, 2013, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2013, which included 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.

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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 September 30, 2013, the balance in the storm reserve was $59.2 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

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. 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 Construction Schedule and 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. The Kemper IGCC was originally scheduled to be placed in service in May 2014.

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On October 28, 2013, Mississippi Power revised the scheduled in-service date for the Kemper IGCC to the fourth quarter 2014 primarily as the result of lower-than-planned installation levels for piping as well as abnormally wet weather. Also on October 28, 2013, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately $4.02 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, $426 million of AFUDC, and $101 million of certain general exceptions. Additionally, Mississippi Power expects to defer $91 million of non-capital Kemper IGCC-related costs to a regulatory asset.

Mississippi Power recorded pre-tax charges to income for estimated probable losses of $78.0 million ($48.2 million after tax) and $462.0 million ($285.3 million after tax) in 2012 and the first quarter 2013, respectively, as a result of additional cost pressures, including labor costs, piping and other material costs, engineering and support costs, and productivity decreases. Mississippi Power recorded a pre-tax charge to income for an estimated probable loss of $450.0 million ($277.9 million after tax) in the second quarter 2013 as a result of 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 recorded a pre-tax charge to income for an estimated probable loss of $150.0 million ($92.6 million after tax) in the third quarter 2013 primarily as a result of the schedule extension. 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, $450.0 million ($277.9 million after tax) in the second quarter 2013, and $150.0 million ($92.6 million after tax) in the third quarter 2013.

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.

Mississippi Power could experience further construction cost increases and/or schedule extensions 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 further schedule extensions 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 and could result in the loss of certain tax benefits related to bonus depreciation. 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 September 30, 2013, Mississippi Power had incurred total costs of $3.61 billion on the Kemper IGCC. These costs include$2.94 billion for the portion of the Kemper IGCC subject to the construction cost cap, $223.9 million for the lignite mine and equipment, $91.9 million for the CO₂ pipeline facilities, $232.2 million of AFUDC, and $67.6 million of certain general exceptions. Also included in this total is $55.2 million of certain regulatory assets. Of this total, $2.41 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.14 billion), $59.1 million in other regulatory assets, and $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, subject to review of such costs by the Mississippi PSC. This includes deferred costs associated with the generation resource planning, evaluation, and screening activities. The amortization period for any such costs approved for recovery 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 (excluding AFUDC) 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 and is expected to be revised later in 2013 in connection with the revised in-service date); (4) the Mississippi PSC's decision on the Seven-Year Rate Plan within four months of that filing (which, given the expected revision, is now expected to occur in the first half of 2014); (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 of up to $1 billion 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 the second quarter 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 October 15, 2013 revised 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 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 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.

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 on January 1, 2014,

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which collectively are designed to collect $156 million annually beginning in 2014. Amounts collected through these rates are being recorded as a regulatory liability to be used to mitigate customer rate impacts when the Kemper IGCC is placed in service. As of September 30, 2013, $62.0 million had been collected and recorded as a regulatory liability 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.

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 contemplates the continued accrual of AFUDC through the in-service date, subject to approval by the Mississippi PSC.

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 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. 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 regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan 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 assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of 2012 (ATRA), which currently requires that the Kemper IGCC be placed in service in 2014. Mississippi Power plans to amend the Seven-Year Rate Plan described above to reflect changes including the revised in-service date, the change in expected benefits relating to tax credits, and other tax matters, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. Mississippi Power does not expect these revisions to change the total customer rate impacts contemplated in the Seven-Year Rate Plan. See "Tax Incentives" herein for additional information relating to tax credits and bonus depreciation.

On October 15, 2013, the Mississippi PSC issued a revised 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 the second quarter 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

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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.

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 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.

Nitrogen Supply Agreement

On September 19, 2013, Mississippi Power entered into an agreement to sell the air separation unit for the Kemper IGCC for $79.0 million and also entered into a 20-year nitrogen supply agreement, whereby nitrogen will be supplied to Mississippi Power for the gasification process. The nitrogen supply agreement resulted in a capital lease obligation for Mississippi Power at inception of $82.9 million with an annual interest rate of 4.9%. Assets acquired under capital leases are recorded on Southern Company's and Mississippi Power’s Condensed Balance Sheets herein as utility plant in service, and the related obligations are classified as long-term debt and securities due within one year.

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 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. On May 15, 2013, the IRS notified Mississippi Power that no additional tax credits under the Internal Revenue Code Section 48A Phase III were allocated to the Kemper IGCC. As a result of the schedule extension for the Kemper IGCC, the Phase I credits will be recaptured and Mississippi Power has reclassified the recaptured credits as a reduction of prepaid income taxes on Southern

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Company's and Mississippi Power’s Condensed Balance Sheets herein. Through September 30, 2013, Mississippi Power had recorded tax benefits totaling $276.4 million for the remaining Phase II credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the tax credits will be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.

On January 2, 2013, the 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.

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

Other Matters

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 4, 2013. Plant Bowen Unit 2 (approximately 700 MWs) remains offline pending completion of the 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 September 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 September 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	$	—	$	11	$	—	$	11
Interest rate derivatives	—		7		—		7
Nuclear decommissioning trusts(a)	553		844		—		1,397
Cash equivalents	465		—		—		465
Other investments	9		—		15		24
Total	$	1,027	$	862	$	15	$	1,904
Liabilities:
Energy-related derivatives	$	—	$	84	$	—	$	84
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Nuclear decommissioning trusts:(b)
Domestic equity	343		74		—		417
Foreign equity	32		62		—		94
U.S. Treasury and government agency securities	—		27		—		27
Corporate bonds	—		101		—		101
Mortgage and asset backed securities	—		23		—		23
Other	—		10		—		10
Cash equivalents	351		—		—		351
Total	$	726	$	300	$	—	$	1,026
Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Fair Value Measurements Using
As of September 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	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts:(b) (c)
Domestic equity	178		1		—		179
Foreign equity	—		125		—		125
U.S. Treasury and government agency securities	—		88		—		88
Municipal bonds	—		64		—		64
Corporate bonds	—		133		—		133
Mortgage and asset backed securities	—		116		—		116
Other	—		19		—		19
Total	$	178	$	548	$	—	$	726
Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	29
Gulf Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Cash equivalents	16		—		—		16
Total	$	16	$	3	$	—	$	19
Liabilities:
Energy-related derivatives	$	—	$	25	$	—	$	25
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Liabilities:
Energy-related derivatives	$	—	$	14	$	—	$	14
Southern Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents	60		—		—		60
Total	$	60	$	2	$	—	$	62
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 September 30, 2013, approximately $14 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

As of September 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 September 30, 2013:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	125	None	Monthly	5 days
Corporate bonds - commingled funds	4		None	Daily	1 to 3 days
Equity - commingled funds	62		None	Daily/Monthly	Daily/7 days
Other - commingled funds	19		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	104		None	Daily	15 days
Cash equivalents:
Money market funds	465		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	62		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	104		None	Daily	15 days
Cash equivalents:
Money market funds	351		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	125		None	Monthly	5 days
Corporate bonds - commingled funds	4		None	Daily	Not applicable
Other - commingled funds	19		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	16		None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	60		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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 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 nine months ended September 30, 2013, the fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $60 million and $112 million, respectively, at Southern Company. For the three and nine months ended September 30, 2013, Alabama Power recorded an increase in fair value of $33 million and $76 million, respectively, as an increase in regulatory liabilities. For the three and nine months ended September 30, 2013, Georgia Power recorded an increase in fair value of $27 million and $36 million, respectively, as a reduction of its regulatory asset related to AROs.

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 September 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	$	22,194	$	22,822
Alabama Power	$	6,179	$	6,536
Georgia Power	$	9,222	$	9,400
Gulf Power	$	1,246	$	1,293
Mississippi Power	$	2,140	$	2,108
Southern Power	$	1,628	$	1,667

182

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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.

(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 September 30, 2013	Three Months Ended September 30, 2012	Nine Months Ended September 30, 2013	Nine Months Ended September 30, 2012
	(in millions)
As reported shares	878	876	874	872
Effect of options and performance share award units	3	7	5	8
Diluted shares	881	883	879	880

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 16 million and 1 million for the three and nine months ended September 30, 2013, respectively, and were immaterial for the three and nine months ended September 30, 2012.

183

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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
	(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	—	—		1,230			—		1,230
Other comprehensive income (loss)	—	—		11			—		11
Treasury stock re-issued	—	1,956		89			—		89
Stock issued	12,046	—		484			49		533
Stock repurchased, at cost	—	—		(19		)	—		(19		)
Cash dividends on common stock	—	—		(1,314		)	—		(1,314		)
Other	—	(30	)	—			—		—
Balance at September 30, 2013	889,849	(8,109	)	$	18,778		$	756	$	19,534
Balance at December 31, 2011	865,664	(539	)	$	17,578		$	707	$	18,285
Net income after dividends on preferred and preference stock	—	—		1,967			—		1,967
Other comprehensive income (loss)	—	—		(1		)	—		(1		)
Stock issued	11,586	—		479			—		479
Stock repurchased, at cost	—	(2,567	)	(117		)	—		(117		)
Cash dividends on common stock	—	—		(1,267		)	—		(1,267		)
Other	—	(38	)	—			—		—
Balance at September 30, 2012	877,250	(3,144	)	$	18,639		$	707	$	19,346

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. There were no repurchases under this program in the first nine 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.

184

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The following table outlines the committed credit arrangements by company as of September 30, 2013:

	Expires(a)														Executable Term Loans				Due Within One Year
Company	2013		2014		2015		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	1		268		35		—		1,000		1,304		1,304		53		—		53		146
Georgia Power	—		—		—		150		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		90		—		165		—		275		275		45		—		45		65
Mississippi Power	15		120		—		165		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		486		—		—		—		—
Other	—		75		25		—		—		100		100		25		—		25		50
Total	$	36	$	553	$	60	$	480	$	4,100	$	5,229	$	5,201	$	148	$	40	$	188	$	331

(a) No credit arrangements expire in 2017.

As reflected in the table above, during the first nine 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 to capitalization 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.

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.

Financing Activities

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

Company(a)	Senior  Note Issuances		Senior  Note Redemptions and  Maturities		Revenue Bond Issuances		Revenue Bond Redemptions and Maturities		Other Long-Term Debt Issuances		Other  Long-Term Debt Redemptions
					(in millions)
Southern Company	$	500	$	—	$	—	$	—	$	—	$	—
Georgia Power	850		1,250		89		89		—		—
Gulf Power	90		90		—		—		—		—
Mississippi Power	—		—		31		83		475		125
Southern Power	300		—		—		—		23		—
Other	—		50		—		—		—		—
Total	$	1,740	$	1,390	$	120	$	172	$	498	$	125

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

185

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Southern Company

In August 2013, Southern Company issued $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes due September 1, 2018. The proceeds were used to pay a portion of Southern Company’s outstanding short-term indebtedness and for other general corporate purposes.

Georgia Power

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 these sales 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 (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 1997.

In August 2013, Georgia Power issued $200 million aggregate principal amount of Series 2013C Floating Rate Senior Notes due August 15, 2016. The proceeds were used to repay at maturity a portion of $100 million aggregate principal amount outstanding of Georgia Power's Series Q 4.90% Senior Notes due September 15, 2013 and a portion of $500 million aggregate principal amount outstanding of Georgia Power's Series 2010D 1.30% Senior Notes due September 15, 2013.

In August 2013, the Development Authority of Bartow County issued $71.7 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013 due August 1, 2043 for the benefit of Georgia Power. The proceeds were used to redeem, in September 2013, $24.9 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1996 and $46.8 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1998.

Gulf Power

In June 2013, Gulf Power issued 500,000 shares of Series 2013A 5.60% Preference Stock and realized proceeds of $50 million. Gulf Power also 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 90-day 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.

Mississippi Power

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. In September 2013, Mississippi Power amended the bank loan, which extended the maturity date to 2015. 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 fourtwo-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 principal amounts, and proceeds were used for working capital and other general corporate purposes, including

186

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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.

In July 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 September 2013, Mississippi Power entered into a two-year floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $125 million aggregate principal amount and proceeds were used to repay at maturity a two-year floating rate bank loan in the aggregate principal amount of $125 million.

Southern Power

In March and September 2013, Southern Power issued an additional $1.7 million and $2.2 million, respectively, under a promissory note, due September 30, 2032, to Turner Renewable Energy, LLC (TRE) related to the financing of Spectrum.

In the second and third quarters of 2013, Southern Power issued an aggregate $8.7 million and $10.2 million, respectively, under a promissory note, due April 30, 2033, to TRE related to the financing of Campo Verde.

In July 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.

(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.

187

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Components of the net periodic benefit costs for the three and nine months ended September 30, 2013 and 2012 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2013
Service cost	$	58		$	12		$	17		$	3		$	3
Interest cost	97			23			35			4			5
Expected return on plan assets	(151		)	(39		)	(54		)	(6		)	(7		)
Amortization:
Prior service costs	7			2			3			—			1
Net (gain)/loss	50			13			19			2			2
Net cost	$	61		$	11		$	20		$	3		$	4
Nine Months Ended September 30, 2013
Service cost	$	174		$	39		$	52		$	8		$	8
Interest cost	291			69			104			13			14
Expected return on plan assets	(452		)	(117		)	(160		)	(19		)	(20		)
Amortization:
Prior service costs	20			5			8			1			1
Net (gain)/loss	150			39			56			6			7
Net cost	$	183		$	35		$	60		$	9		$	10
Three Months Ended September 30, 2012
Service cost	$	49		$	11		$	15		$	2		$	2
Interest cost	98			23			35			5			5
Expected return on plan assets	(145		)	(40		)	(56		)	(7		)	(6		)
Amortization:
Prior service costs	8			2			3			—			—
Net (gain)/loss	24			6			9			1			2
Net cost	$	34		$	2		$	6		$	1		$	3
Nine Months Ended September 30, 2012
Service cost	$	148		$	33		$	45		$	7		$	7
Interest cost	295			70			106			13			14
Expected return on plan assets	(436		)	(121		)	(166		)	(20		)	(18		)
Amortization:
Prior service costs	23			5			9			1			1
Net (gain)/loss	71			18			25			3			3
Net cost	$	101		$	5		$	19		$	4		$	7

188

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2013
Service cost	$	6		$	2		$	3		$	—		$	—
Interest cost	18			5			8			1			1
Expected return on plan assets	(14		)	(6		)	(7		)	(1		)	—
Amortization:
Transition obligation	2			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	3			—			2			—			—
Net cost	$	16		$	2		$	7		$	—		$	1
Nine Months Ended September 30, 2013
Service cost	$	18		$	5		$	6		$	1		$	1
Interest cost	55			14			24			2			3
Expected return on plan assets	(42		)	(18		)	(19		)	(1		)	(1		)
Amortization:
Transition obligation	4			—			3			—			—
Prior service costs	3			3			—			—			—
Net (gain)/loss	9			1			6			—			—
Net cost	$	47		$	5		$	20		$	2		$	3
Three Months Ended September 30, 2012
Service cost	$	5		$	1		$	2		$	—		$	—
Interest cost	21			6			8			1			1
Expected return on plan assets	(15		)	(6		)	(7		)	—			—
Amortization:
Transition obligation	2			—			2			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	2			—			1			—			—
Net cost	$	16		$	2		$	6		$	1		$	1
Nine Months Ended September 30, 2012
Service cost	$	16		$	4		$	5		$	1		$	1
Interest cost	63			17			27			3			3
Expected return on plan assets	(45		)	(18		)	(21		)	(1		)	(1		)
Amortization:
Transition obligation	7			1			5			—			—
Prior service costs	3			3			—			—			—
Net (gain)/loss	5			—			3			—			—
Net cost	$	49		$	7		$	19		$	3		$	3

189

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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 33.9% for the nine months ended September 30, 2013 compared to 35.3% for the corresponding period in 2012. The decrease was primarily due to an increase in non-taxable AFUDC equity at Mississippi Power and increased investment tax credits at Southern Power, combined with lower net income for Southern Company as a whole. The decrease was partially offset by a decrease in state income tax credits and a settlement with the IRS in 2012 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 39.3% for the nine months ended September 30, 2013 compared to 38.8% for the corresponding period in 2012. The increase was primarily due to the recognition in 2012 of tax benefits related to a settlement with the IRS related to the production activities deduction.

Georgia Power

Georgia Power's effective tax rate was 38.0% for the nine months ended September 30, 2013 compared to 35.8% for the corresponding period in 2012. The increase was due to an increase in non-deductible book depreciation, a decrease in state income tax credits, a settlement with the IRS in 2012 related to the production activities deduction, and a decrease in non-taxable AFUDC equity.

Gulf Power

Gulf Power's effective tax rate was 37.6% for the nine months ended September 30, 2013 compared to 37.3% for the corresponding period in 2012.

Mississippi Power

Mississippi Power's effective tax rate was (42.1)% for the nine months ended September 30, 2013 compared to 26.7% 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 20.5% for the nine months ended September 30, 2013 compared to 34.4% for the corresponding period in 2012. The decrease was primarily due to an increase in investment tax credits.

190

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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	3			—			—			—			—			2
Tax positions from prior periods	(66		)	(31		)	(23		)	(5		)	(2		)	(3		)
Balance as of September 30, 2013	$	7		$	—		$	—		$	—		$	4		$	2

The tax positions from prior 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 September 30, 2013			As of December 31, 2012
		Southern Company
	(in millions)
Tax positions impacting the effective tax rate		$	7	$	5
Tax positions not impacting the effective tax rate		—		65
Balance of unrecognized tax benefits		$	7	$	70

The tax positions impacting the effective tax rate primarily relate to state income tax credits. 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 September 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 settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

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 deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued final tangible property regulations. Southern Company is currently reviewing this new guidance. The ultimate outcome

191

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

of this matter cannot be determined at the time; however, these regulations are 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.

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.

192

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 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	267	2018	2017
Alabama Power	68	2017	—
Georgia Power	67	2017	—
Gulf Power	85	2018	—
Mississippi Power	46	2017	—
Southern Power	1	—	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 8 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 1 million mmBtu for Gulf 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 September 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 September 30, 2013, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Interest Rate Paid		Hedge Maturity Date	Fair Value Gain (Loss) September 30, 2013
	(in millions)						(in millions)
Fair value hedges of existing debt
Southern Company	$	350	4.15%	3-month LIBOR  + 1.96%	(a)	May 2014	$	7

(a) Weighted average

The estimated pre-tax gains (losses) that will be reclassified from AOCI to interest expense for the next 12-month period ending September 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

193

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 September 30, 2013, the fair value of the foreign currency derivatives outstanding was immaterial.

Derivative Financial Statement Presentation and Amounts

At September 30, 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at September 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	$	6	$	2	$	1	$	2	$	1
Other deferred charges and assets	3		1		1		1		—
Total derivatives designated as hedging instruments for regulatory purposes	$	9	$	3	$	2	$	3	$	1	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	2		—		—		—		—		2
Total asset derivatives	$	18	$	3	$	2	$	3	$	1	$	2

194

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Liability Derivatives at September 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	$	48	$	9	$	19	$	13	$	7
Other deferred credits and liabilities	35		6		10		12		7
Total derivatives designated as hedging instruments for regulatory purposes	$	83	$	15	$	29	$	25	$	14	N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	84	$	15	$	29	$	25	$	14	$	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

195

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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.

196

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Derivative Contracts at September 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)	$	11		$	3		$	2		$	3		$	1		$	2
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(2		)	(3		)	(1		)	(1		)
Net energy-related derivative assets	$	1		$	—		$	—		$	—		$	—		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	84		$	15		$	29		$	25		$	14		$	1
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(2		)	(3		)	(1		)	(1		)
Net energy-related derivative liabilities	$	74		$	12		$	27		$	22		$	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

(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.

197

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 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 September 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	$	(48	)	$	(9	)	$	(19	)	$	(13	)	$	(7	)
Other regulatory assets, deferred	(35		)	(6		)	(10		)	(12		)	(7		)
Other regulatory liabilities, current	6			2			1			2			1
Other regulatory liabilities, deferred (a)	3			1			1			1			—
Total energy-related derivative gains (losses)	$	(74	)	$	(12	)	$	(27	)	$	(22	)	$	(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 nine months ended September 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 nine months ended September 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 September 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 all registrants.

198

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the nine months ended September 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)
						Statements of Income Location	Amount
	2013		2012				2013			2012
	(in millions)						(in millions)
Southern Company
Interest rate derivatives	$	—	$	(16	)	Interest expense, net of amounts capitalized	$	(12	)	$	(12	)
Alabama Power
Interest rate derivatives	$	—	$	(15	)	Interest expense, net of amounts capitalized	$	(2	)	$	—
Southern Power
Interest rate derivatives	$	—	$	—		Interest expense, net of amounts capitalized	$	(6	)	$	(8	)

For the nine months ended September 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 nine months ended September 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 nine months ended September 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. This third party hedging activity has been discontinued.

For the three and nine months ended September 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 September 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	$	5	$	5	$	7	$	3	$	—

At September 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

199

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

Adobe Solar, LLC

On August 27, 2013, Southern Power and TRE, through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, entered into a purchase agreement with Sun Edison, LLC, the developer of the project, which provides for the acquisition of all of the outstanding membership interests of Adobe Solar, LLC (Adobe) by STR. Adobe is constructing an approximately 20-MW solar generating facility in Kern County, California. The solar facility is expected to begin commercial operation in spring 2014. The output of the plant is contracted under a 20-year PPA with Southern California Edison Company, which is expected to begin in spring 2014. The acquisition is in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Adobe is expected to occur in spring 2014 and the purchase price is expected to be approximately $100 million.

The completion of the acquisition is subject to Sun Edison, LLC achieving certain construction and project milestones by certain dates and various customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

Campo Verde Solar, LLC

On April 23, 2013, Southern Power and TRE, through 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 constructed an approximately 139-MW solar photovoltaic facility in Southern California. Commercial operation of the solar facility was declared by Campo Verde on October 25, 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 began on the commercial operation date. 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 preliminary asset allocation is under evaluation by management; therefore, the allocation of the purchase price to individual assets has not been finalized. Under an engineering, procurement, and construction agreement (Construction Agreement), an additional $328.7 million has been paid to a subsidiary of First Solar, Inc. (Construction Contractor) for the 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

200

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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.

(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.

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 through 2015 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.

201

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(K) SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $97 million and $264 million for the three and nine months ended September 30, 2013, respectively, and $112 million and $330 million for the three and nine months ended September 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 inter-segment 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 September 30, 2013:
Operating revenues	$	4,744	$	365	$	(104	)	$	5,005	$	35		$	(23	)	$	5,017
Segment net income (loss)(a)(b)	765		85		—			850		(1		)	3			852
Nine Months Ended September 30, 2013:
Operating revenues	$	12,430	$	975	$	(285	)	$	13,120	$	108		$	(68	)	$	13,160
Segment net income (loss)(a)(c)	1,099		142		—			1,241		(12		)	1			1,230
Total assets at September 30, 2013	$	59,732	$	4,449	$	(153	)	$	64,028	$	1,090		$	(421	)	$	64,697
Three Months Ended September 30, 2012:
Operating revenues	$	4,794	$	355	$	(116	)	$	5,033	$	36		$	(20	)	$	5,049
Segment net income (loss)(a)	908		68		1			977		1			(2		)	976
Nine Months Ended September 30, 2012:
Operating revenues	$	12,232	$	894	$	(338	)	$	12,788	$	109		$	(63	)	$	12,834
Segment net income (loss)(a)	1,797		144		—			1,941		30			(4		)	1,967
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 September 30, 2013 includes a $150 million pre-tax charge ($93 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 nine months ended September 30, 2013 includes $1.1 billion in pre-tax charges ($704 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 September 30, 2013	$	4,319	$	520	$	166	$	5,005
Three Months Ended September 30, 2012	4,379		497		157		5,033
Nine Months Ended September 30, 2013	$	11,237	$	1,406	$	477	$	13,120
Nine Months Ended September 30, 2012	11,068		1,261		459		12,788

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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 and the Form 10-K/A 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 and the Form 10-K/A.

Item 6.    Exhibits.

(4) Instruments Describing Rights of Security Holders, Including Indentures
Southern Company
(a)1	-	Eighth Supplemental Indenture to Senior Note Indenture dated as of August 27, 2013, providing for the issuance of the Series 2013A 2.45% Senior Notes due September 1, 2018. (Designated in Form 8-K dated August 21, 2013, File No. 1-3526, as Exhibit 4.2.)
Georgia Power
(c)1	-	Fifty-second Supplemental Indenture to Senior Note Indenture dated as of August 16, 2013, providing for the issuance of the Series 2013C Floating Rate Senior Notes due August 15, 2016. (Designated in Form 8-K dated August 12, 2013, File No. 1-6468, as Exhibit 4.2.)
Southern Power
(f)1	-	Fifth Supplemental Indenture to the Senior Note Indenture dated as of July 16, 2013, providing for the issuance of the Series 2013A 5.25% Senior Notes due July 15, 2043. (Designated in Form 8-K dated July 10, 2013, File No. 333-98553, as Exhibit 4.4.)
(10) Material Contracts
Alabama Power
(b)1	-	Retention Award Agreement between Alabama Power and Steven R. Spencer effective July 15, 2013.
(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.)

203

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. (Designated in Form 10-Q for the quarter ended June 30, 2013, File No. 001-11229 as Exhibit 24(e)2 and incorporated herein by reference.)
Southern Power
(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2012, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)
(f)2	-	Power of Attorney for William C. Grantham.
(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.

204

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.
(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.
(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

205

THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	THE SOUTHERN COMPANY
By	Thomas A. Fanning
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Art P. Beattie
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 6, 2013

206

ALABAMA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	ALABAMA POWER COMPANY
By	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: November 6, 2013

207

GEORGIA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	GEORGIA POWER COMPANY
By	W. Paul Bowers
	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: November 6, 2013

208

GULF POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	GULF POWER COMPANY
By	S. W. Connally, Jr.
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Richard S. Teel
	Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 6, 2013

209

MISSISSIPPI POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	MISSISSIPPI POWER COMPANY
By	G. Edison Holland, Jr.
	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: November 6, 2013

210

SOUTHERN POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	SOUTHERN POWER COMPANY
By	Oscar C. Harper IV
	President and Chief Executive Officer
	(Principal Executive Officer)
By	William C. Grantham
	Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 6, 2013

211

EX-10.B1

Exhibit 10(b)1

RETENTION AWARD AGREEMENT

THIS RETENTION AWARD AGREEMENT (Agreement), made and entered into by and between     ALABAMA POWER COMPANY (Company) and STEVEN R. SPENCER (Employee), shall be effective as of July 15, 2013 (Effective Date).

1.    Award Amount. As approved by the Compensation and Management Succession Committee of the Board of Directors of The Southern Company at its meeting held on July 15, 2013, Employee is awarded under the Agreement the number of Restricted Stock Units (RSUs) with a value of One Million One Hundred Eighty Two Thousand Six Hundred Sixty Five Dollars and No Cents ($1,182,665.00) on the Effective Date and shall become vested in the RSUs, provided Employee is actively employed with the Company or an affiliate of the Company on December 31, 2015 (Vesting Date).        

The Award under this Paragraph 1 is an award of time-based RSUs under the terms of the Southern Company Omnibus Incentive Compensation Plan and therefore governed by the terms of that plan. The deemed dividends associated with the RSUs shall be credited and treated as reinvested in additional RSUs until the Award is paid in accordance with Paragraph 2.

2.    Timing and Form of Payment of Retention Amount.

(a)    Generally. Unless modified by the provisions set forth in Paragraphs 2(b)-2(e), the vested amount shall be paid in shares of Common Stock to Employee in a lump sum within 30 days following the Vesting Date (Scheduled Payment Date), less any amounts required to be withheld as set forth in Paragraph 7 below.

(b)    Death. If Employee dies while in active service prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the Award. The amount vested under this Paragraph 2(b) shall be paid on the earlier of (i) the Scheduled Payment Date or (ii) within 30 days following the Employee's date of death. Employee shall designate his beneficiary(ies) in the beneficiary designation form set forth in Exhibit 1 to the Agreement.

(c)    Disability. If Employee separates from service on account of becoming totally disabled as defined under the Company's long term disability plan prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the Award. The amount vested under this Paragraph 2(c) shall be paid on the earlier of (i) the Scheduled Payment Date or (ii) within 30 days following the date Employee separates from service on account of disability.

(d)    Involuntary Termination. If Employee separates from service on account of being involuntarily terminated for reasons other than Cause prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the Award. The amount vested under this Paragraph 2(d) shall be paid on the earlier of

1

(i) the Scheduled Payment Date or (ii) within 30 days following the date the Employee separates from service.

(e)    Voluntary Termination or Termination for Cause. If Employee voluntarily terminates employment prior to the Vesting Date or is terminated for Cause solely as determined by the Company prior to the Scheduled Payment Date, Employee forfeits the Award and all amounts which could have been paid under the Agreement. For purposes of the Agreement, Cause or Termination for Cause shall include the following conditions:

(1)    Failure to Appropriately Discharge Duties. Employee willfully neglects or refuses to discharge his duties of employment, refuses to comply with any lawful or reasonable instructions given to him by the Company without reasonable excuse or knowingly violates the law in the course of the performance of his duties of employment or

(2)     Gross Misconduct. Employee is guilty of gross misconduct. For the purposes of the Agreement, the following acts shall constitute gross misconduct as solely determined by the Company:

(i)    Anyact involving fraud or dishonesty against the Company or any of its affiliates;

(ii)    The carrying out of any activity or the making of any statement which disparages the Company or any of its affiliates or which would prejudice and/or reduce the good name and standing of the Company or any of its affiliates or would bring any one of these into contempt, ridicule or would reasonably shock or offend any community in which these companies are located;

(iii)    Final conviction of any felony or of any crime involving moral turpitude, dishonesty, breach of trust or unethical business conduct; or

(iv)    Violation of any Company policy that would warrant immediate termination of employment.

(e)    Delaying Payment. As set forth in Section 10 of the Agreement, the Award earned, vested and paid hereunder is a Short-Term Deferral and therefore not subject to the delayed payment provisions of Section 409A of the Internal Revenue Code of 1986, as amended (Code), and the regulations promulgated thereunder. Notwithstanding the foregoing, if Employee is a “specified employee” within the meaning of Section 409A of the Code as of the date of his separation from service, then payment of any amounts under the Agreement shall be deferred for six months after the date of his separation from service if it is determined that such delay is required by Section 409A of the Code.

3.    Amendment and/or Termination of the Agreement. The Agreement terminates when all amounts have been paid or forfeited pursuant to Paragraph 2. Notwithstanding the

2

preceding sentence, the Employee and the Company may mutually agree to amend or terminate the Agreement prior to the Vesting Date only by written agreement signed by each party.

4.    Confidentiality. Employee represents and agrees that he will keep all terms and provisions of the Agreement completely confidential, except for possible disclosures to his legal and financial advisors and his spouse or to the extent required by law.

5.    Assignability. Neither Employee, his estate, his beneficiaries nor his legal representatives shall have any rights to commute, sell, assign, transfer or otherwise convey the right to receive any payments hereunder, which payments and the rights thereto are expressly declared to be nonassignable and nontransferable. Any attempt to assign or transfer the right to payments under the Agreement shall be void and have no effect.

6.    No Effect on Other Arrangements. It is expressly understood and agreed that any payments made in accordance with the Agreement are in addition to any other benefits or compensation to which Employee may be entitled or for which he may be eligible, whether funded or unfunded, by reason of his employment with the Company.

7.     Tax Withholding and Implications. To the extent permitted under Section 409A of the Code, there shall be deducted from the vested Award the number of shares of Common Stock necessary to cover the amount of any tax required by any governmental authority to be withheld from the Employee and paid over by the Company or an affiliate of the Company to such governmental authority for the account of the Employee. The Company makes no representations or guarantees regarding the tax implications of the Agreement and advises Employee to consult with his attorney and/or tax advisor regarding the tax implications of the Agreement.

8.    Compensation. Any compensation paid to Employee pursuant to the Agreement shall not be considered "compensation" as the term is defined in The Southern Company Employee Savings Plan, or "earnings" as such term is defined in The Southern Company Pension Plan. Payments to Employee shall not be considered wages, salaries or compensation under any other Company-sponsored employee benefit or compensation plan or program, unless the explicit terms of such plan or program provide otherwise.

9.    No Guarantee of Employment. No provision of the Agreement shall be construed to affect in any manner the existing rights of the Company to suspend, terminate, alter or modify, whether or not for Cause, the Employee’s employment relationship with the Company.

10.    Short-Term Deferral. The parties agree that the terms and provisions of the Agreement will be construed and interpreted to the maximum extent permitted in order to satisfy the requirements of a Short-Term Deferral under Section 409A of the Code, and the regulations promulgated thereunder.

SIGNATURES ARE ON FOLLOWING PAGE

3

The Agreement has been executed by the parties first listed above, this 11th day of June 2013.

COMPANY

By:     /s/Charles D. McCrary

Its: Chairman, President, and Chief Executive Officer

EMPLOYEE

/s/Steven R. Spencer

4

EX-24.F2

Exhibit 24(f)2

William C. Grantham Vice President, and Chief Financial Officer Southern Power 30 Ivan Allen Jr. Blvd. NW
Atlanta, GA 30308

October 8, 2013

Ms. Janet J. Hodnett Southern Power Company 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308 Ms. Melissa K. Caen Southern Company Services, Inc. 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308

Ladies:

As an officer of Southern Power Company, I hereby make, constitute, and appoint you my true and lawful Attorney in my name, place and stead, to sign and cause to be filed with the Securities and Exchange Commission (1) this Company's Quarterly Reports on Form 10-Q during 2013, and (2) any necessary or appropriate amendment or amendments to any such reports and to this Company’s Annual Report on Form 10-K for the year ended December 31, 2012, each such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/William C. Grantham

William C. Grantham

EX-31.A1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Thomas A. Fanning, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

EX-31.A2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Art P. Beattie, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Charles D. McCrary, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/Charles D. McCrary

Charles D. McCrary

President and Chief Executive Officer

EX-31.B2

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer

and Treasurer

EX-31.C1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, W. Paul Bowers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 6, 2013

/s/W. Paul Bowers 

W. Paul Bowers

President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, W. Ron Hinson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer,

Treasurer and Comptroller

EX-31.D1

Exhibit 31(d)1

GULF POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, S. W. Connally, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

President and Chief Executive Officer

EX-31.D2

Exhibit 31(d)2

GULF POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Richard S. Teel, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/Richard S. Teel

Richard S. Teel

Vice President and Chief Financial Officer

EX-31.E1

Exhibit 31(e)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, G. Edison Holland, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/G. Edison Holland, Jr.

G. Edison Holland, Jr.

President and Chief Executive Officer

EX-31.E2

Exhibit 31(e)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013 

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

EX-31.F1

Exhibit 31(f)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Oscar C. Harper IV, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 6, 2013

/s/Oscar C. Harper IV

Oscar C. Harper IV

President and Chief Executive Officer

EX-31.F2

Exhibit 31(f)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, William C. Grantham, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 6, 2013

/s/William C. Grantham

William C. Grantham

Vice President, Treasurer and Chief

Financial Officer

EX-32.A

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2013, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2013, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2013, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and

Chief Financial Officer

November 6, 2013

EX-32.B

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2013, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2013, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2013, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/Charles D. McCrary

Charles D. McCrary

President and Chief Executive Officer

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President,

Chief Financial Officer and Treasurer

November 6, 2013

EX-32.C

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2013, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2013, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2013, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/W. Paul Bowers

W. Paul Bowers

President and Chief Executive Officer

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer,

Treasurer and Comptroller

November 6, 2013

EX-32.D

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended September 30, 2013, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended September 30, 2013, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended September 30, 2013, fairly presents, in all material respects, the financial condition and results of operations of Gulf Power Company.

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

President and Chief Executive Officer

/s/Richard S. Teel

Richard S. Teel

Vice President and Chief Financial Officer

November 6, 2013

EX-32.E

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2013, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2013, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2013, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/G. Edison Holland, Jr.

G. Edison Holland, Jr.

President and Chief Executive Officer

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

November 6, 2013

EX-32.F

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2013, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2013, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2013, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Oscar C. Harper IV

Oscar C. Harper IV

President and Chief Executive Officer

/s/William C. Grantham

William C. Grantham

Vice President, Treasurer and

Chief Financial Officer

November 6, 2013

XML

Acquisitions

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

ACQUISITIONS

ACQUISITIONS

Adobe Solar, LLC

On August 27, 2013, Southern Power and TRE, through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, entered into a purchase agreement with Sun Edison, LLC, the developer of the project, which provides for the acquisition of all of the outstanding membership interests of Adobe Solar, LLC (Adobe) by STR. Adobe is constructing an approximately 20-MW solar generating facility in Kern County, California. The solar facility is expected to begin commercial operation in spring 2014. The output of the plant is contracted under a 20-year PPA with Southern California Edison Company, which is expected to begin in spring 2014. The acquisition is in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Adobe is expected to occur in spring 2014 and the purchase price is expected to be approximately $100 million.

The completion of the acquisition is subject to Sun Edison, LLC achieving certain construction and project milestones by certain dates and various customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

Campo Verde Solar, LLC

On April 23, 2013, Southern Power and TRE, through 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 constructed an approximately 139-MW solar photovoltaic facility in Southern California. Commercial operation of the solar facility was declared by Campo Verde on October 25, 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 began on the commercial operation date. 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 preliminary asset allocation is under evaluation by management; therefore, the allocation of the purchase price to individual assets has not been finalized. Under an engineering, procurement, and construction agreement (Construction Agreement), an additional $328.7 million has been paid to a subsidiary of First Solar, Inc. (Construction Contractor) for the 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.

XML

Acquisitions (Details) (Southern Power [Member], USD $) In Millions, unless otherwise specified	0 Months Ended	9 Months Ended	0 Months Ended	9 Months Ended
	Aug. 27, 2013 Adobe Solar LLC [Member]	Sep. 30, 2013 Adobe Solar LLC [Member] MW	Apr. 23, 2013 Campo Verde Solar LLC [Member]	Sep. 30, 2013 Campo Verde Solar LLC [Member] MW
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent		90.00%
Acquisitions (Textual) [Abstract]
Power of solar polycrystalline silicon facility		20		139
Beginning year of output of constructed plant		2014		2013
Life Output Of Plant		20 years		20 years
Cash Consideration for acquisition of the interests in Apex	$ 100.0		$ 136.6
Business Acquisition Cost Paid At Closing			111.6
Business Acquisition Cost Paid Upon Achievement Of Milestones			25.0
Cash Consideration will be paid under MIPA			$ 328.7

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Changes in fair value of qualifying hedges, tax	$ 0	$ 1,000,000	$ 0	$ (4,000,000)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1,000,000	1,000,000	5,000,000	4,000,000
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	1,000,000	0	3,000,000	1,000,000
Alabama Power [Member]
Changes in fair value of qualifying hedges, tax	0	(2,000,000)	0	(6,000,000)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1,000,000	0	1,000,000	0
Georgia Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	0	0	1,000,000	1,000,000
Gulf Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	58,000	90,000	238,000	270,000
Mississippi Power [Member]
Changes in fair value of qualifying hedges, tax	0	0	0	(296,000)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	131,000	131,000	394,000	279,000
Southern Power [Member]
Changes in fair value of qualifying hedges, tax	0	215,000	0	95,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 213,000	$ 999,000	$ 2,310,000	$ 2,911,000

XML

Contingencies and Regulatory Matters

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

CONTINGENCIES AND REGULATORY MATTERS

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.

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. On September 19, 2013, a three-judge panel of the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment of the U.S. District Court for the Northern District of Alabama in favor of Alabama Power, which was based on the exclusion of the testimony of certain of the EPA's experts, and remanded the case back to the U.S. District Court for the Northern District of Alabama for further proceedings. On October 31, 2013, Alabama Power filed with the U.S. Court of Appeals for the Eleventh Circuit a petition for rehearing. In February 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the 2011 judgment and recusal of the judge in the case involving Alabama Power (including claims related to the unit co-owned by Mississippi Power), which remains pending.

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 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 2009 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 and, on May 20, 2013, the U.S. Supreme Court denied the plaintiffs' petition for review. The case is now concluded.

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 case is now concluded.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of September 30, 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, and the case is currently on appeal to the U.S. Court of Appeals for the Fourth Circuit.

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 Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $52 million as of September 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. 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 the vast majority of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In 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 September 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 and licensing of an on-site dry storage facility at Plant Vogtle Units 1 and 2 is complete. The facility began operation in October 2013 and Plant Vogtle Units 1 and 2 are expected to maintain full-core discharge 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.

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.

Retail Regulatory Matters

Alabama Power

Rate RSE

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Rate RSE" and "Retail Regulatory Matters – Rate RSE," respectively, 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. On August 13, 2013, the Alabama PSC voted to issue a report on Rate RSE that found that Alabama Power's Rate RSE mechanism continues to be just and reasonable to customers and Alabama Power, but recommended Alabama Power modify Rate RSE as follows:

• Eliminate the provision of Rate RSE establishing an allowed range of ROE, which is currently 13.0% to 14.5%, with an adjusting point of 13.75%.

• Eliminate the provision of Rate RSE limiting Alabama Power's capital structure to an allowed equity ratio of 45%.

• Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the current Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.

• Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

Substantially all other provisions of Rate RSE would remain unchanged.

On August 21, 2013, Alabama Power filed its consent to these recommendations with the Alabama PSC. The changes are effective for calendar year 2014.

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," respectively, 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 September 30, 2013 was $22 million as compared to $9 million at December 31, 2012. This under recovered balance at September 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 September 30, 2013 was $12 million as compared to $21 million at December 31, 2012. This under recovered balance at September 30, 2013 consists of $4 million in under recovered regulatory clause revenues and $8 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.

On August 13, 2013, the Alabama PSC approved Alabama Power's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets currently being recovered through Rate RSE. The revenue impact as a result of this revision is estimated to be $50 million in 2014; however, this petition was 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. Any unrecovered amounts associated with 2014 environmental compliance costs will be reflected in the 2015 Rate CNP Environmental filing.

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 September 30, 2013 totaled $43 million as compared to an under recovered balance of $4 million at December 31, 2012. The over recovered fuel costs at September 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 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 September 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.

Non-Nuclear Outage Accounting Order

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Rate RSE" and "Retail Regulatory Matters – Rate RSE," respectively, in Item 8 of the Form 10-K for additional information. On August 13, 2013, the Alabama PSC approved Alabama Power's petition requesting authorization to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures to be deferred and amortized are estimated to total approximately $70 million. This petition was made in accordance with Alabama Power's agreement with the Alabama PSC to develop a plan to keep Rate RSE factors unchanged in 2014.

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 September 30, 2013 and December 31, 2012, Georgia Power's fuel cost over recovery balance totaled $114 million and $230 million, respectively, included in current liabilities and other deferred credits and liabilities 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.

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 was 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.

Hearings on Georgia Power’s testimony were held in October 2013. In testimony filed on October 18, 2013 and October 22, 2013, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period and a 10.0% ROE that would result in excess revenues of $165 million. However, the Georgia PSC Staff also proposed no change to Georgia Power’s current retail base rates through 2014. The excess earnings in 2014 would be used to reduce rate increases in 2015 and 2016. The Georgia PSC Staff further proposed reducing the allowed ROE range to 50 basis points above and below the authorized ROE with one-third of any earnings above the range used to reduce future ECCR tariff increases and the remaining two-thirds applied to rate reductions. Georgia Power disagrees with the Georgia PSC Staff's positions. Hearings on the Georgia PSC Staff and intervenor testimony and Georgia Power's rebuttal hearings will be held in November 2013.

The Georgia PSC is scheduled to issue a final order in this matter in 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. On September 30, 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 IRP in order to comply with the State of Georgia's Multi-Pollutant Rule.

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, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division on September 10, 2013 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. See Note 1 to the financial statements of Georgia Power under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the fuel switch at SEGCO's generating units.

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 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.

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, and subsequently has requested Georgia PSC approval. During 2013, Georgia Power has executed four PPAs to purchase a total of 169 MWs of biomass capacity and energy from four facilities in Georgia that will commence in 2015 and end in 2035. On May 21, 2013, the Georgia PSC approved two of the biomass PPAs. The two wind PPAs and the two Georgia PSC-approved biomass PPAs result in contractual obligations of approximately $13 million in 2015, $47 million in 2016, $49 million in 2017, and $1.29 billion thereafter. If approved by the Georgia PSC, the additional biomass PPAs will result in contractual obligations of approximately $1 million in 2015, $11 million in 2016, $12 million in 2017, and $249 million thereafter. The four biomass PPAs are contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.

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 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. On November 1, 2013, Georgia Power filed to increase the NCCR tariff by approximately $65 million effective January 1, 2014. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At September 30, 2013, approximately $41 million of these 2009 and 2010 costs remained unamortized in CWIP.

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 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. The deadline for any further appeals expired without the petitioners seeking review.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, Georgia Power's eighth VCM report 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.

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 (February 2014 VCM report). The stipulation was approved by the Georgia PSC on September 3, 2013. As required by the stipulation, Georgia Power filed an abbreviated status update with the Georgia PSC on September 3, 2013, which reflected approximately $2.4 billion of total construction capital costs incurred through June 30, 2013. After the February 2014 VCM report, Georgia Power expects to resume filing semi-annual VCM reports in August 2014. On October 15, 2013, the Georgia PSC voted to approve Georgia Power's eighth VCM report, reflecting construction capital costs incurred, which through December 31, 2012 totaled approximately $2.2 billion.

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. On August 30, 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit on September 27, 2013. While litigation has commenced and Georgia Power intends to vigorously defend its positions, Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

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 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.

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.

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.

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 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.

On November 4, 2013, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2014. The net effect of the approved changes is a $65.2 million increase in annual revenue for 2014.

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.

Under recovered fuel costs at September 30, 2013 totaled $10.0 million which is included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. The under recovered fuel cost balance included approximately $26.6 million received during the third quarter 2013 as a result of a payment from one of Gulf Power's fuel vendors pursuant 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 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.

Under recovered purchased power capacity costs at September 30, 2013 totaled $6.4 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.

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.

Under recovered environmental costs at September 30, 2013 totaled $7.9 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.

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.

Under recovered energy conservation costs at September 30, 2013 totaled $5.7 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.

Mississippi Power

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 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.

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 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 September 30, 2013, total project expenditures were $278.3 million, of which Mississippi Power's portion was $139.2 million, excluding AFUDC of $6.6 million. The ultimate outcome of this matter cannot be determined at this time.

On August 13, 2013, the Mississippi PSC approved Mississippi Power’s 2013 ECO Plan filing which proposed no change in rates.

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.

On March 5, 2013, the Mississippi PSC approved a $35.5 million decrease of the annual retail fuel cost recovery factor, or 4.7% of total 2012 retail revenue, effective March 19, 2013.

At September 30, 2013, the amount of over recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $21.8 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 September 30, 2013, the amount of over recovered wholesale MRA and MB fuel costs included on Mississippi Power's Condensed Balance Sheets herein was $9.1 million and $0.6 million, respectively, compared to $19.0 million and $2.1 million, respectively, at December 31, 2012. In addition, at September 30, 2013, the amount of under recovered MRA emissions allowance cost included on Mississippi Power's Condensed Balance Sheets herein was $3.4 million compared to $0.4 million at December 31, 2012. Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel 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 June 4, 2013, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2013, which included 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.

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 September 30, 2013, the balance in the storm reserve was $59.2 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

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. 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 Construction Schedule and 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. The Kemper IGCC was originally scheduled to be placed in service in May 2014.

On October 28, 2013, Mississippi Power revised the scheduled in-service date for the Kemper IGCC to the fourth quarter 2014 primarily as the result of lower-than-planned installation levels for piping as well as abnormally wet weather. Also on October 28, 2013, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately $4.02 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, $426 million of AFUDC, and $101 million of certain general exceptions. Additionally, Mississippi Power expects to defer $91 million of non-capital Kemper IGCC-related costs to a regulatory asset.

Mississippi Power recorded pre-tax charges to income for estimated probable losses of $78.0 million ($48.2 million after tax) and $462.0 million ($285.3 million after tax) in 2012 and the first quarter 2013, respectively, as a result of additional cost pressures, including labor costs, piping and other material costs, engineering and support costs, and productivity decreases. Mississippi Power recorded a pre-tax charge to income for an estimated probable loss of $450.0 million ($277.9 million after tax) in the second quarter 2013 as a result of 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 recorded a pre-tax charge to income for an estimated probable loss of $150.0 million ($92.6 million after tax) in the third quarter 2013 primarily as a result of the schedule extension. 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, $450.0 million ($277.9 million after tax) in the second quarter 2013, and $150.0 million ($92.6 million after tax) in the third quarter 2013.

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.

Mississippi Power could experience further construction cost increases and/or schedule extensions 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 further schedule extensions 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 and could result in the loss of certain tax benefits related to bonus depreciation. 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 September 30, 2013, Mississippi Power had incurred total costs of $3.61 billion on the Kemper IGCC. These costs include$2.94 billion for the portion of the Kemper IGCC subject to the construction cost cap, $223.9 million for the lignite mine and equipment, $91.9 million for the CO₂ pipeline facilities, $232.2 million of AFUDC, and $67.6 million of certain general exceptions. Also included in this total is $55.2 million of certain regulatory assets. Of this total, $2.41 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.14 billion), $59.1 million in other regulatory assets, and $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, subject to review of such costs by the Mississippi PSC. This includes deferred costs associated with the generation resource planning, evaluation, and screening activities. The amortization period for any such costs approved for recovery 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

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 (excluding AFUDC) 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 and is expected to be revised later in 2013 in connection with the revised in-service date); (4) the Mississippi PSC's decision on the Seven-Year Rate Plan within four months of that filing (which, given the expected revision, is now expected to occur in the first half of 2014); (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 of up to $1 billion 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 the second quarter 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 October 15, 2013 revised 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 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 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.

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 on January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. Amounts collected through these rates are being recorded as a regulatory liability to be used to mitigate customer rate impacts when the Kemper IGCC is placed in service. As of September 30, 2013, $62.0 million had been collected and recorded as a regulatory liability 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.

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 contemplates the continued accrual of AFUDC through the in-service date, subject to approval by the Mississippi PSC.

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 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. 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 regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan 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 assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of 2012 (ATRA), which currently requires that the Kemper IGCC be placed in service in 2014. Mississippi Power plans to amend the Seven-Year Rate Plan described above to reflect changes including the revised in-service date, the change in expected benefits relating to tax credits, and other tax matters, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. Mississippi Power does not expect these revisions to change the total customer rate impacts contemplated in the Seven-Year Rate Plan. See "Tax Incentives" herein for additional information relating to tax credits and bonus depreciation.

On October 15, 2013, the Mississippi PSC issued a revised 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 the second quarter 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.

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 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.

Nitrogen Supply Agreement

On September 19, 2013, Mississippi Power entered into an agreement to sell the air separation unit for the Kemper IGCC for $79.0 million and also entered into a 20-year nitrogen supply agreement, whereby nitrogen will be supplied to Mississippi Power for the gasification process. The nitrogen supply agreement resulted in a capital lease obligation for Mississippi Power at inception of $82.9 million with an annual interest rate of 4.9%. Assets acquired under capital leases are recorded on Southern Company's and Mississippi Power’s Condensed Balance Sheets herein as utility plant in service, and the related obligations are classified as long-term debt and securities due within one year.

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 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. On May 15, 2013, the IRS notified Mississippi Power that no additional tax credits under the Internal Revenue Code Section 48A Phase III were allocated to the Kemper IGCC. As a result of the schedule extension for the Kemper IGCC, the Phase I credits will be recaptured and Mississippi Power has reclassified the recaptured credits as a reduction of prepaid income taxes on Southern Company's and Mississippi Power’s Condensed Balance Sheets herein. Through September 30, 2013, Mississippi Power had recorded tax benefits totaling $276.4 million for the remaining Phase II credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the tax credits will be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.

On January 2, 2013, the 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.

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

Other Matters

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 4, 2013. Plant Bowen Unit 2 (approximately 700 MWs) remains offline pending completion of the 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.

XML

Introduction (Tables) (Alabama Power [Member])

9 Months Ended

Sep. 30, 2013

Alabama Power [Member]

Related Party Transaction [Line Items]

Estimated Cost Of Decommissioning [Table Text Block]

The estimated costs of decommissioning based on the 2013 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076

	(in millions)
Site study costs:
Radiated structures	$	1,362
Non-radiated structures	80
Total site study costs	$	1,442

Schedule of Asset Retirement Obligations [Table Text Block]

As of September 30, 2013 and 2012, details of the ARO related to the decommissioning of Plant Farley included in Southern Company's and Alabama Power's Condensed Balance Sheets herein are as follows:

	2013		2012
	(in millions)
Balance at beginning of year	$	589	$	553
Liabilities incurred	—		—
Liabilities settled	—		(1		)
Accretion	29		28
Cash flow revisions	102		—
Balance at end of period	$	720	$	580

XML

Segment and Related Information - Financial Data for Products and Services (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenue from External Customer [Line Items]
Electric Revenue	$ 5,005,000,000	$ 5,033,000,000	$ 13,120,000,000	$ 12,788,000,000
Financial data for Products and Services
Electric Utilities' Revenues	5,017,000,000	5,049,000,000	13,160,000,000	12,834,000,000
Retail [Member]
Revenue from External Customer [Line Items]
Electric Revenue	4,319,000,000	4,379,000,000	11,237,000,000	11,068,000,000
Wholesale [Member]
Revenue from External Customer [Line Items]
Electric Revenue	520,000,000	497,000,000	1,406,000,000	1,261,000,000
Other [Member]
Revenue from External Customer [Line Items]
Electric Revenue	$ 166,000,000	$ 157,000,000	$ 477,000,000	$ 459,000,000

XML

Investment In Leveraged Leases

9 Months Ended

Sep. 30, 2013

Leases [Abstract]

INVESTMENTS IN LEVERAGED LEASES

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.

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 through 2015 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.

XML

Derivatives - Balance Sheet Presentation (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	$ 18	$ 36
Derivative Liability, Fair Value	84	111
Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	9	23
Derivative Liability, Fair Value	83	109
Cash Flow and Fair Value Hedging [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		10
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		3
Derivative Liability, Fair Value		2
Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	48	74
Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	35	35
Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	6	10
Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	3	13
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	1	1
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value		1
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	2	2
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Assets from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		1
Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	7	7
Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		3
Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	3	5
Derivative Liability, Fair Value	15	18
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	3	5
Derivative Liability, Fair Value	15	18
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Derivative Liability, Fair Value		0
Alabama Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	9	14
Alabama Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	6	4
Alabama Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	2	2
Alabama Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	1	3
Alabama Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	0	0
Alabama Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value		0
Alabama Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Alabama Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Assets from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Alabama Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Alabama Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	2	11
Derivative Liability, Fair Value	29	45
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	2	11
Derivative Liability, Fair Value	29	45
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Derivative Liability, Fair Value		0
Georgia Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	19	30
Georgia Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	10	15
Georgia Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	1	6
Georgia Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	1	5
Georgia Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	0	0
Georgia Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value		0
Georgia Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Georgia Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Assets from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Georgia Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Georgia Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	3	4
Derivative Liability, Fair Value	25	27
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	3	4
Derivative Liability, Fair Value	25	27
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Derivative Liability, Fair Value		0
Gulf Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	13	17
Gulf Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	12	10
Gulf Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	2	1
Gulf Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	1	3
Gulf Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	0	0
Gulf Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value		0
Gulf Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Gulf Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Assets from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Gulf Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Gulf Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	1	3
Derivative Liability, Fair Value	14	19
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	1	3
Derivative Liability, Fair Value	14	19
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Derivative Liability, Fair Value		0
Mississippi Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	7	13
Mississippi Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	7	6
Mississippi Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	1	1
Mississippi Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	2
Mississippi Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	0	0
Mississippi Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value		0
Mississippi Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Mississippi Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Assets from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Mississippi Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Mississippi Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Southern Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	2	3
Derivative Liability, Fair Value	1	2
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		0
Southern Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		3
Derivative Liability, Fair Value		2
Southern Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value	1	1
Southern Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value		1
Southern Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	2	2
Southern Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Assets from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		1
Southern Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value	0	0
Southern Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value		$ 0

XML

Fair Value Measurements - Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	$ 60	$ 112
Alabama Power [Member]
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	33	76
Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Notices Of Withdrawal Foreign Equity Funds	20.00%	20.00%
Maximum Number of Months Related to Maturities in Portfolio Not to Exceeded from Date of Purchase		13 months
Maximum Number of Days Related to Dollar Weighted Average Portfolio Maturities Regarding Commingled Funds		90 days
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	27	36
Minimum [Member] | Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Withdrawal Of Foreign Equity Fund Investment	1	1
Foreign Equity Fund Investment	$ 10	$ 10

XML

Financing (Tables)

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Credit arrangements by company

The following table outlines the committed credit arrangements by company as of September 30, 2013:

	Expires(a)														Executable Term Loans				Due Within One Year
Company	2013		2014		2015		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	1		268		35		—		1,000		1,304		1,304		53		—		53		146
Georgia Power	—		—		—		150		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		90		—		165		—		275		275		45		—		45		65
Mississippi Power	15		120		—		165		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		486		—		—		—		—
Other	—		75		25		—		—		100		100		25		—		25		50
Total	$	36	$	553	$	60	$	480	$	4,100	$	5,229	$	5,201	$	148	$	40	$	188	$	331

(a) No credit arrangements expire in 2017.

Schedule of Long-term Debt Instruments [Table Text Block]

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

Company(a)	Senior  Note Issuances		Senior  Note Redemptions and  Maturities		Revenue Bond Issuances		Revenue Bond Redemptions and Maturities		Other Long-Term Debt Issuances		Other  Long-Term Debt Redemptions
					(in millions)
Southern Company	$	500	$	—	$	—	$	—	$	—	$	—
Georgia Power	850		1,250		89		89		—		—
Gulf Power	90		90		—		—		—		—
Mississippi Power	—		—		31		83		475		125
Southern Power	300		—		—		—		23		—
Other	—		50		—		—		—		—
Total	$	1,740	$	1,390	$	120	$	172	$	498	$	125

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

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Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2013	Three Months Ended September 30, 2012	Nine Months Ended September 30, 2013	Nine Months Ended September 30, 2012
	(in millions)
As reported shares	878	876	874	872
Effect of options and performance share award units	3	7	5	8
Diluted shares	881	883	879	880

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
	(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	—	—		1,230			—		1,230
Other comprehensive income (loss)	—	—		11			—		11
Treasury stock re-issued	—	1,956		89			—		89
Stock issued	12,046	—		484			49		533
Stock repurchased, at cost	—	—		(19		)	—		(19		)
Cash dividends on common stock	—	—		(1,314		)	—		(1,314		)
Other	—	(30	)	—			—		—
Balance at September 30, 2013	889,849	(8,109	)	$	18,778		$	756	$	19,534
Balance at December 31, 2011	865,664	(539	)	$	17,578		$	707	$	18,285
Net income after dividends on preferred and preference stock	—	—		1,967			—		1,967
Other comprehensive income (loss)	—	—		(1		)	—		(1		)
Stock issued	11,586	—		479			—		479
Stock repurchased, at cost	—	(2,567	)	(117		)	—		(117		)
Cash dividends on common stock	—	—		(1,267		)	—		(1,267		)
Other	—	(38	)	—			—		—
Balance at September 30, 2012	877,250	(3,144	)	$	18,639		$	707	$	19,346

XML

Effective Tax Rate and Unrecognized Tax Benefits - Narrative (Details)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	33.90%	35.30%
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern	12 months
Alabama Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	39.30%	38.80%
Georgia Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	38.00%	35.80%
Gulf Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	37.60%	37.30%
Mississippi Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	(42.10%)	26.70%
Southern Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	20.50%	34.40%

XML

Contingencies and Regulatory Matters (Details) (USD $)	9 Months Ended		9 Months Ended						0 Months Ended		1 Months Ended	6 Months Ended	9 Months Ended							1 Months Ended									1 Months Ended		9 Months Ended	12 Months Ended								1 Months Ended		9 Months Ended						1 Months Ended														9 Months Ended		3 Months Ended		9 Months Ended	3 Months Ended			9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Kivalina Case [Member]	Sep. 30, 2013 Alabama Power [Member] Coal_Fired_Generating_Facilities claim	Aug. 13, 2013 Alabama Power [Member] Provisions	Dec. 31, 2012 Alabama Power [Member]	Aug. 13, 2013 Alabama Power [Member] Minimum [Member]	Aug. 13, 2013 Alabama Power [Member] Maximum [Member]	May 14, 2013 Georgia Power [Member] Purchased_Power_Agreement	Apr. 22, 2013 Georgia Power [Member] Purchased_Power_Agreement MW	May 31, 2013 Georgia Power [Member] Property	Jun. 30, 2013 Georgia Power [Member]	Sep. 30, 2013 Georgia Power [Member] Property Coal_Fired_Generating_Facilities MW	Jun. 28, 2013 Georgia Power [Member]	May 21, 2013 Georgia Power [Member]	Jan. 02, 2013 Georgia Power [Member]	Dec. 31, 2012 Georgia Power [Member]	Jan. 02, 2012 Georgia Power [Member]	Jan. 02, 2011 Georgia Power [Member]	Oct. 31, 2013 Georgia Power [Member] Subsequent Event [Member]	Nov. 01, 2013 Georgia Power [Member] Subsequent Event [Member]	Oct. 15, 2013 Georgia Power [Member] Subsequent Event [Member]	Sep. 30, 2013 Georgia Power [Member] Minimum [Member]	Sep. 30, 2013 Georgia Power [Member] Maximum [Member]	Sep. 30, 2013 Gulf Power [Member]	Dec. 31, 2012 Gulf Power [Member]	Nov. 04, 2013 Gulf Power [Member] Subsequent Event [Member]	Jul. 12, 2013 Gulf Power [Member] Subsequent Event [Member]	Mar. 31, 2012 Mississippi Power [Member]	May 31, 2010 Mississippi Power [Member] MW	Sep. 30, 2013 Mississippi Power [Member] mi	Dec. 31, 2012 Mississippi Power [Member]	Sep. 19, 2013 Mississippi Power [Member]	Jun. 04, 2013 Mississippi Power [Member]	Mar. 15, 2013 Mississippi Power [Member]	Mar. 05, 2013 Mississippi Power [Member]	Feb. 01, 2013 Mississippi Power [Member]	Jan. 18, 2013 Mississippi Power [Member]	Dec. 31, 2010 Mississippi Power [Member]	Oct. 31, 2013 Mississippi Power [Member] Subsequent Event [Member]	Jul. 11, 2013 Mississippi Power [Member] Subsequent Event [Member] Customer	Sep. 30, 2013 Mississippi Power [Member] Minimum [Member]	Sep. 30, 2013 Mississippi Power [Member] Maximum [Member]	Sep. 30, 2013 Mississippi Power [Member] MRA Revenue [Member]	Dec. 31, 2012 Mississippi Power [Member] MRA Revenue [Member]	Sep. 30, 2013 Mississippi Power [Member] MB Revenue [Member]	Dec. 31, 2012 Mississippi Power [Member] MB Revenue [Member]	Oct. 31, 2013 Mississippi Power [Member] Cost Cap Exceptions [Member]	Oct. 28, 2013 Mississippi Power [Member] Cost Cap Exceptions [Member]	Oct. 28, 2013 Mississippi Power [Member] Non Capital Kemper IGCC Related Costs [Member] Subsequent Event [Member]	Sep. 30, 2013 Gulf Power and Mississippi Power [Member]	Apr. 17, 2013 Plant Bowen [Member] Georgia Power [Member] MW	Apr. 17, 2013 Plant Branch Unit Two [Member] Georgia Power [Member] MW	Jul. 11, 2013 Plant Boulevard [Member] Georgia Power [Member] Subsequent Event [Member] MW	Jul. 11, 2013 Plant Branch Units Three And Four [Member] Georgia Power [Member] Subsequent Event [Member] MW	Jul. 11, 2013 Plant Yates [Member] Georgia Power [Member] Subsequent Event [Member] MW	Jul. 11, 2013 Plant McManus [Member] Georgia Power [Member] Subsequent Event [Member] MW	Jul. 11, 2013 Plant Kraft [Member] Georgia Power [Member] Subsequent Event [Member] MW	Sep. 30, 2013 Utility Scale Projects [Member] Georgia Power [Member] MW	Sep. 30, 2013 Electric Distribution [Member] Georgia Power [Member] MW	Jul. 12, 2013 Electric Transmission [Member] Gulf Power [Member] Subsequent Event [Member]	Sep. 30, 2013 Electricity Generation Plant, Non-Nuclear [Member] Mississippi Power [Member]	Apr. 04, 2013 Plant Bowen Unit One [Member] Georgia Power [Member] MW	Sep. 30, 2013 Kemper IGCC [Member]	Mar. 31, 2013 Kemper IGCC [Member]	Sep. 30, 2013 Kemper IGCC [Member]	Sep. 30, 2013 Kemper IGCC [Member] Mississippi Power [Member]	Jun. 30, 2013 Kemper IGCC [Member] Mississippi Power [Member]	Mar. 31, 2013 Kemper IGCC [Member] Mississippi Power [Member]	Sep. 30, 2013 Kemper IGCC [Member] Mississippi Power [Member]	Dec. 31, 2012 Kemper IGCC [Member] Mississippi Power [Member]	Apr. 04, 2013 Plant Bowen Unit Two [Member] Georgia Power [Member] MW	Sep. 30, 2013 Regulatory Clause Revenues, under-recovered [Member] Alabama Power [Member]	Sep. 30, 2013 Deferred Under Recovered Regulatory Clause Revenue [Member] Alabama Power [Member]	Sep. 30, 2013 Current Liabilities [Member]	Sep. 30, 2013 Current Liabilities [Member] Georgia Power [Member]	Dec. 31, 2012 Current Liabilities And Other Deferred Credits And Liabilities [Member]	Dec. 31, 2012 Current Liabilities And Other Deferred Credits And Liabilities [Member] Georgia Power [Member]	Sep. 19, 2013 Capital Lease Obligations [Member] Mississippi Power [Member]	Aug. 13, 2013 Current Rate Stabilization And Equalization [Member] Alabama Power [Member] Minimum [Member]	Aug. 13, 2013 Current Rate Stabilization And Equalization [Member] Alabama Power [Member] Maximum [Member]	Aug. 13, 2013 Current Rate Stabilization And Equalization [Member] Alabama Power [Member] Maximum [Member]
Loss Contingencies [Line Items]
Estimated Loss On Plant																																																																						$ 1,140,000,000
Significant Assumption Of Inflation Rate Used To Determine Costs For Rate Making				4.50%
Environmental Matters
Number of coal fired generating facilities at which new source review violations occurred				5									3
Number of dismissed claims against Subsidiary				5
Total number of claims				8
Claims left for summary disposition or trial against Alabama Power				3
Civil penalties under Clean Air Act, per day, per violation, minimum	25,000
Civil penalties under Clean Air Act, per day, per violation, maximum	37,500
Damages from lost property values and relocating village cost, lower range			95,000,000
Damages from lost property values and relocating village cost, upper range			400,000,000
Environmental remediation liability													18,000,000												52,000,000
Civil penalties per day violation rate													37,500
Number of times of punitive damages in comparison to cost incurred by Environmental Protection Agency													3
Damages awarded				17,000,000									27,000,000
Amount have been recognized in the financial statements for the second claim													0
Increase in annual base wholesale revenues																															22,600,000
Increase in base rate under cost based electric tariff due to settlement																															24,200,000
Revenue to be received from increase in base rate													334,000,000																		18,000,000
Estimated Increase In ECCR Tariff													132,000,000
Estimated Increase In Demand Side Management Tariffs													5,000,000
Estimated Increase In Municipal Franchise Fee Tariff													11,000,000
Period For Levelized Revenue Requirements													3 years
Test Period For PSC																				1 year
Excess Revenues																				165,000,000
Retail Regulatory Matters
Under recovered rate CNP balance				22,000,000	50,000,000	9,000,000
Under recovered rate CNP environmental balance				12,000,000		21,000,000
Under recovered certified power purchase agreements																																																																									4,000,000	8,000,000
Over recovered fuel costs				43,000,000																						17,100,000
Under recovered regulatory clause revenues						4,000,000																			10,000,000
Fuel Vendor Payment																									26,600,000
Accumulated reserve balance for future storms				95,000,000		103,000,000
Period To Amortize Expense				3 years
Outage Expenditures				70,000,000
Over recovered fuel cost balance																																																																											108,000,000	114,000,000	230,000,000	230,000,000
PSC Retail Rate Increase														482,000,000														74,400,000						7,100,000																											16,400,000
Proposed Change in Annual Revenues																											65,200,000
Percentage Of PSC Retail Rate Increase														6.10%																				0.90%
Retail Rate Of Return On Common Equity							13.00%	14.50%					10.00%	11.50%									10.25%	12.25%	11.50%
Adjusting Point Of Rate Of Return On Common Equity					13.75%
Allowed Equity Ratio					45.00%
Number Of Provisions					2
Weighted Cost Of Equity							5.75%	6.21%																																																																								5.85%	6.53%
Adjusting Point Of Weighted Cost Of Equity					5.98%																																																																													6.19%
Number Of Basis Points					7								50
Percent Of Basis Points					0.07%
Capacity Of Units Approved For Decertification Of Units																																																				32	319	28	1,016	579	122	316
Period Extension Of The MATS Rule													1 year
Energy From Solar Generation													525																																														425	100
Number of wind PPAs										2
Energy from wind-powered generating facilities										250
Number Of Biomass PPAs									2
Capacity of small power production facility													169
Number Of Biomass Facilities											2		4
Additional contractual obligations in 2015													1,000,000		13,000,000
Additional contractual obligations in 2016													11,000,000		47,000,000
Additional contractual obligations in 2017													12,000,000		49,000,000
Additional contractual obligations thereafter													249,000,000		1,290,000,000
Proportionate share owed in consortium agreement													45.70%
Increase In NCCR Tariff																50,000,000		35,000,000	223,000,000		65,000,000
Amortization to earnings of financing costs capitalized over the five year period													91,000,000
Amortization to earnings of financing costs capitalized, amortization term													5 years
Costs included in CWIP													41,000,000																		2,410,000,000
Construction and capital costs included in semi-annual construction monitoring report																						2,200,000,000
Increase (decrease) in projected certified construction capital costs													5.00%
Estimated In-service Capital Cost													4,800,000,000
Cost incurred by Mississippi Power associated with plant including regulatory filing costs													2,000,000,000
Construction Capital Costs												2,400,000,000
Reduction in projected in-service cost due to recovered cost													425,000,000
Under recovered purchased power capacity costs																									6,400,000	800,000
Under recovered environmental cost																									7,900,000	1,900,000
Under recovered energy conservation costs																									5,700,000	800,000
Required Customers For Energy Efficiency Programs																																									25,000
Required Period For Filing Quick Start Plans																															6 months
Period For Quick Start Plans To Be In Effect																																										2 years	3 years
Annual PEP Filing Rate Increase																																				1.925%		1.99%
Annual PEP Filing Rate Increase Amount																																				15,300,000		15,800,000
Potential additional revenues in 2013 as a result of late implementation of the 2013 PEP rate increase																															3,300,000
Annual PEP lookback refund to customers																																			4,700,000
Psc Approved Annual Property Damage Reserve Accrual																																					3,200,000
Ownership percentage in scrubber project																									50.00%						50.00%
Estimated cost of scrubber project																															330,000,000																				660,000,000
Scrubber project expenditures amount																															139,200,000																				278,300,000
Allowance For Funds Used During Construction Cost																															6,600,000
Annual adjustment in retail fuel cost recovery factor, percentage decrease																																				4.70%
Annual adjustment in retail fuel cost recovery factor, amount																																				35,500,000
Amount of over recovered retail fuel costs included in balance sheets																															21,800,000	56,600,000
Amount of over recovered fuel costs																																												9,100,000	19,000,000	600,000	2,100,000
Amount of under recovered emissions allowance costs																															3,400,000	400,000
Storm reserve balance																															59,200,000
Integrated Coal Gasification Combined Cycle [Abstract]
Plant Capacity Under Coal Gasification Combined Cycle Technology																														582
Co Two Pipeline Infrastructure																															61
Estimated Cost																																																														2,400,000,000								2,880,000,000
Alternate Financing																																																														1,000,000,000
Cost Of Plant																																																																						3,610,000,000
Costs associated with CCP12 grant funds																															245,000,000
Maximum Cap Construction Cost																																								4,020,000,000																														2,940,000,000
Estimated Cost of Pipeline Infrastructure																															91,900,000																		115,000,000
Cost Of Lignite Mine																															223,900,000																		245,000,000
AFUDC Cost																															232,200,000																	426,000,000
General Exceptions																															67,600,000																	101,000,000
Regulatory Assets																																																		91,000,000
Pre-tax charge to income																																																																150,000,000	540,000,000	1,100,000,000	150,000,000	450,000,000	462,000,000		78,000,000
After tax charge to income	16,000,000																																																															93,000,000	333,500,000	704,000,000	92,600,000	277,900,000	285,300,000		48,200,000
Costs included in CWIP													41,000,000																		2,410,000,000
Cost deferred in other regulatory assets																															59,100,000
Other deferred charges and assets	3,800,000																														3,900,000
Previously expensed																															1,000,000
Settlement Agreement To Increase Rates																																											172,000,000
Collaboration Period To File Settlement Agreement																															3 months
Beginning Period Of Operation Of Plant																															7 years
Period Of Time For Decision On Rate Recovery Plan Within Filing																															4 months
Prudence Review Of Plant Cost Within Settlement Agreement																															6 months
Increase Retail Rates In Year One																															15.00%
Increase Retail Rates In Year Two																															3.00%
Settlement Agreement Collection Amount To Mitigate Rate Impact Year Two																																				156,000,000
Regulatory Liabilities	27,000,000																														62,000,000
Other Regulatory Liabilities, Current	89,000,000	107,000,000		45,000,000		3,000,000							18,000,000				73,000,000								14,316,000	25,887,000					11,846,000	5,376,000																																3,000,000		3,000,000
Other regulatory liabilities, deferred	375,000,000	289,000,000		211,000,000		183,000,000																			47,090,000	47,863,000					117,804,000	56,984,000																																24,000,000		24,000,000
Reduced percentage interest transferred under asset purchase agreement																																15.00%
Purchase of Interest																																17.50%							17.50%
Deposit received																													150,000,000
Maximum period to refund deposit upon termination of asset purchase agreement																													60 days
Maximum period of discretion in the event senior unsecured credit rating falls																													15 days
Agreement To Sell Air Separation Unit																																	79,000,000
Period Of Nitrogen Supply Agreement																																	20 years
Capital Lease Obligations																																	82,900,000
Debt Instrument, Interest Rate, Stated Percentage																																																																															4.90%
Internal Revenue Code Section Forty Eight Tax Credits Phase I																															133,000,000
Internal Revenue Code Section Forty Eight Tax Credits Phase I I																															279,000,000
Minimum percentage of carbon dioxide that must be capture and sequester to remain eligible for the phase II tax credits																															65.00%
Tax Credit Carryforward, Amount																															276,400,000
Additional Bonus Depreciation For Property Acquired Future Periods																															50.00%
Percent Of Designated Customer Value Benchmark Survey				33.30%
Electric Generating Units, Capacity																																																															700									700
Earnings Above ROE Range To Share With Customers													66.70%
Earnings Above ROE Range To Retain													33.30%
Required Period For Filing Comprehensive Portfolio Plans																															1 year
SignificantAssumption Of Trust Earnings Rate Used To Determine Costs For Rate Making				7.00%
Asset retirement obligation, current				102,000,000
Certain Regulatory Assets																															$ 55,200,000

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Stockholders' Equity - Changes in Stockholders' Equity (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013	Sep. 30, 2012
Changes in Stockholders' Equity
Beginning Balance					$ 19,004,000,000	$ 18,285,000,000
Net Income After Dividends on Preferred and Preference Stock	852,000,000	[1],[2]	976,000,000	[1]	1,230,000,000	1,967,000,000	[1]
Other comprehensive income (loss)	2,000,000		0		11,000,000	(1,000,000)
Stock Issued During Period, Value, Treasury Stock Reissued					89,000,000
Stock issued					533,000,000	479,000,000
Stock Repurchased During Period, Shares					0
Stock Repurchased During Period, Value					(19,000,000)	(117,000,000)
Cash dividends on common stock					(1,314,000,000)	(1,267,000,000)
Other					0	0
Ending Balance	19,534,000,000		19,346,000,000		19,534,000,000	19,346,000,000
Number of Common shares Issued [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares					877,803,000	865,664,000
Stock issued, shares					12,046,000	11,586,000
Stock Repurchased During Period, Shares					0	0
Ending Balance, Shares	889,849,000		877,250,000		889,849,000	877,250,000
Number of Common shares Treasury [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares					(10,035,000)	(539,000)
Stock Issued During Period, Shares, Treasury Stock Reissued					1,956,000
Stock Repurchased During Period, Shares					0	(2,567,000)
Other, Shares					(30,000)	(38,000)
Ending Balance, Shares	8,109,000		(3,144,000)		8,109,000	(3,144,000)
Common Stockholders' Equity [Member]
Changes in Stockholders' Equity
Beginning Balance					18,297,000,000	17,578,000,000
Net Income After Dividends on Preferred and Preference Stock					1,230,000,000	1,967,000,000
Other comprehensive income (loss)					11,000,000	(1,000,000)
Stock Issued During Period, Value, Treasury Stock Reissued					89,000,000
Stock issued					484,000,000	479,000,000
Stock Repurchased During Period, Value					(19,000,000)	(117,000,000)
Cash dividends on common stock					(1,314,000,000)	(1,267,000,000)
Other					0	0
Ending Balance	18,778,000,000		18,639,000,000		18,778,000,000	18,639,000,000
Preferred and Preference Stock of Subsidiaries [Member]
Changes in Stockholders' Equity
Beginning Balance					707,000,000	707,000,000
Net Income After Dividends on Preferred and Preference Stock					0	0
Other comprehensive income (loss)					0	0
Stock issued					49,000,000	0
Stock Repurchased During Period, Value					0	0
Cash dividends on common stock					0
Other					0	0
Ending Balance	$ 756,000,000		$ 707,000,000		$ 756,000,000	$ 707,000,000

[1] After dividends on preferred and preference stock of subsidiaries.

[2] Segment net income (loss) for the three months ended September 30, 2013 includes a $150 million pre-tax charge ($93 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.

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Derivatives - Balance Sheet Offsetting (Details) (Energy Related Derivative [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Derivative [Line Items]
Derivative Asset	$ 1		$ 3
Derivative Liability	74		88
Alabama Power [Member]
Derivative [Line Items]
Derivative Asset	0		1
Derivative Liability	12		14
Georgia Power [Member]
Derivative [Line Items]
Derivative Asset	0		0
Derivative Liability	27		34
Gulf Power [Member]
Derivative [Line Items]
Derivative Asset	0		0
Derivative Liability	22		23
Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset	0		1
Derivative Liability	13		17
Southern Power [Member]
Derivative [Line Items]
Derivative Asset	1		2
Derivative Liability	0		1
Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset	11	[1]	26	[1]
Derivative Liability	84	[1]	111	[1]
Net Amount Of Derivatives [Member] | Alabama Power [Member]
Derivative [Line Items]
Derivative Asset	3	[1]	5	[1]
Derivative Liability	15	[1]	18	[1]
Net Amount Of Derivatives [Member] | Georgia Power [Member]
Derivative [Line Items]
Derivative Asset	2	[1]	11	[1]
Derivative Liability	29	[1]	45	[1]
Net Amount Of Derivatives [Member] | Gulf Power [Member]
Derivative [Line Items]
Derivative Asset	3	[1]	4	[1]
Derivative Liability	25	[1]	27	[1]
Net Amount Of Derivatives [Member] | Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset	1	[1]	3	[1]
Derivative Liability	14	[1]	19	[1]
Net Amount Of Derivatives [Member] | Southern Power [Member]
Derivative [Line Items]
Derivative Asset	2	[1]	3	[1]
Derivative Liability	1	[1]	2	[1]
Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset	(10)	[2]	(23)	[2]
Derivative Liability	(10)	[2]	(23)	[2]
Gross Amount Of Derivatives [Member] | Alabama Power [Member]
Derivative [Line Items]
Derivative Asset	(3)	[2]	(4)	[2]
Derivative Liability	(3)	[2]	(4)	[2]
Gross Amount Of Derivatives [Member] | Georgia Power [Member]
Derivative [Line Items]
Derivative Asset	(2)	[2]	(11)	[2]
Derivative Liability	(2)	[2]	(11)	[2]
Gross Amount Of Derivatives [Member] | Gulf Power [Member]
Derivative [Line Items]
Derivative Asset	(3)	[2]	(4)	[2]
Derivative Liability	(3)	[2]	(4)	[2]
Gross Amount Of Derivatives [Member] | Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset	(1)	[2]	(2)	[2]
Derivative Liability	(1)	[2]	(2)	[2]
Gross Amount Of Derivatives [Member] | Southern Power [Member]
Derivative [Line Items]
Derivative Asset	(1)	[2]	(1)	[2]
Derivative Liability	$ (1)	[2]	$ (1)	[2]

[1] (a) None of the registrants offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

[2] (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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Segment and Related Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Financial data for business segments

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 September 30, 2013:
Operating revenues	$	4,744	$	365	$	(104	)	$	5,005	$	35		$	(23	)	$	5,017
Segment net income (loss)(a)(b)	765		85		—			850		(1		)	3			852
Nine Months Ended September 30, 2013:
Operating revenues	$	12,430	$	975	$	(285	)	$	13,120	$	108		$	(68	)	$	13,160
Segment net income (loss)(a)(c)	1,099		142		—			1,241		(12		)	1			1,230
Total assets at September 30, 2013	$	59,732	$	4,449	$	(153	)	$	64,028	$	1,090		$	(421	)	$	64,697
Three Months Ended September 30, 2012:
Operating revenues	$	4,794	$	355	$	(116	)	$	5,033	$	36		$	(20	)	$	5,049
Segment net income (loss)(a)	908		68		1			977		1			(2		)	976
Nine Months Ended September 30, 2012:
Operating revenues	$	12,232	$	894	$	(338	)	$	12,788	$	109		$	(63	)	$	12,834
Segment net income (loss)(a)	1,797		144		—			1,941		30			(4		)	1,967
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 September 30, 2013 includes a $150 million pre-tax charge ($93 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 nine months ended September 30, 2013 includes $1.1 billion in pre-tax charges ($704 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.

Financial data for products and services

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2013	$	4,319	$	520	$	166	$	5,005
Three Months Ended September 30, 2012	4,379		497		157		5,033
Nine Months Ended September 30, 2013	$	11,237	$	1,406	$	477	$	13,120
Nine Months Ended September 30, 2012	11,068		1,261		459		12,788

XML

Retirement Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	$ 58	$ 49	$ 174	$ 148
Interest cost	97	98	291	295
Expected return on plan assets	(151)	(145)	(452)	(436)
Amortization:
Prior service costs	7	8	20	23
Net (gain)/loss	50	24	150	71
Net cost	61	34	183	101
Pension Plans [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	12	11	39	33
Interest cost	23	23	69	70
Expected return on plan assets	(39)	(40)	(117)	(121)
Amortization:
Prior service costs	2	2	5	5
Net (gain)/loss	13	6	39	18
Net cost	11	2	35	5
Pension Plans [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	17	15	52	45
Interest cost	35	35	104	106
Expected return on plan assets	(54)	(56)	(160)	(166)
Amortization:
Prior service costs	3	3	8	9
Net (gain)/loss	19	9	56	25
Net cost	20	6	60	19
Pension Plans [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	2	8	7
Interest cost	4	5	13	13
Expected return on plan assets	(6)	(7)	(19)	(20)
Amortization:
Prior service costs	0	0	1	1
Net (gain)/loss	2	1	6	3
Net cost	3	1	9	4
Pension Plans [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	2	8	7
Interest cost	5	5	14	14
Expected return on plan assets	(7)	(6)	(20)	(18)
Amortization:
Prior service costs	1	0	1	1
Net (gain)/loss	2	2	7	3
Net cost	4	3	10	7
Other Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost	6	5	18	16
Interest cost	18	21	55	63
Expected return on plan assets	(14)	(15)	(42)	(45)
Amortization:
Transition obligation	2	2	4	7
Prior service costs	1	1	3	3
Net (gain)/loss	3	2	9	5
Net cost	16	16	47	49
Other Postretirement Benefits [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	1	5	4
Interest cost	5	6	14	17
Expected return on plan assets	(6)	(6)	(18)	(18)
Amortization:
Transition obligation	0	0	0	1
Prior service costs	1	1	3	3
Net (gain)/loss	0	0	1	0
Net cost	2	2	5	7
Other Postretirement Benefits [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	2	6	5
Interest cost	8	8	24	27
Expected return on plan assets	(7)	(7)	(19)	(21)
Amortization:
Transition obligation	1	2	3	5
Prior service costs	0	0	0	0
Net (gain)/loss	2	1	6	3
Net cost	7	6	20	19
Other Postretirement Benefits [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	0	0	1	1
Interest cost	1	1	2	3
Expected return on plan assets	(1)	0	(1)	(1)
Amortization:
Transition obligation	0	0	0	0
Prior service costs	0	0	0	0
Net (gain)/loss	0	0	0	0
Net cost	0	1	2	3
Other Postretirement Benefits [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	0	0	1	1
Interest cost	1	1	3	3
Expected return on plan assets	0	0	(1)	(1)
Amortization:
Transition obligation	0	0	0	0
Prior service costs	0	0	0	0
Net (gain)/loss	0	0	0	0
Net cost	$ 1	$ 1	$ 3	$ 3

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Assets and liabilities measured at fair value on a recurring basis

As of September 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 September 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	$	—	$	11	$	—	$	11
Interest rate derivatives	—		7		—		7
Nuclear decommissioning trusts(a)	553		844		—		1,397
Cash equivalents	465		—		—		465
Other investments	9		—		15		24
Total	$	1,027	$	862	$	15	$	1,904
Liabilities:
Energy-related derivatives	$	—	$	84	$	—	$	84
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Nuclear decommissioning trusts:(b)
Domestic equity	343		74		—		417
Foreign equity	32		62		—		94
U.S. Treasury and government agency securities	—		27		—		27
Corporate bonds	—		101		—		101
Mortgage and asset backed securities	—		23		—		23
Other	—		10		—		10
Cash equivalents	351		—		—		351
Total	$	726	$	300	$	—	$	1,026
Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15

	Fair Value Measurements Using
As of September 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	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts:(b) (c)
Domestic equity	178		1		—		179
Foreign equity	—		125		—		125
U.S. Treasury and government agency securities	—		88		—		88
Municipal bonds	—		64		—		64
Corporate bonds	—		133		—		133
Mortgage and asset backed securities	—		116		—		116
Other	—		19		—		19
Total	$	178	$	548	$	—	$	726
Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	29
Gulf Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Cash equivalents	16		—		—		16
Total	$	16	$	3	$	—	$	19
Liabilities:
Energy-related derivatives	$	—	$	25	$	—	$	25
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Liabilities:
Energy-related derivatives	$	—	$	14	$	—	$	14
Southern Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents	60		—		—		60
Total	$	60	$	2	$	—	$	62
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 September 30, 2013, approximately $14 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.

Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments

As of September 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 September 30, 2013:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	125	None	Monthly	5 days
Corporate bonds - commingled funds	4		None	Daily	1 to 3 days
Equity - commingled funds	62		None	Daily/Monthly	Daily/7 days
Other - commingled funds	19		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	104		None	Daily	15 days
Cash equivalents:
Money market funds	465		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	62		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	104		None	Daily	15 days
Cash equivalents:
Money market funds	351		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	125		None	Monthly	5 days
Corporate bonds - commingled funds	4		None	Daily	Not applicable
Other - commingled funds	19		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	16		None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	60		None	Daily	Not applicable

Financial instruments for which carrying amount did not equal fair value

As of September 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	$	22,194	$	22,822
Alabama Power	$	6,179	$	6,536
Georgia Power	$	9,222	$	9,400
Gulf Power	$	1,246	$	1,293
Mississippi Power	$	2,140	$	2,108
Southern Power	$	1,628	$	1,667

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Net cash paid for capitalized interest	$ 67,000	$ 62,000
Alabama Power [Member]
Net cash paid for capitalized interest	8,000	5,000
Georgia Power [Member]
Net cash paid for capitalized interest	10,000	17,000
Gulf Power [Member]
Net cash paid for capitalized interest	2,291	1,846
Mississippi Power [Member]
Interest paid	53,450	45,079
Net cash paid for capitalized interest	37,882	22,131
Southern Power [Member]
Net cash paid for capitalized interest	$ 7,682	$ 16,436

XML

Condensed Consolidated Balance Sheets (Unaudited) - Parenthetical (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Common stock, par value per share	$ 5	$ 5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Common stock, shares issued	890,000,000	878,000,000
Treasury shares at cost	8,100,000	10,000,000
Alabama Power [Member]
Common stock, par value per share	$ 40	$ 40
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares outstanding	30,537,500	30,537,500
Georgia Power [Member]
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	9,261,500	9,261,500
Gulf Power [Member]
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	4,942,717	4,542,717
Mississippi Power [Member]
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	1,130,000	1,130,000
Common stock, shares outstanding	1,121,000	1,121,000
Southern Power [Member]
Other intangible assets, accumulated amortization	$ 4,996	$ 3,141
Common stock, par value per share	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000	1,000,000
Common stock, shares outstanding	1,000	1,000

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of September 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 September 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	$	—	$	11	$	—	$	11
Interest rate derivatives	—		7		—		7
Nuclear decommissioning trusts(a)	553		844		—		1,397
Cash equivalents	465		—		—		465
Other investments	9		—		15		24
Total	$	1,027	$	862	$	15	$	1,904
Liabilities:
Energy-related derivatives	$	—	$	84	$	—	$	84
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Nuclear decommissioning trusts:(b)
Domestic equity	343		74		—		417
Foreign equity	32		62		—		94
U.S. Treasury and government agency securities	—		27		—		27
Corporate bonds	—		101		—		101
Mortgage and asset backed securities	—		23		—		23
Other	—		10		—		10
Cash equivalents	351		—		—		351
Total	$	726	$	300	$	—	$	1,026
Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15

	Fair Value Measurements Using
As of September 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	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts:(b) (c)
Domestic equity	178		1		—		179
Foreign equity	—		125		—		125
U.S. Treasury and government agency securities	—		88		—		88
Municipal bonds	—		64		—		64
Corporate bonds	—		133		—		133
Mortgage and asset backed securities	—		116		—		116
Other	—		19		—		19
Total	$	178	$	548	$	—	$	726
Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	29
Gulf Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Cash equivalents	16		—		—		16
Total	$	16	$	3	$	—	$	19
Liabilities:
Energy-related derivatives	$	—	$	25	$	—	$	25
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Liabilities:
Energy-related derivatives	$	—	$	14	$	—	$	14
Southern Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents	60		—		—		60
Total	$	60	$	2	$	—	$	62
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 September 30, 2013, approximately $14 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and 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.

As of September 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 September 30, 2013:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	125	None	Monthly	5 days
Corporate bonds - commingled funds	4		None	Daily	1 to 3 days
Equity - commingled funds	62		None	Daily/Monthly	Daily/7 days
Other - commingled funds	19		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	104		None	Daily	15 days
Cash equivalents:
Money market funds	465		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	62		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	104		None	Daily	15 days
Cash equivalents:
Money market funds	351		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	125		None	Monthly	5 days
Corporate bonds - commingled funds	4		None	Daily	Not applicable
Other - commingled funds	19		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	16		None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	60		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 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 nine months ended September 30, 2013, the fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $60 million and $112 million, respectively, at Southern Company. For the three and nine months ended September 30, 2013, Alabama Power recorded an increase in fair value of $33 million and $76 million, respectively, as an increase in regulatory liabilities. For the three and nine months ended September 30, 2013, Georgia Power recorded an increase in fair value of $27 million and $36 million, respectively, as a reduction of its regulatory asset related to AROs.

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 September 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	$	22,194	$	22,822
Alabama Power	$	6,179	$	6,536
Georgia Power	$	9,222	$	9,400
Gulf Power	$	1,246	$	1,293
Mississippi Power	$	2,140	$	2,108
Southern Power	$	1,628	$	1,667

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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Introduction

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

INTRODUCTION

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 September 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. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

In September 2013, Alabama Power received a 2013 decommissioning cost site study for Plant Farley. Site study cost is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning based on the 2013 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076

	(in millions)
Site study costs:
Radiated structures	$	1,362
Non-radiated structures	80
Total site study costs	$	1,442

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates due to changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an escalation rate of 4.5% and a trust earnings rate of 7.0%, net of fees and taxes. The next site study is expected to be conducted in 2018.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company and Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information.

Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. In September 2013, Alabama Power received a new ARO liability cost study for the decommissioning of Plant Farley based on the 2013 site study, which increased the estimated ARO liability by approximately $102 million.

As of September 30, 2013 and 2012, details of the ARO related to the decommissioning of Plant Farley included in Southern Company's and Alabama Power's Condensed Balance Sheets herein are as follows:

	2013		2012
	(in millions)
Balance at beginning of year	$	589	$	553
Liabilities incurred	—		—
Liabilities settled	—		(1		)
Accretion	29		28
Cash flow revisions	102		—
Balance at end of period	$	720	$	580

XML

Financing (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Credit arrangements by company
Expires, 2013	$ 36	[1]
Expires, 2014	553	[1]
Expires, 2015	60	[1]
Expires, 2016	480	[1]
Expires, 2018	4,100	[1]
Total	5,229
Unused	5,201
Executable Term-Loans, One Year	148
Executable Term-Loans, Two Years	40
Due Within One Year, Term Out	188
Due Within One Year, No Term Out	331
Southern Company [Member]
Credit arrangements by company
Expires, 2013	0	[1]
Expires, 2014	0	[1]
Expires, 2015	0
Expires, 2016	0	[1]
Expires, 2018	1,000	[1]
Total	1,000
Unused	1,000
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Alabama Power [Member]
Credit arrangements by company
Expires, 2013	1	[1]
Expires, 2014	268	[1]
Expires, 2015	35
Expires, 2016	0	[1]
Expires, 2018	1,000	[1]
Total	1,304
Unused	1,304
Executable Term-Loans, One Year	53
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	53
Due Within One Year, No Term Out	146
Georgia Power [Member]
Credit arrangements by company
Expires, 2013	0	[1]
Expires, 2014	0	[1]
Expires, 2015	0
Expires, 2016	150	[1]
Expires, 2018	1,600	[1]
Total	1,750
Unused	1,736
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Gulf Power [Member]
Credit arrangements by company
Expires, 2013	20	[1]
Expires, 2014	90	[1]
Expires, 2015	0
Expires, 2016	165	[1]
Expires, 2018	0	[1]
Total	275
Unused	275
Executable Term-Loans, One Year	45
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	45
Due Within One Year, No Term Out	65
Mississippi Power [Member]
Credit arrangements by company
Expires, 2013	15	[1]
Expires, 2014	120	[1]
Expires, 2015	0
Expires, 2016	165	[1]
Expires, 2018	0	[1]
Total	300
Unused	300
Executable Term-Loans, One Year	25
Executable Term-Loans, Two Years	40
Due Within One Year, Term Out	65
Due Within One Year, No Term Out	70
Southern Power [Member]
Credit arrangements by company
Expires, 2013	0	[1]
Expires, 2014	0	[1]
Expires, 2015	0
Expires, 2016	0	[1]
Expires, 2018	500	[1]
Total	500
Unused	486
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Other Subsidiaries [Member]
Credit arrangements by company
Expires, 2013	0	[1]
Expires, 2014	75	[1]
Expires, 2015	25
Expires, 2016	0	[1]
Expires, 2018	0	[1]
Total	100
Unused	100
Executable Term-Loans, One Year	25
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	25
Due Within One Year, No Term Out	$ 50

[1] No credit arrangements expire in 2017.

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Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and nine months ended September 30, 2013 and 2012 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2013
Service cost	$	58		$	12		$	17		$	3		$	3
Interest cost	97			23			35			4			5
Expected return on plan assets	(151		)	(39		)	(54		)	(6		)	(7		)
Amortization:
Prior service costs	7			2			3			—			1
Net (gain)/loss	50			13			19			2			2
Net cost	$	61		$	11		$	20		$	3		$	4
Nine Months Ended September 30, 2013
Service cost	$	174		$	39		$	52		$	8		$	8
Interest cost	291			69			104			13			14
Expected return on plan assets	(452		)	(117		)	(160		)	(19		)	(20		)
Amortization:
Prior service costs	20			5			8			1			1
Net (gain)/loss	150			39			56			6			7
Net cost	$	183		$	35		$	60		$	9		$	10
Three Months Ended September 30, 2012
Service cost	$	49		$	11		$	15		$	2		$	2
Interest cost	98			23			35			5			5
Expected return on plan assets	(145		)	(40		)	(56		)	(7		)	(6		)
Amortization:
Prior service costs	8			2			3			—			—
Net (gain)/loss	24			6			9			1			2
Net cost	$	34		$	2		$	6		$	1		$	3
Nine Months Ended September 30, 2012
Service cost	$	148		$	33		$	45		$	7		$	7
Interest cost	295			70			106			13			14
Expected return on plan assets	(436		)	(121		)	(166		)	(20		)	(18		)
Amortization:
Prior service costs	23			5			9			1			1
Net (gain)/loss	71			18			25			3			3
Net cost	$	101		$	5		$	19		$	4		$	7

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2013
Service cost	$	6		$	2		$	3		$	—		$	—
Interest cost	18			5			8			1			1
Expected return on plan assets	(14		)	(6		)	(7		)	(1		)	—
Amortization:
Transition obligation	2			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	3			—			2			—			—
Net cost	$	16		$	2		$	7		$	—		$	1
Nine Months Ended September 30, 2013
Service cost	$	18		$	5		$	6		$	1		$	1
Interest cost	55			14			24			2			3
Expected return on plan assets	(42		)	(18		)	(19		)	(1		)	(1		)
Amortization:
Transition obligation	4			—			3			—			—
Prior service costs	3			3			—			—			—
Net (gain)/loss	9			1			6			—			—
Net cost	$	47		$	5		$	20		$	2		$	3
Three Months Ended September 30, 2012
Service cost	$	5		$	1		$	2		$	—		$	—
Interest cost	21			6			8			1			1
Expected return on plan assets	(15		)	(6		)	(7		)	—			—
Amortization:
Transition obligation	2			—			2			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	2			—			1			—			—
Net cost	$	16		$	2		$	6		$	1		$	1
Nine Months Ended September 30, 2012
Service cost	$	16		$	4		$	5		$	1		$	1
Interest cost	63			17			27			3			3
Expected return on plan assets	(45		)	(18		)	(21		)	(1		)	(1		)
Amortization:
Transition obligation	7			1			5			—			—
Prior service costs	3			3			—			—			—
Net (gain)/loss	5			—			3			—			—
Net cost	$	49		$	7		$	19		$	3		$	3

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Introduction Estimated Cost Of Decommissioning (Details) (Alabama Power [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Public Utilities, General Disclosures [Line Items]
Significant Assumption Of Inflation Rate Used To Determine Costs For Rate Making	4.50%
Site Study Costs	$ 1,442
SignificantAssumption Of Trust Earnings Rate Used To Determine Costs For Rate Making	7.00%
Site Study Cost Radiated Structures [Member]
Public Utilities, General Disclosures [Line Items]
Site Study Costs	1,362
Site Study Cost Non-Radiated Structures [Member]
Public Utilities, General Disclosures [Line Items]
Site Study Costs	$ 80
Plant Farley [Member]
Public Utilities, General Disclosures [Line Items]
Estimated Cost Of Decommissioning Completion Year	2076
Estimated Cost Of Decommissioning Beginning Year	2037

XML

Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Long-term debt:
Long-term debt, Carrying Amount	$ 22,194
Long-term debt, Fair Value	22,822
Alabama Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	6,179
Long-term debt, Fair Value	6,536
Georgia Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	9,222
Long-term debt, Fair Value	9,400
Gulf Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,246
Long-term debt, Fair Value	1,293
Mississippi Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	2,140
Long-term debt, Fair Value	2,108
Southern Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,628
Long-term debt, Fair Value	$ 1,667

XML

Segment and Related Information - Financial Data for Business Segments (Details) (USD $)	3 Months Ended				9 Months Ended				3 Months Ended				9 Months Ended					3 Months Ended				9 Months Ended					3 Months Ended		9 Months Ended		3 Months Ended				9 Months Ended					3 Months Ended				9 Months Ended					3 Months Ended				9 Months Ended					3 Months Ended				9 Months Ended					3 Months Ended		9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013	Sep. 30, 2012		Dec. 31, 2012	Sep. 30, 2013 Electric Utilities [Member]		Sep. 30, 2012 Electric Utilities [Member]		Sep. 30, 2013 Electric Utilities [Member]		Sep. 30, 2012 Electric Utilities [Member]		Dec. 31, 2012 Electric Utilities [Member]	Sep. 30, 2013 Traditional Operating Companies [Member] Electric Utilities [Member]		Sep. 30, 2012 Traditional Operating Companies [Member] Electric Utilities [Member]		Sep. 30, 2013 Traditional Operating Companies [Member] Electric Utilities [Member]		Sep. 30, 2012 Traditional Operating Companies [Member] Electric Utilities [Member]		Dec. 31, 2012 Traditional Operating Companies [Member] Electric Utilities [Member]	Sep. 30, 2013 Southern Power [Member]	Sep. 30, 2012 Southern Power [Member]	Sep. 30, 2013 Southern Power [Member]	Sep. 30, 2012 Southern Power [Member]	Sep. 30, 2013 Southern Power [Member] Electric Utilities [Member]		Sep. 30, 2012 Southern Power [Member] Electric Utilities [Member]		Sep. 30, 2013 Southern Power [Member] Electric Utilities [Member]		Sep. 30, 2012 Southern Power [Member] Electric Utilities [Member]		Dec. 31, 2012 Southern Power [Member] Electric Utilities [Member]	Sep. 30, 2013 Eliminations [Member]		Sep. 30, 2012 Eliminations [Member]		Sep. 30, 2013 Eliminations [Member]		Sep. 30, 2012 Eliminations [Member]		Dec. 31, 2012 Eliminations [Member]	Sep. 30, 2013 Eliminations [Member] Electric Utilities [Member]		Sep. 30, 2012 Eliminations [Member] Electric Utilities [Member]		Sep. 30, 2013 Eliminations [Member] Electric Utilities [Member]		Sep. 30, 2012 Eliminations [Member] Electric Utilities [Member]		Dec. 31, 2012 Eliminations [Member] Electric Utilities [Member]	Sep. 30, 2013 All Other [Member]		Sep. 30, 2012 All Other [Member]		Sep. 30, 2013 All Other [Member]		Sep. 30, 2012 All Other [Member]		Dec. 31, 2012 All Other [Member]	Sep. 30, 2013 Kemper Igcc [Member]	Mar. 31, 2013 Kemper Igcc [Member]	Sep. 30, 2013 Kemper Igcc [Member]
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	$ 5,017,000,000		$ 5,049,000,000		$ 13,160,000,000	$ 12,834,000,000			$ 5,005,000,000		$ 5,033,000,000		$ 13,120,000,000		$ 12,788,000,000			$ 4,744,000,000		$ 4,794,000,000		$ 12,430,000,000		$ 12,232,000,000			$ 97,000,000	$ 112,000,000	$ 264,000,000	$ 330,000,000	$ 365,000,000		$ 355,000,000		$ 975,000,000		$ 894,000,000			$ (23,000,000)		$ (20,000,000)		$ (68,000,000)		$ (63,000,000)			$ (104,000,000)		$ (116,000,000)		$ (285,000,000)		$ (338,000,000)			$ 35,000,000		$ 36,000,000		$ 108,000,000		$ 109,000,000
Financial data for business segments
Electric Utilities' Revenues	5,017,000,000		5,049,000,000		13,160,000,000	12,834,000,000			5,005,000,000		5,033,000,000		13,120,000,000		12,788,000,000			4,744,000,000		4,794,000,000		12,430,000,000		12,232,000,000			97,000,000	112,000,000	264,000,000	330,000,000	365,000,000		355,000,000		975,000,000		894,000,000			(23,000,000)		(20,000,000)		(68,000,000)		(63,000,000)			(104,000,000)		(116,000,000)		(285,000,000)		(338,000,000)			35,000,000		36,000,000		108,000,000		109,000,000
Segment net income (loss)	852,000,000	[1],[2]	976,000,000	[1]	1,230,000,000	1,967,000,000	[1]		850,000,000	[1],[2]	977,000,000	[1]	1,241,000,000	[1],[3]	1,941,000,000	[1]		765,000,000	[1],[2]	908,000,000	[1]	1,099,000,000	[1],[3]	1,797,000,000	[1]						85,000,000	[1],[2]	68,000,000	[1]	142,000,000	[1],[3]	144,000,000	[1]		3,000,000	[1],[2]	(2,000,000)	[1]	1,000,000	[1],[3]	(4,000,000)	[1]		0	[1],[2]	1,000,000	[1]	0	[1],[3]	0	[1]		(1,000,000)	[1],[2]	1,000,000	[1]	(12,000,000)	[1],[3]	30,000,000	[1]
Total assets	64,697,000,000				64,697,000,000			63,149,000,000	64,028,000,000				64,028,000,000				62,251,000,000	59,732,000,000				59,732,000,000				58,600,000,000					4,449,000,000				4,449,000,000				3,780,000,000	(421,000,000)				(421,000,000)				(218,000,000)	(153,000,000)				(153,000,000)				(129,000,000)	1,090,000,000				1,090,000,000				1,116,000,000
Pre-tax charge to income																																																																			150,000,000	540,000,000	1,100,000,000
After tax charge to income					$ 16,000,000																																																														$ 93,000,000	$ 333,500,000	$ 704,000,000

[1] After dividends on preferred and preference stock of subsidiaries.

[2] Segment net income (loss) for the three months ended September 30, 2013 includes a $150 million pre-tax charge ($93 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.

[3] Segment net income (loss) for the nine months ended September 30, 2013 includes $1.1 billion in pre-tax charges ($704 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.

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Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended																																																								9 Months Ended
	Sep. 30, 2013 Interest Expense [Member]	Sep. 30, 2012 Interest Expense [Member]	Sep. 30, 2013 Interest Expense [Member] Alabama Power [Member]	Sep. 30, 2012 Interest Expense [Member] Alabama Power [Member]	Sep. 30, 2013 Interest Expense [Member] Southern Power [Member]	Sep. 30, 2012 Interest Expense [Member] Southern Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member]	Dec. 31, 2012 Energy Related Derivative [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Alabama Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Alabama Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Georgia Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Georgia Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Gulf Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Gulf Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Mississippi Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Mississippi Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets current [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets current [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets current [Member] Alabama Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets current [Member] Alabama Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets current [Member] Georgia Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets current [Member] Georgia Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets current [Member] Gulf Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets current [Member] Gulf Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets current [Member] Mississippi Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets current [Member] Mississippi Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets deferred [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets deferred [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets deferred [Member] Alabama Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets deferred [Member] Alabama Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets deferred [Member] Georgia Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets deferred [Member] Georgia Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets deferred [Member] Gulf Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets deferred [Member] Gulf Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory assets deferred [Member] Mississippi Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory assets deferred [Member] Mississippi Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities current [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities current [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities current [Member] Alabama Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities current [Member] Alabama Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities current [Member] Georgia Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities current [Member] Georgia Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities current [Member] Gulf Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities current [Member] Gulf Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities current [Member] Mississippi Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities current [Member] Mississippi Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member] Alabama Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member] Alabama Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member] Georgia Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member] Georgia Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member] Gulf Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member] Gulf Power [Member]	Sep. 30, 2013 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member] Mississippi Power [Member]	Dec. 31, 2012 Energy Related Derivative [Member] Other regulatory liabilities deferred [Member] Mississippi Power [Member]	Sep. 30, 2013 Interest rate derivatives [Member]	Sep. 30, 2012 Interest rate derivatives [Member]	Sep. 30, 2013 Interest rate derivatives [Member] Alabama Power [Member]	Sep. 30, 2012 Interest rate derivatives [Member] Alabama Power [Member]	Sep. 30, 2013 Interest rate derivatives [Member] Southern Power [Member]	Sep. 30, 2012 Interest rate derivatives [Member] Southern Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)							$ (74)	$ (86)	$ (12)	$ (13)	$ (27)	$ (34)	$ (22)	$ (23)	$ (13)	$ (16)	$ (48)	$ (74)	$ (9)	$ (14)	$ (19)	$ (30)	$ (13)	$ (17)	$ (7)	$ (13)	$ (35)	$ (35)	$ (6)	$ (4)	$ (10)	$ (15)	$ (12)	$ (10)	$ (7)	$ (6)	$ 6	$ 10	$ 2	$ 2	$ 1	$ 6	$ 2	$ 1	$ 1	$ 1	$ 3	$ 13	$ 1	$ 3	$ 1	$ 5	$ 1	$ 3	$ 0	$ 2
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)																																																									0	(16)	0	(15)	0	0
Gain (Loss) Reclassified from AOCI into Income (Effective Portion)	$ (12)	$ (12)	$ (2)	$ 0	$ (6)	$ (8)

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Effective Tax Rate and Unrecognized Tax Benefits - Impact on Effective Tax Rate (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Impact on effective tax rate
Tax positions impacting the effective tax rate	$ 7	$ 5
Tax positions not impacting the effective tax rate	0	65
Balance of unrecognized tax benefits	$ 7	$ 70

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income	$ 869,000,000	$ 993,000,000	$ 1,279,000,000	$ 2,016,000,000
Qualifying hedges:
Changes in fair value, net of tax	0	(4,000,000)	0	(11,000,000)
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	3,000,000	7,000,000	7,000,000
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	1,000,000	4,000,000	3,000,000
Total other comprehensive income (loss)	2,000,000	0	11,000,000	(1,000,000)
Dividends on preferred and preference stock of subsidiaries	(17,000,000)	(17,000,000)	(49,000,000)	(49,000,000)
Comprehensive Income	854,000,000	976,000,000	1,241,000,000	1,966,000,000
Alabama Power [Member]
Net Income	268,000,000	290,000,000	602,000,000	621,000,000
Qualifying hedges:
Changes in fair value, net of tax	0	(2,000,000)	0	(9,000,000)
Reclassification adjustment for amounts included in net income, net of tax	0	0	1,000,000	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	(2,000,000)	1,000,000	(9,000,000)
Comprehensive Income	268,000,000	288,000,000	603,000,000	612,000,000
Georgia Power [Member]
Net Income	491,000,000	529,000,000	979,000,000	1,000,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	1,000,000	2,000,000	2,000,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	1,000,000	1,000,000	2,000,000	2,000,000
Comprehensive Income	492,000,000	530,000,000	981,000,000	1,002,000,000
Gulf Power [Member]
Net Income	47,005,000	49,305,000	104,581,000	108,035,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	93,000	143,000	379,000	429,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	93,000	143,000	379,000	429,000
Comprehensive Income	47,098,000	49,448,000	104,960,000	108,464,000
Mississippi Power [Member]
Net Income	(23,682,000)	55,058,000	(488,247,000)	116,206,000
Qualifying hedges:
Changes in fair value, net of tax	0	1,000	0	(477,000)
Reclassification adjustment for amounts included in net income, net of tax	212,000	212,000	637,000	450,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	212,000	213,000	637,000	(27,000)
Comprehensive Income	(23,470,000)	55,271,000	(487,610,000)	116,179,000
Southern Power [Member]
Net Income	85,153,000	68,376,000	142,267,000	144,294,000
Qualifying hedges:
Changes in fair value, net of tax	0	338,000	0	152,000
Reclassification adjustment for amounts included in net income, net of tax	338,000	1,569,000	3,619,000	4,608,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	338,000	1,907,000	3,619,000	4,760,000
Comprehensive Income	$ 85,491,000	$ 70,283,000	$ 145,886,000	$ 149,054,000

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Retirement Benefits

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

RETIREMENT BENEFITS

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.

Components of the net periodic benefit costs for the three and nine months ended September 30, 2013 and 2012 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2013
Service cost	$	58		$	12		$	17		$	3		$	3
Interest cost	97			23			35			4			5
Expected return on plan assets	(151		)	(39		)	(54		)	(6		)	(7		)
Amortization:
Prior service costs	7			2			3			—			1
Net (gain)/loss	50			13			19			2			2
Net cost	$	61		$	11		$	20		$	3		$	4
Nine Months Ended September 30, 2013
Service cost	$	174		$	39		$	52		$	8		$	8
Interest cost	291			69			104			13			14
Expected return on plan assets	(452		)	(117		)	(160		)	(19		)	(20		)
Amortization:
Prior service costs	20			5			8			1			1
Net (gain)/loss	150			39			56			6			7
Net cost	$	183		$	35		$	60		$	9		$	10
Three Months Ended September 30, 2012
Service cost	$	49		$	11		$	15		$	2		$	2
Interest cost	98			23			35			5			5
Expected return on plan assets	(145		)	(40		)	(56		)	(7		)	(6		)
Amortization:
Prior service costs	8			2			3			—			—
Net (gain)/loss	24			6			9			1			2
Net cost	$	34		$	2		$	6		$	1		$	3
Nine Months Ended September 30, 2012
Service cost	$	148		$	33		$	45		$	7		$	7
Interest cost	295			70			106			13			14
Expected return on plan assets	(436		)	(121		)	(166		)	(20		)	(18		)
Amortization:
Prior service costs	23			5			9			1			1
Net (gain)/loss	71			18			25			3			3
Net cost	$	101		$	5		$	19		$	4		$	7

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2013
Service cost	$	6		$	2		$	3		$	—		$	—
Interest cost	18			5			8			1			1
Expected return on plan assets	(14		)	(6		)	(7		)	(1		)	—
Amortization:
Transition obligation	2			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	3			—			2			—			—
Net cost	$	16		$	2		$	7		$	—		$	1
Nine Months Ended September 30, 2013
Service cost	$	18		$	5		$	6		$	1		$	1
Interest cost	55			14			24			2			3
Expected return on plan assets	(42		)	(18		)	(19		)	(1		)	(1		)
Amortization:
Transition obligation	4			—			3			—			—
Prior service costs	3			3			—			—			—
Net (gain)/loss	9			1			6			—			—
Net cost	$	47		$	5		$	20		$	2		$	3
Three Months Ended September 30, 2012
Service cost	$	5		$	1		$	2		$	—		$	—
Interest cost	21			6			8			1			1
Expected return on plan assets	(15		)	(6		)	(7		)	—			—
Amortization:
Transition obligation	2			—			2			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	2			—			1			—			—
Net cost	$	16		$	2		$	6		$	1		$	1
Nine Months Ended September 30, 2012
Service cost	$	16		$	4		$	5		$	1		$	1
Interest cost	63			17			27			3			3
Expected return on plan assets	(45		)	(18		)	(21		)	(1		)	(1		)
Amortization:
Transition obligation	7			1			5			—			—
Prior service costs	3			3			—			—			—
Net (gain)/loss	5			—			3			—			—
Net cost	$	49		$	7		$	19		$	3		$	3

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Operating Activities:
Consolidated net income	$ 1,279,000,000	$ 2,016,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	1,725,000,000	1,602,000,000
Deferred income taxes	263,000,000	645,000,000
Allowance for equity funds used during construction	(139,000,000)	(102,000,000)
Leveraged lease income (loss)	11,000,000	(16,000,000)
Pension, postretirement, and other employee benefits	124,000,000	78,000,000
Stock based compensation expense	48,000,000	45,000,000
Retail fuel cost over recovery - long-term	(123,000,000)	118,000,000
Estimated loss on Kemper IGCC	1,140,000,000	0
Other, net	64,000,000	34,000,000
Changes in certain current assets and liabilities --
-Receivables	(407,000,000)	(157,000,000)
-Fossil fuel stock	471,000,000	(232,000,000)
-Materials and supplies	33,000,000	(28,000,000)
-Other current assets	(1,000,000)	22,000,000
-Accounts payable	(140,000,000)	(240,000,000)
-Accrued taxes	268,000,000	311,000,000
-Accrued compensation	(198,000,000)	(142,000,000)
-Retail fuel cost over recovery - short-term	(3,000,000)	112,000,000
-Other current liabilities	(4,000,000)	(22,000,000)
Net cash provided from operating activities	4,411,000,000	4,044,000,000
Investing Activities:
Property additions	(3,978,000,000)	(3,558,000,000)
Investment of restricted cash	(169,000,000)	(230,000,000)
Distribution of restricted cash	94,000,000	234,000,000
Nuclear decommissioning trust fund purchases	(744,000,000)	(758,000,000)
Nuclear decommissioning trust fund sales	742,000,000	756,000,000
Cost of removal, net of salvage	(90,000,000)	(83,000,000)
Change in construction payables	(8,000,000)	(61,000,000)
Other investing activities	51,000,000	(58,000,000)
Net cash used for investing activities	(4,102,000,000)	(3,758,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(70,000,000)	(521,000,000)
Proceeds --
Long-term debt issuances	2,421,000,000	3,114,000,000
Interest-bearing refundable deposit related to asset sale	0	150,000,000
Preference stock	50,000,000	0
Common stock issuances	479,000,000	381,000,000
Redemptions --
Long-term debt	(1,767,000,000)	(2,098,000,000)
Common stock repurchased	(19,000,000)	(85,000,000)
Payment of common stock dividends	(1,314,000,000)	(1,267,000,000)
Payment of dividends on preferred and preference stock of subsidiaries	(49,000,000)	(49,000,000)
Other financing activities	14,000,000	30,000,000
Net cash provided from (used for) financing activities	(255,000,000)	(345,000,000)
Net Change in Cash and Cash Equivalents	54,000,000	(59,000,000)
Cash and Cash Equivalents at Beginning of Period	628,000,000	1,315,000,000
Cash and Cash Equivalents at End of Period	682,000,000	1,256,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	564,000,000	589,000,000
Income taxes, net	149,000,000	6,000,000
Noncash transactions - accrued property additions at end of period	539,000,000	531,000,000
Noncash transactions — capital lease obligation	83,000,000	0
Alabama Power [Member]
Operating Activities:
Consolidated net income	602,000,000	621,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	616,000,000	574,000,000
Deferred income taxes	200,000,000	132,000,000
Allowance for equity funds used during construction	(23,000,000)	(13,000,000)
Pension, postretirement, and other employee benefits	17,000,000	10,000,000
Stock based compensation expense	8,000,000	7,000,000
Other, net	(24,000,000)	(3,000,000)
Changes in certain current assets and liabilities --
-Receivables	(98,000,000)	(83,000,000)
-Fossil fuel stock	173,000,000	(93,000,000)
-Materials and supplies	16,000,000	(5,000,000)
-Other current assets	(18,000,000)	(1,000,000)
-Accounts payable	(109,000,000)	(167,000,000)
-Accrued taxes	105,000,000	146,000,000
-Accrued compensation	(36,000,000)	(27,000,000)
-Retail fuel cost over recovery - short-term	42,000,000	2,000,000
-Other current liabilities	(2,000,000)	(15,000,000)
Net cash provided from operating activities	1,469,000,000	1,085,000,000
Investing Activities:
Property additions	(779,000,000)	(616,000,000)
Nuclear decommissioning trust fund purchases	(162,000,000)	(128,000,000)
Nuclear decommissioning trust fund sales	162,000,000	128,000,000
Cost of removal, net of salvage	(29,000,000)	(17,000,000)
Change in construction payables	12,000,000	(2,000,000)
Other investing activities	35,000,000	(11,000,000)
Net cash used for investing activities	(761,000,000)	(646,000,000)
Proceeds --
Capital contributions from parent company	18,000,000	22,000,000
Senior notes issuances	0	250,000,000
Redemptions --
Pollution control revenue bonds	0	(1,000,000)
Senior notes	0	(250,000,000)
Payment of preferred and preference stock dividends	(30,000,000)	(30,000,000)
Payment of common stock dividends	(397,000,000)	(404,000,000)
Other financing activities	0	(4,000,000)
Net cash provided from (used for) financing activities	(409,000,000)	(417,000,000)
Net Change in Cash and Cash Equivalents	299,000,000	22,000,000
Cash and Cash Equivalents at Beginning of Period	137,000,000	344,000,000
Cash and Cash Equivalents at End of Period	436,000,000	366,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	182,000,000	203,000,000
Income taxes, net	154,000,000	172,000,000
Noncash transactions - accrued property additions at end of period	43,000,000	16,000,000
Georgia Power [Member]
Operating Activities:
Consolidated net income	979,000,000	1,000,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	734,000,000	684,000,000
Deferred income taxes	354,000,000	243,000,000
Allowance for equity funds used during construction	(24,000,000)	(41,000,000)
Pension, postretirement, and other employee benefits	58,000,000	23,000,000
Retail fuel cost over recovery - long-term	(123,000,000)	118,000,000
Deferred expenses	(34,000,000)	(20,000,000)
Other, net	28,000,000	0
Changes in certain current assets and liabilities --
-Receivables	(191,000,000)	(23,000,000)
-Fossil fuel stock	213,000,000	(126,000,000)
-Prepaid income taxes	11,000,000	40,000,000
-Other current assets	38,000,000	4,000,000
-Accounts payable	(5,000,000)	(57,000,000)
-Accrued taxes	131,000,000	40,000,000
-Accrued compensation	(53,000,000)	(43,000,000)
-Retail fuel cost over recovery - short-term	7,000,000	81,000,000
-Other current liabilities	5,000,000	48,000,000
Net cash provided from operating activities	2,128,000,000	1,971,000,000
Investing Activities:
Property additions	(1,165,000,000)	(1,291,000,000)
Investment of restricted cash	(89,000,000)	(234,000,000)
Distribution of restricted cash	89,000,000	234,000,000
Nuclear decommissioning trust fund purchases	(582,000,000)	(630,000,000)
Nuclear decommissioning trust fund sales	580,000,000	628,000,000
Cost of removal, net of salvage	(42,000,000)	(42,000,000)
Change in construction payables, net of joint owner portion	(28,000,000)	(141,000,000)
Other investing activities	(14,000,000)	9,000,000
Net cash used for investing activities	(1,251,000,000)	(1,467,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	211,000,000	(513,000,000)
Proceeds --
Capital contributions from parent company	30,000,000	29,000,000
Pollution control revenue bonds issuances	89,000,000	234,000,000
Senior notes issuances	850,000,000	1,900,000,000
Redemptions --
Pollution control revenue bonds	(89,000,000)	(234,000,000)
Senior notes	(1,250,000,000)	(550,000,000)
Other long-term debt	0	(250,000,000)
Payment of preferred and preference stock dividends	(13,000,000)	(13,000,000)
Payment of common stock dividends	(680,000,000)	(681,000,000)
Other financing activities	(17,000,000)	(14,000,000)
Net cash provided from (used for) financing activities	(869,000,000)	(92,000,000)
Net Change in Cash and Cash Equivalents	8,000,000	412,000,000
Cash and Cash Equivalents at Beginning of Period	45,000,000	13,000,000
Cash and Cash Equivalents at End of Period	53,000,000	425,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	247,000,000	237,000,000
Income taxes, net	109,000,000	186,000,000
Noncash transactions - accrued property additions at end of period	230,000,000	253,000,000
Gulf Power [Member]
Operating Activities:
Consolidated net income	104,581,000	108,035,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	116,626,000	109,132,000
Deferred income taxes	55,911,000	132,367,000
Allowance for equity funds used during construction	(4,318,000)	(3,988,000)
Pension, postretirement, and other employee benefits	9,279,000	4,361,000
Stock based compensation expense	1,389,000	1,346,000
Other, net	2,509,000	3,839,000
Changes in certain current assets and liabilities --
-Receivables	(49,690,000)	(10,995,000)
-Prepayments	2,568,000	3,066,000
-Fossil fuel stock	24,475,000	14,055,000
-Materials and supplies	(2,683,000)	(3,859,000)
-Prepaid income taxes	23,515,000	28,108,000
-Accounts payable	(9,132,000)	(453,000)
-Accrued taxes	20,648,000	18,566,000
-Accrued compensation	(5,974,000)	(4,263,000)
-Over recovered regulatory clause revenues	(17,092,000)	7,387,000
-Other current liabilities	5,258,000	(925,000)
Net cash provided from operating activities	277,870,000	405,779,000
Investing Activities:
Property additions	(205,161,000)	(239,705,000)
Cost of removal, net of salvage	(12,563,000)	(20,931,000)
Change in construction payables	6,752,000	(542,000)
Payments pursuant to long-term service agreements	(3,843,000)	(6,184,000)
Other investing activities	306,000	627,000
Net cash used for investing activities	(214,509,000)	(266,735,000)
Financing Activities:
Increase (decrease) in notes payable, net	(65,077,000)	(91,699,000)
Proceeds --
Capital contributions from parent company	1,936,000	1,569,000
Pollution control revenue bonds issuances	63,000,000	0
Preference stock	50,000,000	0
Common stock issuances	40,000,000	40,000,000
Senior notes issuances	90,000,000	100,000,000
Redemptions --
Pollution control revenue bonds	(63,000,000)	0
Senior notes	(90,000,000)	(91,363,000)
Payment of preferred and preference stock dividends	(4,753,000)	(4,652,000)
Payment of common stock dividends	(86,550,000)	(86,850,000)
Other financing activities	(3,209,000)	(468,000)
Net cash provided from (used for) financing activities	(67,653,000)	(133,463,000)
Net Change in Cash and Cash Equivalents	(4,292,000)	5,581,000
Cash and Cash Equivalents at Beginning of Period	32,167,000	17,328,000
Cash and Cash Equivalents at End of Period	27,875,000	22,909,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	33,433,000	38,806,000
Income taxes, net	(17,064,000)	(101,825,000)
Noncash transactions - accrued property additions at end of period	30,846,000	25,115,000
Mississippi Power [Member]
Operating Activities:
Consolidated net income	(488,247,000)	116,206,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	68,436,000	65,902,000
Deferred income taxes	(391,143,000)	8,527,000
Investment tax credits	45,228,000	38,811,000
Allowance for equity funds used during construction	(87,740,000)	(43,460,000)
Pension, postretirement, and other employee benefits	12,876,000	6,700,000
Hedge settlements	0	(15,983,000)
Stock based compensation expense	2,029,000	1,718,000
Regulatory assets associated with Kemper IGCC	(23,545,000)	(11,921,000)
Estimated loss on Kemper IGCC	1,062,000,000	0
Kemper regulatory deferral	61,997,000	0
Other, net	8,792,000	7,086,000
Changes in certain current assets and liabilities --
-Receivables	(40,003,000)	(17,622,000)
-Fossil fuel stock	59,608,000	(19,888,000)
-Materials and supplies	(8,029,000)	(2,683,000)
-Prepaid income taxes	33,793,000	2,517,000
-Other current assets	(1,710,000)	(14,652,000)
-Accounts payable	17,397,000	13,581,000
-Accrued taxes	(2,334,000)	2,361,000
-Accrued interest	15,153,000	16,015,000
-Accrued compensation	(8,543,000)	(4,830,000)
-Over recovered regulatory clause revenues	(49,247,000)	10,982,000
-Other current liabilities	0	(1,488,000)
Net cash provided from operating activities	286,768,000	157,879,000
Investing Activities:
Property additions	(1,221,519,000)	(1,169,653,000)
Cost of removal, net of salvage	(5,769,000)	(3,092,000)
Change in construction payables	(6,200,000)	97,360,000
Capital grant proceeds	4,500,000	10,058,000
Proceeds from asset sales	79,020,000	0
Other investing activities	(3,659,000)	(12,891,000)
Net cash used for investing activities	(1,153,627,000)	(1,078,218,000)
Proceeds --
Capital contributions from parent company	601,197,000	429,272,000
Bonds-Other	31,092,000	25,613,000
Interest-bearing refundable deposit related to asset sale	0	150,000,000
Senior notes issuances	0	600,000,000
Other long-term debt issuances	475,000,000	0
Redemptions --
Bonds-Other	(82,563,000)	0
Capital leases	(82,000)	(633,000)
Other long-term debt	(125,000,000)	(205,000,000)
Return of paid in capital	(60,614,000)	0
Payment of preferred and preference stock dividends	(1,299,000)	(1,299,000)
Payment of common stock dividends	(71,956,000)	(80,100,000)
Other financing activities	(1,845,000)	7,597,000
Net cash provided from (used for) financing activities	763,930,000	925,450,000
Net Change in Cash and Cash Equivalents	(102,929,000)	5,111,000
Cash and Cash Equivalents at Beginning of Period	145,008,000	211,585,000
Cash and Cash Equivalents at End of Period	42,079,000	216,696,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	15,568,000	22,948,000
Income taxes, net	(48,307,000)	(11,737,000)
Noncash transactions - accrued property additions at end of period	208,663,000	233,262,000
Noncash transactions — capital lease obligation	82,915,000	0
Southern Power [Member]
Operating Activities:
Consolidated net income	142,267,000	144,294,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	131,955,000	112,013,000
Deferred income taxes	83,331,000	147,993,000
Investment tax credits	(25,137,000)	36,308,000
Deferred revenues	3,136,000	9,299,000
Mark-to-market adjustments	68,000	(8,970,000)
Other, net	894,000	1,168,000
Changes in certain current assets and liabilities --
-Receivables	(28,486,000)	(20,427,000)
-Fossil fuel stock	881,000	(6,440,000)
-Materials and supplies	(5,902,000)	(5,557,000)
-Prepaid income taxes	(12,485,000)	(5,669,000)
-Other current assets	(2,017,000)	(2,159,000)
-Accounts payable	(4,282,000)	5,668,000
-Accrued taxes	12,550,000	48,203,000
-Accrued interest	(8,306,000)	(10,225,000)
-Other current liabilities	235,000	808,000
Net cash provided from operating activities	288,702,000	446,307,000
Investing Activities:
Plant acquisition	(111,600,000)	(113,651,000)
Property additions	(463,873,000)	(97,569,000)
Investment of restricted cash	(20,000,000)	0
Change in construction payables	292,000	(17,557,000)
Payments pursuant to long-term service agreements	(40,978,000)	(52,650,000)
Other investing activities	(1,724,000)	153,000
Net cash used for investing activities	(637,883,000)	(281,274,000)
Financing Activities:
Increase (decrease) in notes payable, net	120,798,000	(78,059,000)
Proceeds --
Capital contributions from parent company	1,897,000	(681,000)
Senior notes issuances	300,000,000	0
Other long-term debt issuances	22,722,000	4,949,000
Redemptions --
Other long-term debt	(220,000)	(650,000)
Payment of common stock dividends	(96,840,000)	(95,250,000)
Other financing activities	14,369,000	3,776,000
Net cash provided from (used for) financing activities	362,726,000	(165,915,000)
Net Change in Cash and Cash Equivalents	13,545,000	(882,000)
Cash and Cash Equivalents at Beginning of Period	28,592,000	16,943,000
Cash and Cash Equivalents at End of Period	42,137,000	16,061,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	55,190,000	46,163,000
Income taxes, net	(6,518,000)	(137,756,000)
Noncash transactions - accrued property additions at end of period	$ 36,370,000	$ 21,034,000

XML

Condensed Consolidated Statements of Income (Unaudited) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013	Sep. 30, 2012
Operating Revenues:
Retail revenues	$ 4,319,000,000		$ 4,379,000,000		$ 11,237,000,000	$ 11,068,000,000
Wholesale revenues	520,000,000		497,000,000		1,406,000,000	1,261,000,000
Other electric revenues	166,000,000		157,000,000		477,000,000	459,000,000
Other revenues	12,000,000		16,000,000		40,000,000	46,000,000
Total operating revenues	5,017,000,000		5,049,000,000		13,160,000,000	12,834,000,000
Operating Expenses:
Fuel	1,580,000,000		1,553,000,000		4,216,000,000	3,907,000,000
Purchased power	145,000,000		164,000,000		367,000,000	455,000,000
Other operations and maintenance	928,000,000		906,000,000		2,849,000,000	2,817,000,000
MC Asset Recovery insurance settlement	0		0		0	(19,000,000)
Depreciation and amortization	480,000,000		449,000,000		1,422,000,000	1,335,000,000
Taxes other than income taxes	243,000,000		237,000,000		710,000,000	690,000,000
Estimated loss on Kemper IGCC	150,000,000		0		1,140,000,000	0
Total operating expenses	3,526,000,000		3,309,000,000		10,704,000,000	9,185,000,000
Operating Income	1,491,000,000		1,740,000,000		2,456,000,000	3,649,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	53,000,000		39,000,000		139,000,000	102,000,000
Leveraged lease income (loss)	5,000,000		5,000,000		(11,000,000)	16,000,000
Interest expense, net of amounts capitalized	(202,000,000)		(218,000,000)		(628,000,000)	(649,000,000)
Other income (expense), net	(10,000,000)		(4,000,000)		(20,000,000)	(4,000,000)
Total other income and (expense)	(154,000,000)		(178,000,000)		(520,000,000)	(535,000,000)
Earnings Before Income Taxes	1,337,000,000		1,562,000,000		1,936,000,000	3,114,000,000
Income taxes	468,000,000		569,000,000		657,000,000	1,098,000,000
Consolidated Net Income	869,000,000		993,000,000		1,279,000,000	2,016,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	17,000,000		17,000,000		49,000,000	49,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	852,000,000	[1],[2]	976,000,000	[1]	1,230,000,000	1,967,000,000	[1]
Earnings per share (EPS) -
Basic EPS (in dollars per share)	$ 0.97		$ 1.11		$ 1.41	$ 2.26
Diluted EPS (in dollars per share)	$ 0.97		$ 1.11		$ 1.40	$ 2.23
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	878		876		874	872
Diluted (in shares)	881		883		879	880
Cash dividends paid per share of common stock	$ 0.5075		$ 0.4900		$ 1.5050	$ 1.4525
Alabama Power [Member]
Operating Revenues:
Retail revenues	1,438,000,000		1,476,000,000		3,800,000,000	3,822,000,000
Wholesale revenues, non-affiliates	66,000,000		79,000,000		186,000,000	210,000,000
Wholesale revenues, affiliates	47,000,000		31,000,000		163,000,000	51,000,000
Other revenues	53,000,000		51,000,000		155,000,000	147,000,000
Total operating revenues	1,604,000,000		1,637,000,000		4,304,000,000	4,230,000,000
Operating Expenses:
Fuel	467,000,000		469,000,000		1,240,000,000	1,118,000,000
Purchased power, non-affiliates	36,000,000		31,000,000		84,000,000	63,000,000
Purchased power, affiliates	30,000,000		41,000,000		102,000,000	147,000,000
Other operations and maintenance	316,000,000		307,000,000		965,000,000	944,000,000
Depreciation and amortization	170,000,000		161,000,000		487,000,000	478,000,000
Taxes other than income taxes	85,000,000		84,000,000		262,000,000	255,000,000
Total operating expenses	1,104,000,000		1,093,000,000		3,140,000,000	3,005,000,000
Operating Income	500,000,000		544,000,000		1,164,000,000	1,225,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	7,000,000		4,000,000		23,000,000	13,000,000
Interest expense, net of amounts capitalized	(65,000,000)		(71,000,000)		(196,000,000)	(217,000,000)
Other income (expense), net	0		(3,000,000)		1,000,000	(6,000,000)
Total other income and (expense)	(58,000,000)		(70,000,000)		(172,000,000)	(210,000,000)
Earnings Before Income Taxes	442,000,000		474,000,000		992,000,000	1,015,000,000
Income taxes	174,000,000		184,000,000		390,000,000	394,000,000
Consolidated Net Income	268,000,000		290,000,000		602,000,000	621,000,000
Dividends on Preferred and Preference Stock	10,000,000		10,000,000		30,000,000	30,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	258,000,000		280,000,000		572,000,000	591,000,000
Georgia Power [Member]
Operating Revenues:
Retail revenues	2,314,000,000		2,335,000,000		5,922,000,000	5,786,000,000
Wholesale revenues, non-affiliates	77,000,000		73,000,000		212,000,000	214,000,000
Wholesale revenues, affiliates	3,000,000		5,000,000		14,000,000	14,000,000
Other revenues	90,000,000		85,000,000		260,000,000	249,000,000
Total operating revenues	2,484,000,000		2,498,000,000		6,408,000,000	6,263,000,000
Operating Expenses:
Fuel	691,000,000		630,000,000		1,767,000,000	1,642,000,000
Purchased power, non-affiliates	64,000,000		79,000,000		175,000,000	266,000,000
Purchased power, affiliates	152,000,000		181,000,000		503,000,000	469,000,000
Other operations and maintenance	402,000,000		398,000,000		1,230,000,000	1,243,000,000
Depreciation and amortization	201,000,000		186,000,000		605,000,000	559,000,000
Taxes other than income taxes	102,000,000		100,000,000		292,000,000	281,000,000
Total operating expenses	1,612,000,000		1,574,000,000		4,572,000,000	4,460,000,000
Operating Income	872,000,000		924,000,000		1,836,000,000	1,803,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	11,000,000		15,000,000		24,000,000	41,000,000
Interest expense, net of amounts capitalized	(92,000,000)		(95,000,000)		(279,000,000)	(276,000,000)
Other income (expense), net	(1,000,000)		(1,000,000)		(2,000,000)	(10,000,000)
Total other income and (expense)	(82,000,000)		(81,000,000)		(257,000,000)	(245,000,000)
Earnings Before Income Taxes	790,000,000		843,000,000		1,579,000,000	1,558,000,000
Income taxes	299,000,000		314,000,000		600,000,000	558,000,000
Consolidated Net Income	491,000,000		529,000,000		979,000,000	1,000,000,000
Dividends on Preferred and Preference Stock	4,000,000		4,000,000		13,000,000	13,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	487,000,000		525,000,000		966,000,000	987,000,000
Gulf Power [Member]
Operating Revenues:
Retail revenues	335,916,000		347,435,000		901,343,000	880,833,000
Wholesale revenues, non-affiliates	29,431,000		27,462,000		82,533,000	83,309,000
Wholesale revenues, affiliates	16,701,000		30,113,000		65,206,000	95,179,000
Other revenues	17,313,000		16,809,000		47,726,000	48,951,000
Total operating revenues	399,361,000		421,819,000		1,096,808,000	1,108,272,000
Operating Expenses:
Fuel	136,216,000		160,749,000		397,409,000	423,057,000
Purchased power, non-affiliates	17,180,000		18,380,000		41,369,000	41,690,000
Purchased power, affiliates	15,829,000		10,785,000		30,075,000	18,508,000
Other operations and maintenance	76,964,000		74,781,000		232,472,000	229,790,000
Depreciation and amortization	37,345,000		36,169,000		111,479,000	104,649,000
Taxes other than income taxes	28,051,000		27,142,000		75,437,000	76,202,000
Total operating expenses	311,585,000		328,006,000		888,241,000	893,896,000
Operating Income	87,776,000		93,813,000		208,567,000	214,376,000
Other Income and (Expense):
Allowance for equity funds used during construction	1,663,000		1,015,000		4,318,000	3,988,000
Interest expense, net of amounts capitalized	(13,988,000)		(14,637,000)		(42,650,000)	(45,703,000)
Other income (expense), net	(337,000)		(557,000)		(2,704,000)	(454,000)
Total other income and (expense)	(12,662,000)		(14,179,000)		(41,036,000)	(42,169,000)
Earnings Before Income Taxes	75,114,000		79,634,000		167,531,000	172,207,000
Income taxes	28,109,000		30,329,000		62,950,000	64,172,000
Consolidated Net Income	47,005,000		49,305,000		104,581,000	108,035,000
Dividends on Preferred and Preference Stock	2,251,000		1,551,000		5,453,000	4,652,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	44,754,000		47,754,000		99,128,000	103,383,000
Mississippi Power [Member]
Operating Revenues:
Retail revenues	230,710,000		220,296,000		613,274,000	578,744,000
Wholesale revenues, non-affiliates	82,937,000		77,017,000		219,984,000	195,364,000
Wholesale revenues, affiliates	6,999,000		4,232,000		31,242,000	13,596,000
Other revenues	4,560,000		3,874,000		13,075,000	12,513,000
Total operating revenues	325,206,000		305,419,000		877,575,000	800,217,000
Operating Expenses:
Fuel	138,148,000		127,576,000		384,905,000	321,664,000
Purchased power, non-affiliates	2,077,000		1,357,000		5,222,000	4,434,000
Purchased power, affiliates	14,691,000		15,683,000		28,302,000	35,386,000
Other operations and maintenance	56,907,000		53,541,000		166,175,000	168,937,000
Depreciation and amortization	22,202,000		21,136,000		67,644,000	66,134,000
Taxes other than income taxes	21,071,000		19,975,000		60,760,000	60,312,000
Estimated loss on Kemper IGCC	150,000,000		0		1,062,000,000	0
Total operating expenses	405,096,000		239,268,000		1,775,008,000	656,867,000
Operating Income	(79,890,000)		66,151,000		(897,433,000)	143,350,000
Other Income and (Expense):
Allowance for equity funds used during construction	32,624,000		17,763,000		87,740,000	43,460,000
Interest expense, net of amounts capitalized	(8,728,000)		(9,735,000)		(29,526,000)	(30,563,000)
Other income (expense), net	(375,000)		2,584,000		(4,184,000)	2,303,000
Total other income and (expense)	23,521,000		10,612,000		54,030,000	15,200,000
Earnings Before Income Taxes	(56,369,000)		76,763,000		(843,403,000)	158,550,000
Income taxes	(32,687,000)		21,705,000		(355,156,000)	42,344,000
Consolidated Net Income	(23,682,000)		55,058,000		(488,247,000)	116,206,000
Dividends on Preferred and Preference Stock	433,000		433,000		1,299,000	1,299,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	(24,115,000)		54,625,000		(489,546,000)	114,907,000
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	265,752,000		239,916,000		705,828,000	558,338,000
Wholesale revenues, affiliates	96,795,000		112,705,000		263,624,000	330,443,000
Other revenues	2,220,000		2,350,000		5,517,000	5,676,000
Total operating revenues	364,767,000		354,971,000		974,969,000	894,457,000
Operating Expenses:
Fuel	133,464,000		126,109,000		363,466,000	306,738,000
Purchased power, non-affiliates	19,673,000		23,888,000		56,553,000	67,052,000
Purchased power, affiliates	7,011,000		2,650,000		21,158,000	7,904,000
Other operations and maintenance	41,309,000		40,357,000		154,920,000	128,951,000
Depreciation and amortization	41,094,000		37,612,000		126,152,000	103,541,000
Taxes other than income taxes	5,719,000		5,121,000		16,526,000	14,656,000
Total operating expenses	248,270,000		235,737,000		738,775,000	628,842,000
Operating Income	116,497,000		119,234,000		236,194,000	265,615,000
Other Income and (Expense):
Interest expense, net of amounts capitalized	(12,961,000)		(17,210,000)		(53,923,000)	(44,801,000)
Other income (expense), net	(791,000)		(522,000)		(2,739,000)	(686,000)
Total other income and (expense)	(13,752,000)		(17,732,000)		(56,662,000)	(45,487,000)
Earnings Before Income Taxes	102,745,000		101,502,000		179,532,000	220,128,000
Income taxes	17,592,000		33,126,000		37,265,000	75,834,000
Consolidated Net Income	$ 85,153,000		$ 68,376,000		$ 142,267,000	$ 144,294,000

[1] After dividends on preferred and preference stock of subsidiaries.

[2] Segment net income (loss) for the three months ended September 30, 2013 includes a $150 million pre-tax charge ($93 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.

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Derivatives - Contingent Features (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 20
Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	5
Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	5
Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	7
Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	3
Southern Power [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 0

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Effective Tax Rate and Unrecognized Tax Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Changes for 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	3			—			—			—			—			2
Tax positions from prior periods	(66		)	(31		)	(23		)	(5		)	(2		)	(3		)
Balance as of September 30, 2013	$	7		$	—		$	—		$	—		$	4		$	2

Impact on effective tax rate

The impact on the effective tax rate, if recognized, was as follows:

	As of September 30, 2013			As of December 31, 2012
		Southern Company
	(in millions)
Tax positions impacting the effective tax rate		$	7	$	5
Tax positions not impacting the effective tax rate		—		65
Balance of unrecognized tax benefits		$	7	$	70

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Derivatives (Policies)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Energy-Related Derivatives and Interest Rate Derivatives

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.

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.

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.

Foreign Currency Derivatives

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 September 30, 2013, the fair value of the foreign currency derivatives outstanding was immaterial.

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Effective Tax Rate and Unrecognized Tax Benefits - Changes for Unrecognized Tax Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Mar. 31, 2013	Sep. 30, 2013
Changes for Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits as of December 31, 2012	$ 70	$ 70
Tax positions from current periods		3
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(66)
Balance as of September 30, 2013		7
Alabama Power [Member]
Changes for Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits as of December 31, 2012	31	31
Tax positions from current periods		0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(31)
Balance as of September 30, 2013		0
Georgia Power [Member]
Changes for Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits as of December 31, 2012	23	23
Tax positions from current periods		0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(23)
Balance as of September 30, 2013		0
Gulf Power [Member]
Changes for Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits as of December 31, 2012	5	5
Tax positions from current periods		0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(5)
Balance as of September 30, 2013		0
Mississippi Power [Member]
Changes for Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits as of December 31, 2012	6	6
Tax positions from current periods		0
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(2)
Balance as of September 30, 2013		4
Southern Power [Member]
Changes for Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits as of December 31, 2012	3	3
Tax positions from current periods		2
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(3)
Balance as of September 30, 2013		$ 2

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Investment In Leveraged Leases (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013 MW
Leases [Abstract]
After tax charge to income	$ 16
Capacity generation facility	440
Commitment to invest capital	$ 60
Commitment term for nonrecourse debt	19 years

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Stockholders' Equity - Earnings per Share (Details) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Earnings per Share
As reported shares	878	876	874	872
Effect of options and performance share award units	3	7	5	8
Diluted shares	881	883	879	880
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	16		1

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Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	$ 11
Interest rate derivatives	7
Nuclear decommissioning trusts	1,397	[1]
Cash equivalents	465
Other	24
Fair value assets, total	1,904
Liabilities:
Energy-related derivatives	84
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Nuclear decommissioning trusts	553	[1]
Cash equivalents	465
Other	9
Fair value assets, total	1,027
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	11
Interest rate derivatives	7
Nuclear decommissioning trusts	844	[1]
Cash equivalents	0
Other	0
Fair value assets, total	862
Liabilities:
Energy-related derivatives	84
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Nuclear decommissioning trusts	0	[1]
Cash equivalents	0
Other	15
Fair value assets, total	15
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	3
Fair value assets, total	1,026
Liabilities:
Energy-related derivatives	15
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	417	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	94	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	27	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	101	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	23	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	10	[2]
Cash equivalents	351
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Fair value assets, total	726
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	343	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	32	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	3
Fair value assets, total	300
Liabilities:
Energy-related derivatives	15
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	74	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	62	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	27	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	101	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	23	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	10	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Cash equivalents	0
Georgia Power [Member]
Assets:
Nuclear decommissioning trusts	14
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	2
Fair value assets, total	726
Liabilities:
Energy-related derivatives	29
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	179	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	125	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	88	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	64	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	133	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	116	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	19	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Fair value assets, total	178
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	178	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	2
Fair value assets, total	548
Liabilities:
Energy-related derivatives	29
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	1	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	125	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	88	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	64	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	133	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	116	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	19	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	3
Cash equivalents	16
Fair value assets, total	19
Liabilities:
Energy-related derivatives	25
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	16
Fair value assets, total	16
Liabilities:
Energy-related derivatives	0
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	3
Cash equivalents	0
Fair value assets, total	3
Liabilities:
Energy-related derivatives	25
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	1
Liabilities:
Energy-related derivatives	14
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	1
Liabilities:
Energy-related derivatives	14
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Liabilities:
Energy-related derivatives	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	2
Cash equivalents	60
Fair value assets, total	62
Liabilities:
Energy-related derivatives	1
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	60
Fair value assets, total	60
Liabilities:
Energy-related derivatives	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	2
Cash equivalents	0
Fair value assets, total	2
Liabilities:
Energy-related derivatives	1
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	$ 0

[1] For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

[2] Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.

[3] Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of September 30, 2013, approximately $14 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.

XML

Fair Value Measurements - Fair Value Measurements Calculated at Net Asset Value Per Share (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Foreign Equity [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	$ 125,000,000
Unfunded Commitments	0
Redemption Frequency	Monthly
Redemption Notice Period, Description	5 days
Foreign Equity [Member] | Georgia Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	125,000,000
Unfunded Commitments	0
Redemption Frequency	Monthly
Redemption Notice Period, Description	5 days
Corporate bonds - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	4,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	1 to 3 days
Corporate bonds - commingled funds [Member] | Georgia Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	4,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Equity - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	62,000,000
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period, Description	Daily/7 days
Equity - commingled funds [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	62,000,000
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period, Description	Daily/7 days
Other - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	19,000,000
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period, Description	Daily/7 days
Other - commingled funds [Member] | Georgia Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	19,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Trust owned life insurance [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	104,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	15 days
Trust owned life insurance [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	104,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	15 days
Money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	465,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Money market funds [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	351,000,000
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Money market funds [Member] | Gulf Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	16,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Money market funds [Member] | Mississippi Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Unfunded Commitments	0
Money market funds [Member] | Southern Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	60,000,000
Unfunded Commitments	$ 0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Minimum [Member] | Corporate bonds - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	1 day
Maximum [Member] | Foreign Equity [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	5 days
Maximum [Member] | Foreign Equity [Member] | Georgia Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	5 days
Maximum [Member] | Corporate bonds - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	3 days
Maximum [Member] | Equity - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	7 days
Maximum [Member] | Equity - commingled funds [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	7 days
Maximum [Member] | Other - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	7 days
Maximum [Member] | Trust owned life insurance [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	15 days
Maximum [Member] | Trust owned life insurance [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	15 days

XML

Financing

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

FINANCING

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 September 30, 2013:

	Expires(a)														Executable Term Loans				Due Within One Year
Company	2013		2014		2015		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	1		268		35		—		1,000		1,304		1,304		53		—		53		146
Georgia Power	—		—		—		150		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		90		—		165		—		275		275		45		—		45		65
Mississippi Power	15		120		—		165		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		486		—		—		—		—
Other	—		75		25		—		—		100		100		25		—		25		50
Total	$	36	$	553	$	60	$	480	$	4,100	$	5,229	$	5,201	$	148	$	40	$	188	$	331

(a) No credit arrangements expire in 2017.

As reflected in the table above, during the first nine 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 to capitalization 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.

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.

Financing Activities

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

Company(a)	Senior  Note Issuances		Senior  Note Redemptions and  Maturities		Revenue Bond Issuances		Revenue Bond Redemptions and Maturities		Other Long-Term Debt Issuances		Other  Long-Term Debt Redemptions
					(in millions)
Southern Company	$	500	$	—	$	—	$	—	$	—	$	—
Georgia Power	850		1,250		89		89		—		—
Gulf Power	90		90		—		—		—		—
Mississippi Power	—		—		31		83		475		125
Southern Power	300		—		—		—		23		—
Other	—		50		—		—		—		—
Total	$	1,740	$	1,390	$	120	$	172	$	498	$	125

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

Southern Company

In August 2013, Southern Company issued $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes due September 1, 2018. The proceeds were used to pay a portion of Southern Company’s outstanding short-term indebtedness and for other general corporate purposes.

Georgia Power

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 these sales 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 (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 1997.

In August 2013, Georgia Power issued $200 million aggregate principal amount of Series 2013C Floating Rate Senior Notes due August 15, 2016. The proceeds were used to repay at maturity a portion of $100 million aggregate principal amount outstanding of Georgia Power's Series Q 4.90% Senior Notes due September 15, 2013 and a portion of $500 million aggregate principal amount outstanding of Georgia Power's Series 2010D 1.30% Senior Notes due September 15, 2013.

In August 2013, the Development Authority of Bartow County issued $71.7 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013 due August 1, 2043 for the benefit of Georgia Power. The proceeds were used to redeem, in September 2013, $24.9 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1996 and $46.8 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1998.

Gulf Power

In June 2013, Gulf Power issued 500,000 shares of Series 2013A 5.60% Preference Stock and realized proceeds of $50 million. Gulf Power also 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 90-day 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.

Mississippi Power

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. In September 2013, Mississippi Power amended the bank loan, which extended the maturity date to 2015. 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 fourtwo-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 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.

In July 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 September 2013, Mississippi Power entered into a two-year floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $125 million aggregate principal amount and proceeds were used to repay at maturity a two-year floating rate bank loan in the aggregate principal amount of $125 million.

Southern Power

In March and September 2013, Southern Power issued an additional $1.7 million and $2.2 million, respectively, under a promissory note, due September 30, 2032, to Turner Renewable Energy, LLC (TRE) related to the financing of Spectrum.

In the second and third quarters of 2013, Southern Power issued an aggregate $8.7 million and $10.2 million, respectively, under a promissory note, due April 30, 2033, to TRE related to the financing of Campo Verde.

In July 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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Derivatives (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivatives

At September 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	267	2018	2017
Alabama Power	68	2017	—
Georgia Power	67	2017	—
Gulf Power	85	2018	—
Mississippi Power	46	2017	—
Southern Power	1	—	2017

Notional amount of interest rate derivatives

At September 30, 2013, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Interest Rate Paid		Hedge Maturity Date	Fair Value Gain (Loss) September 30, 2013
	(in millions)						(in millions)
Fair value hedges of existing debt
Southern Company	$	350	4.15%	3-month LIBOR  + 1.96%	(a)	May 2014	$	7

(a) Weighted average

Fair value of energy-related derivatives and interest rate derivatives

At September 30, 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at September 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	$	6	$	2	$	1	$	2	$	1
Other deferred charges and assets	3		1		1		1		—
Total derivatives designated as hedging instruments for regulatory purposes	$	9	$	3	$	2	$	3	$	1	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	2		—		—		—		—		2
Total asset derivatives	$	18	$	3	$	2	$	3	$	1	$	2

Liability Derivatives at September 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	$	48	$	9	$	19	$	13	$	7
Other deferred credits and liabilities	35		6		10		12		7
Total derivatives designated as hedging instruments for regulatory purposes	$	83	$	15	$	29	$	25	$	14	N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	84	$	15	$	29	$	25	$	14	$	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

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

Offsetting Assets And Liabilities [Table Text Block]

Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.

Derivative Contracts at September 30, 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)	$	11		$	3		$	2		$	3		$	1		$	2
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(2		)	(3		)	(1		)	(1		)
Net energy-related derivative assets	$	1		$	—		$	—		$	—		$	—		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	84		$	15		$	29		$	25		$	14		$	1
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(2		)	(3		)	(1		)	(1		)
Net energy-related derivative liabilities	$	74		$	12		$	27		$	22		$	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

(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.

Pre-tax effect of unrealized derivative gains (losses)

At September 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 September 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	$	(48	)	$	(9	)	$	(19	)	$	(13	)	$	(7	)
Other regulatory assets, deferred	(35		)	(6		)	(10		)	(12		)	(7		)
Other regulatory liabilities, current	6			2			1			2			1
Other regulatory liabilities, deferred (a)	3			1			1			1			—
Total energy-related derivative gains (losses)	$	(74	)	$	(12	)	$	(27	)	$	(22	)	$	(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.

Pre-tax effect of derivatives designated as cash flow hedging instruments

For the three months ended September 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 all registrants.

For the nine months ended September 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)
						Statements of Income Location	Amount
	2013		2012				2013			2012
	(in millions)						(in millions)
Southern Company
Interest rate derivatives	$	—	$	(16	)	Interest expense, net of amounts capitalized	$	(12	)	$	(12	)
Alabama Power
Interest rate derivatives	$	—	$	(15	)	Interest expense, net of amounts capitalized	$	(2	)	$	—
Southern Power
Interest rate derivatives	$	—	$	—		Interest expense, net of amounts capitalized	$	(6	)	$	(8	)

Fair value of derivative liabilities with contingent features

At September 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	$	5	$	5	$	7	$	3	$	—

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Financing Debt Instruments (Details) (USD $)	9 Months Ended							1 Months Ended	9 Months Ended						1 Months Ended	9 Months Ended					1 Months Ended			3 Months Ended	9 Months Ended				1 Months Ended		3 Months Ended						1 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Aug. 31, 2013 Senior Notes [Member]	Sep. 30, 2013 Debt Redemptions [Member]	Sep. 30, 2013 Debt Issuances [Member]	Sep. 30, 2013 Parent Company [Member] Debt Redemptions [Member]	Sep. 30, 2013 Parent Company [Member] Debt Issuances [Member]	Mar. 31, 2013 Georgia Power [Member]	Sep. 30, 2013 Georgia Power [Member]	Sep. 30, 2012 Georgia Power [Member]	Aug. 31, 2013 Georgia Power [Member]	Aug. 31, 2013 Georgia Power [Member] Senior Notes [Member]	Sep. 30, 2013 Georgia Power [Member] Debt Redemptions [Member]	Sep. 30, 2013 Georgia Power [Member] Debt Issuances [Member]	Jun. 30, 2013 Gulf Power [Member]	Sep. 30, 2013 Gulf Power [Member]	Sep. 30, 2012 Gulf Power [Member]	Jun. 30, 2013 Gulf Power [Member] Senior Notes [Member]	Sep. 30, 2013 Gulf Power [Member] Debt Redemptions [Member]	Sep. 30, 2013 Gulf Power [Member] Debt Issuances [Member]	Sep. 30, 2013 Mississippi Power [Member]	Mar. 31, 2013 Mississippi Power [Member] loan	Nov. 30, 2012 Mississippi Power [Member]	Dec. 31, 2012 Mississippi Power [Member]	Sep. 30, 2013 Mississippi Power [Member]	Jul. 31, 2013 Mississippi Power [Member]	Sep. 30, 2013 Mississippi Power [Member] Debt Redemptions [Member]	Sep. 30, 2013 Mississippi Power [Member] Debt Issuances [Member]	Sep. 30, 2013 Southern Power [Member]	Mar. 31, 2013 Southern Power [Member]	Sep. 30, 2013 Southern Power [Member]	Jun. 30, 2013 Southern Power [Member]	Sep. 30, 2013 Southern Power [Member] Debt Redemptions [Member]	Sep. 30, 2013 Southern Power [Member] Debt Issuances [Member]	Sep. 30, 2013 Other Subsidiaries [Member] Debt Redemptions [Member]	Sep. 30, 2013 Other Subsidiaries [Member] Debt Issuances [Member]	Sep. 30, 2013 First Series Nineteen Ninety Six [Member] Georgia Power [Member]	Sep. 30, 2013 First Series Nineteen Ninety Eight [Member] Georgia Power [Member]	Aug. 31, 2013 SeriesTwoThousandThirteenA [Member] Senior Notes [Member]	Mar. 31, 2013 SeriesTwoThousandThirteenA [Member] Georgia Power [Member] Senior Notes [Member]	Jun. 30, 2013 SeriesTwoThousandThirteenA [Member] Gulf Power [Member] Senior Notes [Member]	Jul. 31, 2013 SeriesTwoThousandThirteenA [Member] Southern Power [Member] Senior Notes [Member]	Mar. 31, 2013 SeriesTwoThousandThirteenB [Member] Georgia Power [Member] Senior Notes [Member]	Mar. 31, 2013 SeriesTwoThousandTenA [Member] Georgia Power [Member] Senior Notes [Member]	Aug. 31, 2013 SeriesTwoThousandThirteenC [Member] Georgia Power [Member]	Aug. 31, 2013 Series Two Thousand Ten D [Member] Georgia Power [Member] Senior Notes [Member]	Jun. 30, 2013 Series G [Member] Gulf Power [Member] Senior Notes [Member]	Jun. 30, 2013 Series H [Member] Gulf Power [Member] Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 500,000,000																																					$ 400,000,000	$ 90,000,000	$ 300,000,000	$ 250,000,000		$ 200,000,000
Senior Notes				1,390,000,000	1,740,000,000	0	500,000,000						1,250,000,000	850,000,000					90,000,000	90,000,000							0	0					0	300,000,000	50,000,000	0
Revenue Bond				172,000,000	120,000,000	0	0						89,000,000	89,000,000					0	0							83,000,000	31,000,000							0	0
Other Long-term Debt				125,000,000	498,000,000	0	0						0	0					0	0							125,000,000	475,000,000					0	23,000,000	0	0
Debt Instrument, Interest Rate, Stated Percentage												4.90%																											2.45%	4.30%	5.00%	5.25%				1.30%	4.35%	5.25%
Redemption Amount Of Principal Notes												100,000,000						125,000,000																										350,000,000		500,000,000	60,000,000	30,000,000
Long-term Pollution Control Bond								17,500,000			71,700,000
Repayments of Pollution Control Bond								17,500,000	89,000,000	234,000,000						63,000,000	0																				24,900,000	46,800,000
Preferred Stock, Shares Issued															500,000
Preferred Stock, Dividend Rate, Percentage															5.60%
Preference stock	50,000,000	0														50,000,000	0
Bank Loans Period Of Extension																90 days					2 years	2 years		366 days
Aggregate Principal Amount Of Floating Rate Bank Loan																					125,000,000		100,000,000		125,000,000
Debt Instrument, Description of Variable Rate Basis																									P1M
First Term Loan																						50,000,000
Second Term Loan																						75,000,000
Third Term Loan																						75,000,000
Forth Term Loan																						100,000,000
Taxable Revenue Bonds																						15,800,000				15,300,000
First Advance On Bank Loan																							50,000,000
Second Advance On Bank Loan																							50,000,000
Number Of Bank Loans																						4
Repayment Aggregate Principal Amount Of Floating Rate Bank Loan																					125,000,000				125,000,000
Promissory Note																													$ 2,200,000	$ 1,700,000	$ 10,200,000	$ 8,700,000

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Derivatives

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

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.

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 September 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	267	2018	2017
Alabama Power	68	2017	—
Georgia Power	67	2017	—
Gulf Power	85	2018	—
Mississippi Power	46	2017	—
Southern Power	1	—	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 8 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 1 million mmBtu for Gulf 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 September 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 September 30, 2013, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Interest Rate Paid		Hedge Maturity Date	Fair Value Gain (Loss) September 30, 2013
	(in millions)						(in millions)
Fair value hedges of existing debt
Southern Company	$	350	4.15%	3-month LIBOR  + 1.96%	(a)	May 2014	$	7

(a) Weighted average

The estimated pre-tax gains (losses) that will be reclassified from AOCI to interest expense for the next 12-month period ending September 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 September 30, 2013, the fair value of the foreign currency derivatives outstanding was immaterial.

Derivative Financial Statement Presentation and Amounts

At September 30, 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at September 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	$	6	$	2	$	1	$	2	$	1
Other deferred charges and assets	3		1		1		1		—
Total derivatives designated as hedging instruments for regulatory purposes	$	9	$	3	$	2	$	3	$	1	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	2		—		—		—		—		2
Total asset derivatives	$	18	$	3	$	2	$	3	$	1	$	2

Liability Derivatives at September 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	$	48	$	9	$	19	$	13	$	7
Other deferred credits and liabilities	35		6		10		12		7
Total derivatives designated as hedging instruments for regulatory purposes	$	83	$	15	$	29	$	25	$	14	N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	84	$	15	$	29	$	25	$	14	$	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

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.

Derivative Contracts at September 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)	$	11		$	3		$	2		$	3		$	1		$	2
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(2		)	(3		)	(1		)	(1		)
Net energy-related derivative assets	$	1		$	—		$	—		$	—		$	—		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	84		$	15		$	29		$	25		$	14		$	1
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(2		)	(3		)	(1		)	(1		)
Net energy-related derivative liabilities	$	74		$	12		$	27		$	22		$	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

(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.

At September 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 September 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	$	(48	)	$	(9	)	$	(19	)	$	(13	)	$	(7	)
Other regulatory assets, deferred	(35		)	(6		)	(10		)	(12		)	(7		)
Other regulatory liabilities, current	6			2			1			2			1
Other regulatory liabilities, deferred (a)	3			1			1			1			—
Total energy-related derivative gains (losses)	$	(74	)	$	(12	)	$	(27	)	$	(22	)	$	(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 nine months ended September 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 nine months ended September 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 September 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 all registrants.

For the nine months ended September 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)
						Statements of Income Location	Amount
	2013		2012				2013			2012
	(in millions)						(in millions)
Southern Company
Interest rate derivatives	$	—	$	(16	)	Interest expense, net of amounts capitalized	$	(12	)	$	(12	)
Alabama Power
Interest rate derivatives	$	—	$	(15	)	Interest expense, net of amounts capitalized	$	(2	)	$	—
Southern Power
Interest rate derivatives	$	—	$	—		Interest expense, net of amounts capitalized	$	(6	)	$	(8	)

For the nine months ended September 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 nine months ended September 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 nine months ended September 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. This third party hedging activity has been discontinued.

For the three and nine months ended September 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 September 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	$	5	$	5	$	7	$	3	$	—

At September 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 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.

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Stockholders' Equity

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

STOCKHOLDERS' EQUITY

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 September 30, 2013	Three Months Ended September 30, 2012	Nine Months Ended September 30, 2013	Nine Months Ended September 30, 2012
	(in millions)
As reported shares	878	876	874	872
Effect of options and performance share award units	3	7	5	8
Diluted shares	881	883	879	880

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 16 million and 1 million for the three and nine months ended September 30, 2013, respectively, and were immaterial for the three and nine months ended September 30, 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
	(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	—	—		1,230			—		1,230
Other comprehensive income (loss)	—	—		11			—		11
Treasury stock re-issued	—	1,956		89			—		89
Stock issued	12,046	—		484			49		533
Stock repurchased, at cost	—	—		(19		)	—		(19		)
Cash dividends on common stock	—	—		(1,314		)	—		(1,314		)
Other	—	(30	)	—			—		—
Balance at September 30, 2013	889,849	(8,109	)	$	18,778		$	756	$	19,534
Balance at December 31, 2011	865,664	(539	)	$	17,578		$	707	$	18,285
Net income after dividends on preferred and preference stock	—	—		1,967			—		1,967
Other comprehensive income (loss)	—	—		(1		)	—		(1		)
Stock issued	11,586	—		479			—		479
Stock repurchased, at cost	—	(2,567	)	(117		)	—		(117		)
Cash dividends on common stock	—	—		(1,267		)	—		(1,267		)
Other	—	(38	)	—			—		—
Balance at September 30, 2012	877,250	(3,144	)	$	18,639		$	707	$	19,346

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. There were no repurchases under this program in the first nine months of 2013 and no further repurchases under the program are anticipated.

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Current Assets:
Cash and cash equivalents	$ 682,000,000	$ 628,000,000
Restricted cash and cash equivalents	0	7,000,000
Receivables --
Customer accounts receivable	1,292,000,000	961,000,000
Unbilled revenues	473,000,000	441,000,000
Under recovered regulatory clause revenues	45,000,000	29,000,000
Other accounts and notes receivable	269,000,000	235,000,000
Accumulated provision for uncollectible accounts	(19,000,000)	(17,000,000)
Fossil fuel stock, at average cost	1,349,000,000	1,819,000,000
Materials and supplies, at average cost	959,000,000	1,000,000,000
Vacation pay	164,000,000	165,000,000
Prepaid expenses	418,000,000	657,000,000
Other regulatory assets, current	120,000,000	163,000,000
Other current assets	33,000,000	74,000,000
Total current assets	5,785,000,000	6,162,000,000
Property, Plant, and Equipment:
In service	64,793,000,000	63,251,000,000
Less accumulated provision for depreciation	22,821,000,000	21,964,000,000
Plant in service, net of depreciation	41,972,000,000	41,287,000,000
Other utility plant, net	252,000,000	263,000,000
Nuclear fuel, at amortized cost	832,000,000	851,000,000
Construction work in progress	7,144,000,000	5,989,000,000
Total property, plant, and equipment	50,200,000,000	48,390,000,000
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,397,000,000	1,303,000,000
Leveraged leases	658,000,000	670,000,000
Miscellaneous property and investments	220,000,000	216,000,000
Total other property and investments	2,275,000,000	2,189,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,402,000,000	1,385,000,000
Unamortized debt issuance expense	146,000,000	133,000,000
Unamortized loss on reacquired debt	291,000,000	309,000,000
Other regulatory assets, deferred	4,012,000,000	4,032,000,000
Other deferred charges and assets	586,000,000	549,000,000
Total deferred charges and other assets	6,437,000,000	6,408,000,000
Total Assets	64,697,000,000	63,149,000,000
Current Liabilities:
Securities due within one year	1,307,000,000	2,335,000,000
Interest-bearing refundable deposit related to asset sale	150,000,000	150,000,000
Notes payable	750,000,000	825,000,000
Other accounts payable	1,281,000,000	1,387,000,000
Customer deposits	377,000,000	370,000,000
Accrued taxes --
Accrued income taxes	87,000,000	10,000,000
Other accrued taxes	512,000,000	391,000,000
Accrued interest	262,000,000	237,000,000
Accrued vacation pay	210,000,000	212,000,000
Accrued compensation	250,000,000	433,000,000
Other regulatory liabilities, current	89,000,000	107,000,000
Other current liabilities	429,000,000	557,000,000
Total current liabilities	5,704,000,000	7,014,000,000
Long-term Debt	21,053,000,000	19,274,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,291,000,000	9,938,000,000
Deferred credits related to income taxes	203,000,000	211,000,000
Accumulated deferred investment tax credits	819,000,000	894,000,000
Employee benefit obligations	2,548,000,000	2,540,000,000
Asset retirement obligations	1,967,000,000	1,748,000,000
Other cost of removal obligations	1,278,000,000	1,194,000,000
Other regulatory liabilities, deferred	375,000,000	289,000,000
Other deferred credits and liabilities	550,000,000	668,000,000
Total deferred credits and other liabilities	18,031,000,000	17,482,000,000
Total Liabilities	44,788,000,000	43,770,000,000
Redeemable Preferred Stock of Subsidiaries	375,000,000	375,000,000
Common Stockholders' Equity:
Common stock	4,447,000,000	4,389,000,000
Paid-in capital	5,262,000,000	4,855,000,000
Treasury, at cost	(363,000,000)	(450,000,000)
Retained earnings	9,543,000,000	9,626,000,000
Accumulated other comprehensive loss	(111,000,000)	(123,000,000)
Total common stockholders' equity	18,778,000,000	18,297,000,000
Preferred and Preference Stock of Subsidiaries	756,000,000	707,000,000
Total Stockholders' Equity	19,534,000,000	19,004,000,000
Total Liabilities and Stockholders' Equity	64,697,000,000	63,149,000,000
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	436,000,000	137,000,000
Receivables --
Customer accounts receivable	417,000,000	321,000,000
Unbilled revenues	133,000,000	138,000,000
Under recovered regulatory clause revenues	4,000,000	23,000,000
Other accounts and notes receivable	62,000,000	42,000,000
Affiliated companies	45,000,000	55,000,000
Accumulated provision for uncollectible accounts	(9,000,000)	(8,000,000)
Fossil fuel stock, at average cost	302,000,000	475,000,000
Materials and supplies, at average cost	370,000,000	395,000,000
Vacation pay	60,000,000	61,000,000
Prepaid expenses	74,000,000	81,000,000
Other regulatory assets, current	14,000,000	24,000,000
Other current assets	3,000,000	13,000,000
Total current assets	1,911,000,000	1,757,000,000
Property, Plant, and Equipment:
In service	21,916,000,000	21,407,000,000
Less accumulated provision for depreciation	8,016,000,000	7,761,000,000
Plant in service, net of depreciation	13,900,000,000	13,646,000,000
Nuclear fuel, at amortized cost	357,000,000	354,000,000
Construction work in progress	638,000,000	438,000,000
Total property, plant, and equipment	14,895,000,000	14,438,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	54,000,000	53,000,000
Nuclear decommissioning trusts, at fair value	673,000,000	605,000,000
Miscellaneous property and investments	78,000,000	78,000,000
Total other property and investments	805,000,000	736,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	521,000,000	525,000,000
Deferred under recovered regulatory clause revenues	30,000,000	11,000,000
Other regulatory assets, deferred	1,056,000,000	1,083,000,000
Other deferred charges and assets	134,000,000	162,000,000
Total deferred charges and other assets	1,741,000,000	1,781,000,000
Total Assets	19,352,000,000	18,712,000,000
Current Liabilities:
Securities due within one year	250,000,000	250,000,000
Affiliated accounts payable	192,000,000	191,000,000
Other accounts payable	225,000,000	318,000,000
Customer deposits	85,000,000	85,000,000
Accrued taxes --
Accrued income taxes	68,000,000	5,000,000
Other accrued taxes	108,000,000	33,000,000
Accrued interest	63,000,000	62,000,000
Accrued vacation pay	50,000,000	50,000,000
Accrued compensation	61,000,000	94,000,000
Other regulatory liabilities, current	45,000,000	3,000,000
Other current liabilities	42,000,000	52,000,000
Total current liabilities	1,189,000,000	1,143,000,000
Long-term Debt	5,934,000,000	5,929,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,596,000,000	3,404,000,000
Deferred credits related to income taxes	76,000,000	79,000,000
Accumulated deferred investment tax credits	135,000,000	141,000,000
Employee benefit obligations	323,000,000	321,000,000
Asset retirement obligations	720,000,000	589,000,000
Other cost of removal obligations	822,000,000	759,000,000
Other regulatory liabilities, deferred	211,000,000	183,000,000
Other deferred credits and liabilities	59,000,000	81,000,000
Total deferred credits and other liabilities	5,942,000,000	5,557,000,000
Total Liabilities	13,065,000,000	12,629,000,000
Redeemable Preferred Stock	342,000,000	342,000,000
Preference Stock	343,000,000	343,000,000
Common Stockholders' Equity:
Common stock	1,222,000,000	1,222,000,000
Paid-in capital	2,255,000,000	2,227,000,000
Retained earnings	2,151,000,000	1,976,000,000
Accumulated other comprehensive loss	(26,000,000)	(27,000,000)
Total common stockholders' equity	5,602,000,000	5,398,000,000
Total Liabilities and Stockholders' Equity	19,352,000,000	18,712,000,000
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	53,000,000	45,000,000
Receivables --
Customer accounts receivable	657,000,000	484,000,000
Unbilled revenues	239,000,000	217,000,000
Joint owner accounts receivable	54,000,000	51,000,000
Other accounts and notes receivable	81,000,000	68,000,000
Affiliated companies	23,000,000	23,000,000
Accumulated provision for uncollectible accounts	(8,000,000)	(6,000,000)
Fossil fuel stock, at average cost	779,000,000	992,000,000
Materials and supplies, at average cost	422,000,000	452,000,000
Vacation pay	86,000,000	85,000,000
Prepaid income taxes	114,000,000	164,000,000
Other regulatory assets, current	43,000,000	72,000,000
Other current assets	75,000,000	104,000,000
Total current assets	2,618,000,000	2,751,000,000
Property, Plant, and Equipment:
In service	29,762,000,000	29,244,000,000
Less accumulated provision for depreciation	10,842,000,000	10,431,000,000
Plant in service, net of depreciation	18,920,000,000	18,813,000,000
Other utility plant, net	252,000,000	263,000,000
Nuclear fuel, at amortized cost	475,000,000	497,000,000
Construction work in progress	3,399,000,000	2,893,000,000
Total property, plant, and equipment	23,046,000,000	22,466,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	46,000,000	45,000,000
Nuclear decommissioning trusts, at fair value	724,000,000	698,000,000
Miscellaneous property and investments	43,000,000	44,000,000
Total other property and investments	813,000,000	787,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	713,000,000	733,000,000
Other regulatory assets, deferred	1,773,000,000	1,798,000,000
Other deferred charges and assets	244,000,000	268,000,000
Total deferred charges and other assets	2,730,000,000	2,799,000,000
Total Assets	29,207,000,000	28,803,000,000
Current Liabilities:
Securities due within one year	530,000,000	1,680,000,000
Notes payable	211,000,000	2,000,000
Affiliated accounts payable	428,000,000	417,000,000
Other accounts payable	428,000,000	436,000,000
Customer deposits	243,000,000	237,000,000
Accrued taxes --
Accrued income taxes	161,000,000	6,000,000
Other accrued taxes	283,000,000	260,000,000
Accrued interest	113,000,000	100,000,000
Accrued vacation pay	60,000,000	61,000,000
Accrued compensation	64,000,000	113,000,000
Liabilities from risk management activities	19,000,000	30,000,000
Other regulatory liabilities, current	18,000,000	73,000,000
Over recovered regulatory clause liabilities	81,000,000	107,000,000
Other current liabilities	109,000,000	146,000,000
Total current liabilities	2,748,000,000	3,668,000,000
Long-term Debt	8,739,000,000	7,994,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,139,000,000	4,861,000,000
Deferred credits related to income taxes	112,000,000	115,000,000
Accumulated deferred investment tax credits	205,000,000	208,000,000
Employee benefit obligations	976,000,000	950,000,000
Asset retirement obligations	1,182,000,000	1,097,000,000
Other cost of removal obligations	64,000,000	63,000,000
Other deferred credits and liabilities	177,000,000	308,000,000
Total deferred credits and other liabilities	7,855,000,000	7,602,000,000
Total Liabilities	19,342,000,000	19,264,000,000
Redeemable Preferred Stock	45,000,000	45,000,000
Preference Stock	221,000,000	221,000,000
Common Stockholders' Equity:
Common stock	398,000,000	398,000,000
Paid-in capital	5,625,000,000	5,585,000,000
Retained earnings	3,581,000,000	3,297,000,000
Accumulated other comprehensive loss	(5,000,000)	(7,000,000)
Total common stockholders' equity	9,599,000,000	9,273,000,000
Total Liabilities and Stockholders' Equity	29,207,000,000	28,803,000,000
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	27,875,000	32,167,000
Receivables --
Customer accounts receivable	83,132,000	58,449,000
Unbilled revenues	61,322,000	53,363,000
Under recovered regulatory clause revenues	33,759,000	6,138,000
Other accounts and notes receivable	9,613,000	11,859,000
Affiliated companies	783,000	13,624,000
Accumulated provision for uncollectible accounts	(1,172,000)	(1,490,000)
Fossil fuel stock, at average cost	130,044,000	153,710,000
Materials and supplies, at average cost	56,048,000	53,365,000
Prepaid expenses	18,881,000	62,877,000
Other regulatory assets, current	26,465,000	30,576,000
Other current assets	2,271,000	2,690,000
Total current assets	449,021,000	477,328,000
Property, Plant, and Equipment:
In service	4,323,305,000	4,260,844,000
Less accumulated provision for depreciation	1,196,883,000	1,168,055,000
Plant in service, net of depreciation	3,126,422,000	3,092,789,000
Construction work in progress	247,290,000	136,062,000
Total property, plant, and equipment	3,373,712,000	3,228,851,000
Other Property and Investments:
Total other property and investments	15,442,000	15,737,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	51,715,000	50,139,000
Other regulatory assets, deferred	386,960,000	372,294,000
Other deferred charges and assets	36,563,000	33,053,000
Total deferred charges and other assets	475,238,000	455,486,000
Total Assets	4,313,413,000	4,177,402,000
Current Liabilities:
Securities due within one year	0	60,000,000
Notes payable	58,693,000	127,002,000
Affiliated accounts payable	81,588,000	66,161,000
Other accounts payable	40,711,000	54,551,000
Customer deposits	34,783,000	34,749,000
Accrued taxes --
Accrued income taxes	21,136,000	45,000
Other accrued taxes	27,705,000	7,036,000
Accrued interest	17,742,000	12,364,000
Accrued compensation	8,991,000	14,966,000
Liabilities from risk management activities	13,130,000	16,529,000
Other regulatory liabilities, current	14,316,000	25,887,000
Other current liabilities	21,888,000	19,930,000
Total current liabilities	340,683,000	439,220,000
Long-term Debt	1,246,022,000	1,185,870,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	689,840,000	648,952,000
Accumulated deferred investment tax credits	4,393,000	5,408,000
Employee benefit obligations	128,631,000	126,871,000
Other cost of removal obligations	224,977,000	213,413,000
Other regulatory liabilities, deferred	47,090,000	47,863,000
Deferred capacity expense	169,504,000	137,568,000
Other deferred credits and liabilities	78,705,000	93,497,000
Total deferred credits and other liabilities	1,343,140,000	1,273,572,000
Total Liabilities	2,929,845,000	2,898,662,000
Preference Stock	146,535,000	97,998,000
Common Stockholders' Equity:
Common stock	433,060,000	393,060,000
Paid-in capital	551,232,000	547,798,000
Retained earnings	253,943,000	241,465,000
Accumulated other comprehensive loss	(1,202,000)	(1,581,000)
Total common stockholders' equity	1,237,033,000	1,180,742,000
Total Liabilities and Stockholders' Equity	4,313,413,000	4,177,402,000
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	42,079,000	145,008,000
Receivables --
Customer accounts receivable	50,679,000	29,561,000
Unbilled revenues	38,802,000	32,688,000
Other accounts and notes receivable	5,580,000	7,517,000
Affiliated companies	39,334,000	27,160,000
Accumulated provision for uncollectible accounts	(636,000)	(373,000)
Fossil fuel stock, at average cost	116,955,000	176,378,000
Materials and supplies, at average cost	42,289,000	34,260,000
Prepaid income taxes	96,914,000	129,835,000
Other regulatory assets, current	55,375,000	55,302,000
Other current assets	5,270,000	17,170,000
Total current assets	492,641,000	654,506,000
Property, Plant, and Equipment:
In service	3,313,524,000	3,036,159,000
Less accumulated provision for depreciation	1,101,682,000	1,065,474,000
Plant in service, net of depreciation	2,211,842,000	1,970,685,000
Construction work in progress	2,339,396,000	2,393,145,000
Total property, plant, and equipment	4,551,238,000	4,363,830,000
Other Property and Investments:
Total other property and investments	4,912,000	4,887,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	110,978,000	71,869,000
Other regulatory assets, deferred	259,906,000	236,225,000
Other deferred charges and assets	52,618,000	42,304,000
Total deferred charges and other assets	423,502,000	350,398,000
Total Assets	5,472,293,000	5,373,621,000
Current Liabilities:
Securities due within one year	152,509,000	276,471,000
Interest-bearing refundable deposit related to asset sale	150,000,000	150,000,000
Affiliated accounts payable	65,065,000	54,769,000
Other accounts payable	263,913,000	262,992,000
Customer deposits	14,394,000	14,202,000
Accrued taxes --
Accrued income taxes	8,903,000	2,339,000
Other accrued taxes	61,117,000	69,376,000
Accrued interest	45,529,000	30,376,000
Accrued compensation	7,163,000	15,706,000
Other regulatory liabilities, current	11,846,000	5,376,000
Over recovered regulatory clause liabilities	28,091,000	77,338,000
Other current liabilities	24,825,000	31,882,000
Total current liabilities	833,355,000	990,827,000
Long-term Debt	2,069,938,000	1,564,462,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	29,086,000	244,958,000
Deferred credits related to income taxes	8,818,000	10,106,000
Accumulated deferred investment tax credits	284,496,000	370,554,000
Employee benefit obligations	161,938,000	157,421,000
Other cost of removal obligations	150,028,000	143,461,000
Other regulatory liabilities, deferred	117,804,000	56,984,000
Other deferred credits and liabilities	52,891,000	52,860,000
Total deferred credits and other liabilities	805,061,000	1,036,344,000
Total Liabilities	3,708,354,000	3,591,633,000
Redeemable Preferred Stock	32,780,000	32,780,000
Common Stockholders' Equity:
Common stock	37,691,000	37,691,000
Paid-in capital	1,944,336,000	1,401,520,000
Retained earnings	(242,792,000)	318,710,000
Accumulated other comprehensive loss	(8,076,000)	(8,713,000)
Total common stockholders' equity	1,731,159,000	1,749,208,000
Total Liabilities and Stockholders' Equity	5,472,293,000	5,373,621,000
Southern Power [Member]
Current Assets:
Cash and cash equivalents	42,137,000	28,592,000
Receivables --
Customer accounts receivable	86,717,000	62,857,000
Other accounts and notes receivable	1,754,000	3,135,000
Affiliated companies	44,474,000	38,269,000
Fossil fuel stock, at average cost	20,735,000	21,616,000
Materials and supplies, at average cost	52,272,000	46,370,000
Prepaid service agreements - current	80,053,000	80,629,000
Prepaid income taxes	67,729,000	4,498,000
Prepaid expenses	7,714,000	5,637,000
Assets from risk management activities	46,000	375,000
Total current assets	403,631,000	291,978,000
Property, Plant, and Equipment:
In service	4,203,999,000	4,059,839,000
Less accumulated provision for depreciation	871,648,000	786,620,000
Plant in service, net of depreciation	3,332,351,000	3,273,219,000
Construction work in progress	494,867,000	24,835,000
Total property, plant, and equipment	3,827,218,000	3,298,054,000
Other Property and Investments:
Goodwill	1,839,000	1,839,000
Other intangible assets, net of amortization of $4,996 and $3,141 at September 30, 2013 and December 31, 2012, respectively	44,124,000	45,979,000
Total other property and investments	45,963,000	47,818,000
Deferred Charges and Other Assets:
Prepaid long-term service agreements	85,651,000	100,921,000
Other deferred charges and assets -- affiliated	2,792,000	3,468,000
Other deferred charges and assets	83,863,000	37,688,000
Total deferred charges and other assets	172,306,000	142,077,000
Total Assets	4,449,118,000	3,779,927,000
Current Liabilities:
Securities due within one year	2,200,000	259,000
Notes payable	191,765,000	70,968,000
Affiliated accounts payable	68,677,000	65,832,000
Other accounts payable	20,131,000	26,204,000
Accrued taxes --
Accrued income taxes	2,303,000	87,000
Other accrued taxes	13,362,000	3,031,000
Accrued interest	13,953,000	22,259,000
Construction holdbacks	25,000,000	0
Other current liabilities	21,609,000	8,932,000
Total current liabilities	359,000,000	197,572,000
Long-term Debt	1,625,830,000	1,306,099,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	636,530,000	550,685,000
Deferred convertible investment tax credits	189,152,000	167,130,000
Deferred capacity revenues -- affiliated	28,048,000	19,514,000
Other deferred credits and liabilities — affiliated	1,876,000	2,638,000
Other deferred credits and liabilities	8,318,000	5,863,000
Total deferred credits and other liabilities	863,924,000	745,830,000
Total Liabilities	2,848,754,000	2,249,501,000
Redeemable Noncontrolling Interest	27,065,000	8,069,000
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	1,029,443,000	1,027,548,000
Retained earnings	541,013,000	495,585,000
Accumulated other comprehensive loss	2,843,000	(776,000)
Total common stockholders' equity	1,573,299,000	1,522,357,000
Total Liabilities and Stockholders' Equity	$ 4,449,118,000	$ 3,779,927,000

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Derivatives - Narrative (Details) (USD $)	9 Months Ended
	Sep. 30, 2013 MMBTU
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	8,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	$ 20,000,000
Alabama Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	1,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	20,000,000
Georgia Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	5,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	20,000,000
Gulf Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	1,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	20,000,000
Mississippi Power [Member]
Derivatives (Textual) [Abstract]
Maximum potential collateral requirements arising the from credit-risk-related contingent features	20,000,000
Southern Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	1,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	$ 20,000,000

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Derivatives - Schedule of Derivatives and Gains (Losses) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Notional amount of interest rate derivatives
Notional Amount	$ 350
Interest Rate Paid, basis spread on LIBOR	1.96%	[1]
Fair Value Hedging [Member]
Notional amount of interest rate derivatives
Interest Rate Received	4.15%
Interest Rate Paid	3-month LIBOR  + 1.96%	[1]
Hedge Maturity Date	May 01, 2014
Fair Value Gain (Loss) September 30, 2013	$ 7
Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu	267,000,000
Longest Hedge Date	2018
Longest Non-Hedge Date	2017
Gas [Member] | Alabama Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	68,000,000
Longest Hedge Date	2017
Gas [Member] | Georgia Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	67,000,000
Longest Hedge Date	2017
Gas [Member] | Gulf Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	85,000,000
Longest Hedge Date	2018
Gas [Member] | Mississippi Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	46,000,000
Longest Hedge Date	2017
Gas [Member] | Southern Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	1,000,000
Longest Non-Hedge Date	2017

[1] (a)Weighted average

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Introduction Asset Retirement Obligations (Details) (Alabama Power [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Alabama Power [Member]
Jointly Owned Utility Plant Interests [Line Items]
Asset retirement obligation, current	$ 102
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	589	553
Liabilities incurred	0	0
Liabilities settled	0	(1)
Accretion	29	28
Cash flow revisions	102	0
Balance at end of period	$ 720	$ 580

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Segment and Related Information

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

SEGMENT AND RELATED INFORMATION

SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $97 million and $264 million for the three and nine months ended September 30, 2013, respectively, and $112 million and $330 million for the three and nine months ended September 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 inter-segment 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 September 30, 2013:
Operating revenues	$	4,744	$	365	$	(104	)	$	5,005	$	35		$	(23	)	$	5,017
Segment net income (loss)(a)(b)	765		85		—			850		(1		)	3			852
Nine Months Ended September 30, 2013:
Operating revenues	$	12,430	$	975	$	(285	)	$	13,120	$	108		$	(68	)	$	13,160
Segment net income (loss)(a)(c)	1,099		142		—			1,241		(12		)	1			1,230
Total assets at September 30, 2013	$	59,732	$	4,449	$	(153	)	$	64,028	$	1,090		$	(421	)	$	64,697
Three Months Ended September 30, 2012:
Operating revenues	$	4,794	$	355	$	(116	)	$	5,033	$	36		$	(20	)	$	5,049
Segment net income (loss)(a)	908		68		1			977		1			(2		)	976
Nine Months Ended September 30, 2012:
Operating revenues	$	12,232	$	894	$	(338	)	$	12,788	$	109		$	(63	)	$	12,834
Segment net income (loss)(a)	1,797		144		—			1,941		30			(4		)	1,967
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 September 30, 2013 includes a $150 million pre-tax charge ($93 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 nine months ended September 30, 2013 includes $1.1 billion in pre-tax charges ($704 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 September 30, 2013	$	4,319	$	520	$	166	$	5,005
Three Months Ended September 30, 2012	4,379		497		157		5,033
Nine Months Ended September 30, 2013	$	11,237	$	1,406	$	477	$	13,120
Nine Months Ended September 30, 2012	11,068		1,261		459		12,788

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Effective Tax Rate and Unrecognized Tax Benefits

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

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 33.9% for the nine months ended September 30, 2013 compared to 35.3% for the corresponding period in 2012. The decrease was primarily due to an increase in non-taxable AFUDC equity at Mississippi Power and increased investment tax credits at Southern Power, combined with lower net income for Southern Company as a whole. The decrease was partially offset by a decrease in state income tax credits and a settlement with the IRS in 2012 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 39.3% for the nine months ended September 30, 2013 compared to 38.8% for the corresponding period in 2012. The increase was primarily due to the recognition in 2012 of tax benefits related to a settlement with the IRS related to the production activities deduction.

Georgia Power

Georgia Power's effective tax rate was 38.0% for the nine months ended September 30, 2013 compared to 35.8% for the corresponding period in 2012. The increase was due to an increase in non-deductible book depreciation, a decrease in state income tax credits, a settlement with the IRS in 2012 related to the production activities deduction, and a decrease in non-taxable AFUDC equity.

Gulf Power

Gulf Power's effective tax rate was 37.6% for the nine months ended September 30, 2013 compared to 37.3% for the corresponding period in 2012.

Mississippi Power

Mississippi Power's effective tax rate was (42.1)% for the nine months ended September 30, 2013 compared to 26.7% 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 20.5% for the nine months ended September 30, 2013 compared to 34.4% for the corresponding period in 2012. The decrease was primarily due to an increase in investment tax credits.

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	3			—			—			—			—			2
Tax positions from prior periods	(66		)	(31		)	(23		)	(5		)	(2		)	(3		)
Balance as of September 30, 2013	$	7		$	—		$	—		$	—		$	4		$	2

The tax positions from prior 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 September 30, 2013			As of December 31, 2012
		Southern Company
	(in millions)
Tax positions impacting the effective tax rate		$	7	$	5
Tax positions not impacting the effective tax rate		—		65
Balance of unrecognized tax benefits		$	7	$	70

The tax positions impacting the effective tax rate primarily relate to state income tax credits. 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 September 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 settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

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 deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued final tangible property regulations. Southern Company is currently reviewing this new guidance. The ultimate outcome of this matter cannot be determined at the time; however, these regulations are not expected to have a material impact on net income.

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Stockholders' Equity (Policies)

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Earnings per Share

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.

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Introduction (Policies)

9 Months Ended

Sep. 30, 2013

Nuclear Decommissioning [Abstract]

Nuclear Decommissioning [Policy Text Block]

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

In September 2013, Alabama Power received a 2013 decommissioning cost site study for Plant Farley. Site study cost is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning based on the 2013 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076

	(in millions)
Site study costs:
Radiated structures	$	1,362
Non-radiated structures	80
Total site study costs	$	1,442

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates due to changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an escalation rate of 4.5% and a trust earnings rate of 7.0%, net of fees and taxes. The next site study is expected to be conducted in 2018.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations and Environmental Cost, Policy [Policy Text Block]

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company and Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information.

Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. In September 2013, Alabama Power received a new ARO liability cost study for the decommissioning of Plant Farley based on the 2013 site study, which increased the estimated ARO liability by approximately $102 million.

As of September 30, 2013 and 2012, details of the ARO related to the decommissioning of Plant Farley included in Southern Company's and Alabama Power's Condensed Balance Sheets herein are as follows:

	2013		2012
	(in millions)
Balance at beginning of year	$	589	$	553
Liabilities incurred	—		—
Liabilities settled	—		(1		)
Accretion	29		28
Cash flow revisions	102		—
Balance at end of period	$	720	$	580

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013
Entity Information [Line Items]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	881,740,546
Alabama Power [Member]
Entity Information [Line Items]
Entity Registrant Name	ALABAMA POWER CO
Entity Central Index Key	0000003153
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	30,537,500
Georgia Power [Member]
Entity Information [Line Items]
Entity Registrant Name	GEORGIA POWER CO
Entity Central Index Key	0000041091
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	9,261,500
Gulf Power [Member]
Entity Information [Line Items]
Entity Registrant Name	GULF POWER CO
Entity Central Index Key	0000044545
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	4,942,717
Mississippi Power [Member]
Entity Information [Line Items]
Entity Registrant Name	MISSISSIPPI POWER CO
Entity Central Index Key	0000066904
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,121,000
Southern Power [Member]
Entity Information [Line Items]
Entity Registrant Name	SOUTHERN POWER CO
Entity Central Index Key	0001160661
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,000

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Fair Value Measurements (Policies)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Valuation Methodologies

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.