10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

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

     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 o

     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 o

     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):

	Large			Smaller
	Accelerated	Accelerated	Non-accelerated	Reporting
Registrant	Filer	Filer	Filer	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 o No þ (Response applicable to all registrants.)

	Description of	Shares Outstanding
Registrant	Common Stock	at September 30, 2011
The Southern Company	Par Value $5 Per Share		861,928,103
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		4,142,717
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, 2011

		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		9
	Condensed Consolidated Statements of Cash Flows		10
	Condensed Consolidated Balance Sheets		11
	Condensed Consolidated Statements of Comprehensive Income		13
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
	Alabama Power Company
	Condensed Statements of Income		39
	Condensed Statements of Comprehensive Income		39
	Condensed Statements of Cash Flows		40
	Condensed Balance Sheets		41
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		43
	Georgia Power Company
	Condensed Statements of Income		60
	Condensed Statements of Comprehensive Income		60
	Condensed Statements of Cash Flows		61
	Condensed Balance Sheets		62
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		64
	Gulf Power Company
	Condensed Statements of Income		84
	Condensed Statements of Comprehensive Income		84
	Condensed Statements of Cash Flows		85
	Condensed Balance Sheets		86
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		88
	Mississippi Power Company
	Condensed Statements of Income		105
	Condensed Statements of Comprehensive Income		105
	Condensed Statements of Cash Flows		106
	Condensed Balance Sheets		107
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		109
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		132
	Condensed Consolidated Statements of Comprehensive Income		132
	Condensed Consolidated Statements of Cash Flows		133
	Condensed Consolidated Balance Sheets		134
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		136
	Notes to the Condensed Financial Statements		148
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		37
Item 4.	Controls and Procedures		37

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2011

		Page
		Number
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		185
Item 1A.	Risk Factors		185
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits		186
	Signatures		191

4

DEFINITIONS

Term	Meaning
2007 Retail Rate Plan	Georgia Power’s retail rate plan for the years 2008 through 2010
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
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
Clean Air Act	Clean Air Act Amendments of 1990
DOE	U.S. Department of Energy
Duke Energy	Duke Energy Corporation
ECO Plan	Mississippi Power’s Environmental Compliance Overview Plan
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
Form 10-K	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2010
GAAP	Generally Accepted Accounting Principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany Interchange Contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
MW	Megawatt
MWH	Megawatt-hour
NCCR tariff	Georgia Power’s Nuclear Construction Cost Recovery tariff, which became effective January 1, 2011, in accordance with the Georgia Nuclear Energy Financing Act
NDR	Alabama Power’s natural disaster reserve
NRC	Nuclear Regulatory Commission
NSR	New Source Review
OCI	Other Comprehensive Income
PEP	Mississippi Power’s Performance Evaluation Plan
Plant Vogtle Units 3 and 4	Two new nuclear generating units under construction at Plant Vogtle
Power Pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power Purchase Agreement
PSC	Public Service Commission
Rate CNP Environmental	Alabama Power’s rate certificated new plant environmental
Rate ECR	Alabama Power’s energy cost recovery rate mechanism
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
SCR	Selective catalytic reduction
SCS	Southern Company Services, Inc.

5

Term	Meaning
SEC	Securities and Exchange Commission
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, and other subsidiaries
SouthernLINC Wireless	Southern Communications Services, Inc.
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company
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 the strategic goals for the wholesale business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate actions, current and proposed environmental regulations and related estimated expenditures, future earnings, access to sources of capital, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impact of the Small Business Jobs and Credit Act of 2010, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, storm damage cost recovery and repairs, and estimated construction and other 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, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, 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 and IRS 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), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities;

• investment performance of Southern Company’s employee benefit plans and 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 the Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;

• regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals and potential DOE loan guarantees;

• 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 Southern Company’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 Southern Company’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 filed by the registrants from time to time with the SEC.

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

7

THE SOUTHERN COMPANY AND
SUBSIDIARY COMPANIES

8

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	4,693		$	4,573		$	11,931		$	11,603
Wholesale revenues		557			566			1,513			1,581
Other electric revenues		161			160			464			438
Other revenues		17			21			53			63
Total operating revenues		5,428			5,320			13,961			13,685
Operating Expenses:
Fuel		1,908			1,970			5,057			5,244
Purchased power		215			209			460			464
Other operations and maintenance		983			1,019			2,837			2,846
Depreciation and amortization		431			427			1,279			1,137
Taxes other than income taxes		239			236			686			662
Total operating expenses		3,776			3,861			10,319			10,353
Operating Income		1,652			1,459			3,642			3,332
Other Income and (Expense):
Allowance for equity funds used during construction		42			45			113			140
Interest expense, net of amounts capitalized		(217	)		(225	)		(638	)		(666	)
Other income (expense), net		(1	)		(3	)		(3	)		(10	)
Total other income and (expense)		(176	)		(183	)		(528	)		(536	)
Earnings Before Income Taxes		1,476			1,276			3,114			2,796
Income taxes		543			442			1,123			925
Consolidated Net Income		933			834			1,991			1,871
Dividends on Preferred and Preference Stock of Subsidiaries		17			17			49			49
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	916		$	817		$	1,942		$	1,822
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	1.07		$	0.98		$	2.27		$	2.20
Diluted EPS	$	1.06		$	0.97		$	2.26		$	2.19
Average number of shares of common stock outstanding (in millions)
Basic		860			836			854			829
Diluted		868			842			861			833
Cash dividends paid per share of common stock	$	0.4725		$	0.4550		$	1.4000		$	1.3475

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

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2011			2010
	(in millions)
Operating Activities:
Consolidated net income	$	1,991		$	1,871
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		1,530			1,377
Deferred income taxes		914			573
Deferred revenues		(2	)		(77	)
Allowance for equity funds used during construction		(113	)		(140	)
Pension, postretirement, and other employee benefits		(1	)		52
Stock based compensation expense		35			28
Generation construction screening costs		—			(51	)
Other, net		13			(1	)
Changes in certain current assets and liabilities —
-Receivables		(118	)		(319	)
-Fossil fuel stock		229			220
-Other current assets		(45	)		(59	)
-Accounts payable		(155	)		(82	)
-Accrued taxes		440			118
-Accrued compensation		(96	)		93
-Other current liabilities		(24	)		(76	)
Net cash provided from operating activities		4,598			3,527
Investing Activities:
Property additions		(3,115	)		(2,894	)
Distribution of restricted cash		61			25
Nuclear decommissioning trust fund purchases		(1,946	)		(696	)
Nuclear decommissioning trust fund sales		1,942			672
Proceeds from property sales		21			7
Cost of removal, net of salvage		(90	)		(84	)
Change in construction payables		137			(84	)
Other investing activities		92			48
Net cash used for investing activities		(2,898	)		(3,006	)
Financing Activities:
Decrease in notes payable, net		(1,160	)		(289	)
Proceeds —
Long-term debt issuances		3,144			2,796
Common stock issuances		620			610
Redemptions —
Long-term debt		(1,987	)		(1,871	)
Payment of common stock dividends		(1,193	)		(1,114	)
Payment of dividends on preferred and preference stock of subsidiaries		(49	)		(49	)
Other financing activities		(6	)		(35	)
Net cash provided from (used for) financing activities		(631	)		48
Net Change in Cash and Cash Equivalents		1,069			569
Cash and Cash Equivalents at Beginning of Period		447			690
Cash and Cash Equivalents at End of Period	$	1,516		$	1,259
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $54 and $61 capitalized for 2011 and 2010, respectively)	$	369		$	589
Income taxes (net of refunds)		(358	)		278
Noncash transactions — accrued property additions at end of period		541			361

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 BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2011			2010
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,516		$	447
Restricted cash and cash equivalents		9			68
Receivables —
Customer accounts receivable		1,401			1,140
Unbilled revenues		449			420
Under recovered regulatory clause revenues		210			209
Other accounts and notes receivable		250			285
Accumulated provision for uncollectible accounts		(30	)		(25	)
Fossil fuel stock, at average cost		1,076			1,308
Materials and supplies, at average cost		854			827
Vacation pay		150			151
Prepaid expenses		319			784
Other regulatory assets, current		191			210
Other current assets		100			59
Total current assets		6,495			5,883
Property, Plant, and Equipment:
In service		58,079			56,731
Less accumulated depreciation		20,891			20,174
Plant in service, net of depreciation		37,188			36,557
Other utility plant, net		57			—
Nuclear fuel, at amortized cost		743			670
Construction work in progress		5,809			4,775
Total property, plant, and equipment		43,797			42,002
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,159			1,370
Leveraged leases		641			624
Miscellaneous property and investments		256			277
Total other property and investments		2,056			2,271
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,361			1,280
Prepaid pension costs		137			88
Unamortized debt issuance expense		163			178
Unamortized loss on reacquired debt		283			274
Deferred under recovered regulatory clause revenues		64			218
Other regulatory assets, deferred		2,496			2,402
Other deferred charges and assets		491			436
Total deferred charges and other assets		4,995			4,876
Total Assets	$	57,343		$	55,032

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 BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholders’ Equity	2011			2010
	(in millions)
Current Liabilities:
Securities due within one year	$	1,891		$	1,301
Notes payable		137			1,297
Accounts payable		1,355			1,275
Customer deposits		340			332
Accrued taxes —
Accrued income taxes		46			8
Unrecognized tax benefits		22			187
Other accrued taxes		458			440
Accrued interest		245			225
Accrued vacation pay		191			194
Accrued compensation		349			438
Liabilities from risk management activities		136			152
Other regulatory liabilities, current		107			88
Other current liabilities		380			535
Total current liabilities		5,657			6,472
Long-term Debt		18,733			18,154
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		8,613			7,554
Deferred credits related to income taxes		223			235
Accumulated deferred investment tax credits		579			509
Employee benefit obligations		1,608			1,580
Asset retirement obligations		1,307			1,257
Other cost of removal obligations		1,170			1,158
Other regulatory liabilities, deferred		255			312
Other deferred credits and liabilities		483			517
Total deferred credits and other liabilities		14,238			13,122
Total Liabilities		38,628			37,748
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, 2011: 862 million shares
— December 31, 2010: 844 million shares
Treasury — September 30, 2011: 0.5 million shares
— December 31, 2010: 0.5 million shares
Par value		4,312			4,219
Paid-in capital		4,302			3,702
Treasury, at cost		(16	)		(15	)
Retained earnings		9,116			8,366
Accumulated other comprehensive loss		(81	)		(70	)
Total Common Stockholders’ Equity		17,633			16,202
Preferred and Preference Stock of Subsidiaries		707			707
Total Stockholders’ Equity		18,340			16,909
Total Liabilities and Stockholders’ Equity	$	57,343		$	55,032

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 STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	(in millions)						(in millions)
Consolidated Net Income	$	933		$	834		$	1,991		$	1,871
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(10), $-, $(8), and $-, respectively		(17	)		2			(14	)		1
Reclassification adjustment for amounts included in net income, net of tax of $2, $4, $4, and $10, respectively		3			3			6			14
Marketable securities:
Change in fair value, net of tax of $(2), $-, $(1) and $-, respectively		(5	)		(3	)		(3	)		—
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $2, $1, $2, and $1, respectively		—			—			—			1
Total other comprehensive income (loss)		(19	)		2			(11	)		16
Dividends on preferred and preference stock of subsidiaries		(17	)		(17	)		(49	)		(49	)
Comprehensive Income	$	897		$	819		$	1,931		$	1,838

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
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010

OVERVIEW

Discussion of the results of operations is focused on Southern Company’s primary business of electricity sales in the Southeast by the traditional operating companies — Alabama Power, Georgia Power, Gulf Power, and Mississippi Power — and Southern Power. The traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets 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.

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.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$99	12.1	$120	6.6

Southern Company’s third quarter 2011 net income after dividends on preferred and preference stock of subsidiaries was $916 million ($1.07 per share) compared to $817 million ($0.98 per share) for the third quarter 2010. The net income increase for the third quarter 2011 when compared to the corresponding period in 2010 was primarily the result of increases in retail base revenues at Georgia Power as authorized under the 2010 ARP and the NCCR tariff and a decrease in other operations and maintenance expenses. The net income increase for third quarter 2011 was partially offset by decreases in revenues due to relatively cooler weather primarily in the month of September compared to the third quarter 2010.

Southern Company’s year-to-date 2011 net income after dividends on preferred and preference stock of subsidiaries was $1.94 billion ($2.27 per share) compared to $1.82 billion ($2.20 per share) for year-to-date 2010. The net income increase for year-to-date 2011 when compared to the corresponding period in 2010 was primarily the result of increases in retail base revenues at Georgia Power as authorized under the 2010 ARP and the NCCR tariff and increases in energy and capacity revenues at Southern Power. The net income increase for year-to-date 2011 was partially offset by a decrease in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power, decreases in revenues due to relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010, a decrease in wholesale revenues primarily at Alabama Power, and an increase in depreciation on additional plant in service related to environmental, transmission, and distribution projects.

14

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$120	2.6	$328	2.8

In the third quarter 2011, retail revenues were $4.69 billion compared to $4.57 billion for the corresponding period in 2010. For year-to-date 2011, retail revenues were $11.93 billion compared to $11.60 billion for the corresponding period in 2010.

Details of the change to retail revenues follow:

	Third Quarter						Year-to-Date
	2011						2011
	(in millions)			(% change)			(in millions)			(% change)
Retail — prior year	$	4,573					$	11,603
Estimated change in —
Rates and pricing		227			5.0			593			5.1
Sales growth (decline)		9			0.2			25			0.2
Weather		(93	)		(2.0	)		(170	)		(1.5	)
Fuel and other cost recovery		(23	)		(0.5	)		(120	)		(1.0	)
Retail – current year	$	4,693			2.7	%	$	11,931			2.8	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 primarily due to increases in Georgia Power’s retail base revenues as authorized under the 2010 ARP and the NCCR tariff, which both became effective January 1, 2011. Also contributing to these increases were revenues associated with Alabama Power’s Rate CNP Environmental due to completion of construction projects related to environmental mandates, although there was no increase in the Rate CNP Environmental billing factors in 2011.

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 due to increases in weather-adjusted retail KWH sales of 0.5% and 1.1%, respectively. For the third quarter 2011, weather-adjusted residential KWH sales decreased 0.3%, weather-adjusted commercial KWH sales remained flat, and weather-adjusted industrial KWH sales increased 2.0%. For year-to-date 2011, weather-adjusted residential KWH sales decreased 0.1%, weather-adjusted commercial KWH sales decreased 0.2%, and weather-adjusted industrial KWH sales increased 3.9%. Increased demand in the primary metals, petroleum refining, fabricated metals, and pipelines sectors were the main contributors to the increases in weather-adjusted industrial KWH sales for the third quarter and year-to-date 2011.

Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 due to relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010.

Fuel and other cost recovery revenues decreased $23 million in the third quarter 2011 and $120 million for year-to-date 2011 when compared to the corresponding periods in 2010. 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 fuel component of purchased power costs, and do not affect net income.

15

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(9)	(1.6)	$(68)	(4.3)

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-owned generation, demand for energy within the Southern Company system service territory, and the availability of the Southern Company system 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 variable cost to produce the energy.

In the third quarter 2011, wholesale revenues were $557 million compared to $566 million for the corresponding period in 2010, reflecting a $15 million decrease in energy revenues and a $6 million increase in capacity revenues. The decrease was primarily due to less favorable weather in the third quarter 2011 and lower energy and capacity revenues associated with the expiration of PPAs in December 2010 at Southern Power. The decrease was partially offset by higher energy and capacity revenues under new PPAs at Southern Power that began in December 2010 and January 2011.

For year-to-date 2011, wholesale revenues were $1.51 billion compared to $1.58 billion for the corresponding period in 2010, reflecting a $48 million decrease in energy revenues and a $20 million decrease in capacity revenues. The decrease was primarily related to a decrease in wholesale revenues at Alabama Power due to the expiration of long-term unit power sales contracts in May 2010 and the capacity subject to those contracts being made available for retail service starting in June 2010, as well as lower energy and capacity revenues associated with the expiration of PPAs in December 2010 at Southern Power. The decrease was partially offset by higher energy and capacity revenues under new PPAs at Southern Power that began in June, July, and December 2010 and January 2011.

Other Electric Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$1	0.6	$26	5.9

In the third quarter 2011, other electric revenues were $161 million compared to $160 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material. For year-to-date 2011, other electric revenues were $464 million compared to $438 million for the corresponding period in 2010. The increase was primarily the result of an increase in transmission revenues at Georgia Power.

Other Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(19.0)	$(10)	(15.9)

In the third quarter 2011, other revenues were $17 million compared to $21 million for the corresponding period in 2010. For year-to-date 2011, other revenues were $53 million compared to $63 million for the corresponding period in 2010. The third quarter and year-to-date 2011 decreases were primarily the result of a decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to continued competition in the industry.

16

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Third Quarter 2011						Year-to-Date 2011
	vs.						vs.
	Third Quarter 2010						Year-to-Date 2010
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	(62	)		(3.1	)	$	(187	)		(3.6	)
Purchased power		6			2.9			(4	)		(0.9	)
Total fuel and purchased power expenses	$	(56	)				$	(191	)

* Fuel includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.

Fuel and purchased power expenses for the third quarter 2011 were $2.12 billion compared to $2.18 billion for the corresponding period in 2010. The decrease was primarily the result of a $59 million net decrease in the average cost of fuel and purchased power, slightly offset by a $3 million net increase related to total KWHs generated and purchased. The decrease in the average cost of fuel and purchased power was primarily the result of a 21.7% decrease in the average cost of purchased power, slightly offset by a 1.1% increase in the average cost of fuel per KWH generated.

For year-to-date 2011, fuel and purchased power expenses were $5.52 billion compared to $5.71 billion for the corresponding period in 2010. The decrease was primarily the result of a $143 million net decrease related to total KWHs generated and purchased and a $48 million decrease in the average cost of fuel and purchased power. The net decrease related to total KWHs generated and purchased resulted primarily from lower customer demand. The decrease in the average cost of fuel and purchased power resulted primarily from a 9.6% decrease in the average cost of natural gas per KWH generated, partially offset by a 3.8% increase in the average cost of coal per KWH generated.

Fuel expenses at the traditional operating companies are generally offset by fuel revenues and do not have a significant effect on net income. See FUTURE EARNINGS POTENTIAL — “State 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 affect net income.

Details of the Southern Company system’s cost of generation and purchased power are as follows:

	Third Quarter		Third Quarter									Percent
Average Cost	2011		2010		Percent Change			Year-to-Date 2011		Year-to-Date 2010		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		3.59		3.55		1.1			3.52		3.55		(0.9	)
Purchased power		6.29		8.03		(21.7	)		7.06		7.13		(1.0	)

Energy purchases will vary depending on demand for energy within the Southern Company system service area, the market cost of available energy as compared to the cost of Southern Company system-generated energy, and the availability of Southern Company system generation.

17

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(36)	(3.5)	$(9)	(0.3)

In the third quarter 2011, other operations and maintenance expenses were $983 million compared to $1.02 billion for the corresponding period in 2010. The decrease was primarily the result of an additional accrual in the third quarter 2010 of $40 million to the NDR at Alabama Power and reductions in overhead line costs at Alabama Power due to storm restoration efforts. The decrease was partially offset by increases in routine transmission and distribution expenses and customer service related costs.

For year-to-date 2011, other operations and maintenance expenses were $2.84 billion compared to $2.85 billion for the corresponding period in 2010. The decrease was primarily the result of a $53 million decrease in transmission and distribution costs mainly due to an additional accrual in the third quarter 2010 of $40 million to the NDR at Alabama Power and reductions in overhead line costs at Alabama Power due to storm restoration efforts, partially offset by an increase in overhead line maintenance at Georgia Power. Also contributing to the decrease was a $20 million reduction in administrative and general costs. The decrease was partially offset by a $33 million increase in commodity and labor costs, a $17 million increase in scheduled outage and maintenance costs, and a $12 million increase in customer service related costs.

In August 2010, the Alabama PSC approved a change to Alabama Power’s nuclear maintenance outage accounting process associated with routine refueling activities. As a result, Alabama Power will not recognize any nuclear maintenance outage expenses in 2011, reducing nuclear production expense by approximately $50 million as compared to 2010. 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.

Depreciation and Amortization

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$4	0.9	$142	12.5

In the third quarter 2011, depreciation and amortization was $431 million compared to $427 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material.

For year-to-date 2011, depreciation and amortization was $1.28 billion compared to $1.14 billion for the corresponding period in 2010. The increase was primarily the result of a $94 million decrease in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC and additional depreciation on plant in service related to environmental, transmission, and distribution projects.

See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” for additional information on the other cost of removal regulatory liability.

18

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$3	1.3	$24	3.6

In the third quarter 2011, taxes other than income taxes were $239 million compared to $236 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material.

For year-to-date 2011, taxes other than income taxes were $686 million compared to $662 million for the corresponding period in 2010. The year-to-date 2011 increase was primarily the result of increases in property taxes and franchise fees.

Allowance for Equity Funds Used During Construction

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(6.7)	$(27)	(19.3)

In the third quarter 2011, AFUDC equity was $42 million compared to $45 million for the corresponding period in 2010. The decrease when compared to the corresponding period in 2010 was not material.

For year-to-date 2011, AFUDC equity was $113 million compared to $140 million for the corresponding period in 2010. The decrease was primarily due to the inclusion of Georgia Power’s Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011 which reduced the amount of AFUDC capitalized and the completion of construction projects related to environmental mandates at Alabama Power. The decrease was partially offset by construction work in progress related to Mississippi Power’s Kemper IGCC which began construction in June 2010.

See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” herein for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(3.6)	$(28)	(4.2)

In the third quarter 2011, interest expense, net of amounts capitalized was $217 million compared to $225 million for the corresponding period in 2010. The decrease was primarily due to lower interest expense on variable rate pollution control bonds at Georgia Power.

For year-to-date 2011, interest expense, net of amounts capitalized was $638 million compared to $666 million for the corresponding period in 2010. The decrease was primarily due to a reduction of $23 million in interest expense at Georgia Power related to the settlement of tax litigation with the Georgia Department of Revenue (DOR). See Note (B) to the Condensed Financial Statements under “Income Tax Matters — Georgia State Income Tax Credits” herein for additional information.

19

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$101	22.9	$198	21.4

In the third quarter 2011, income taxes were $543 million compared to $442 million for the corresponding period in 2010. The increase was primarily due to higher pre-tax earnings and an increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid.

For year-to-date 2011, income taxes were $1.12 billion compared to $925 million for the corresponding period in 2010. The increase was primarily due to higher pre-tax earnings, a decrease in the first quarter 2010 in uncertain tax positions at Georgia Power related to state income tax credits, an increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid, and a reduction in AFUDC equity, which is non-taxable.

See Notes (B) and (G) to the Condensed Financial Statements under “Income Tax Matters — Georgia State Income Tax Credits” and “Unrecognized Tax Benefits,” respectively, herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company’s future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’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. Other major factors include profitability of the competitive wholesale supply business and federal regulatory policy. 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 area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total available generating capacity, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in economic conditions impact sales for the traditional operating companies and Southern Power, and 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 the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. 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.

Southern Company has completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. 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 proposed coal combustion byproducts rule. Although its analysis is preliminary,

20

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company estimates that the aggregate capital costs to the traditional operating companies for compliance with these rules could range from $13 billion to $18 billion through 2020 if the rules are adopted as proposed. Included in this amount is $686 million of estimated expenditures included in the 2011-2013 base level capital budgets of Southern Company subsidiaries described herein in anticipation of these rules. See FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein for additional information. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Southern Company’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.

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 regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has appealed the decision to the U.S. Court of Appeals for the Eleventh Circuit. The ultimate outcome of this matter cannot be determined at this time.

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — New York Case” of Southern Company in Item 7 and Note 3 of the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.

21

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” of Southern Company in Item 7 and Note 3 of the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies (including Alabama Power, Georgia Power, Gulf Power, and Southern Power) and includes many of the same defendants that were involved in the earlier case. Southern Company believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.

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 regulation of air quality.

On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of the facilities of Southern Company’s subsidiaries which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.

In April 2010, the EPA proposed an Industrial Boiler MACT rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA published the final rule on March 21, 2011 and, at the same time, issued a notice of intent to reconsider the final rule to allow for additional public review and comment. The EPA has announced plans to finalize the rule by April 30, 2012. The effect of the regulatory proceedings will depend on the final form of the revised regulations and the outcome of any legal challenges and cannot be determined at this time. On October 18, 2011, the Georgia PSC approved Georgia Power’s request to further delay the decision to convert Plant Mitchell Unit 3 from coal to biomass for two to four years, until there is greater clarity regarding the Industrial Boiler MACT rule and other proposed and recently adopted regulations. Georgia Power will file semi-annual construction monitoring reports on March 1 and August 15 throughout the delay period.

In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. On April 6, 2011, the EPA attempted to rescind its previous approval of the Alabama SIP revision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s

22

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

attempted rescission pending judicial review. The EPA’s decision became effective May 6, 2011 and the court denied Alabama Power’s requested stay on May 12, 2011. Unless the court resolves Alabama Power’s appeal in its favor, the EPA’s rescission will continue to affect Alabama Power’s operations. The EPA’s rescission has affected unit availability and increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.

On June 23, 2011, the EPA published its determination that the 20-county area within metropolitan Atlanta has air quality which attains the 1997 eight-hour ozone air quality standard. In March 2008, the EPA adopted a more stringent eight-hour ozone air quality standard, which it began to implement in September 2011. The 2008 standard is expected to result in designation of new nonattainment areas within the Southern Company system service territory and could result in additional required reductions in nitrogen oxide emissions. The ultimate outcome of this matter cannot be determined at this time.

On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. Each of the states within the Southern Company system service area is subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program, and the States of Alabama, Georgia, North Carolina, and Texas are subject to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for each state, and the effect on each of the traditional operating companies will vary. The rule could have significant effects on the traditional operating companies, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including the traditional operating companies and Southern Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.

On March 22, 2011, the Board of the Georgia Department of Natural Resources began consideration of modifications to the Georgia Multi-Pollutant Rule, which is designed to reduce emissions of mercury, sulfur dioxide, and nitrogen oxides statewide. On June 29, 2011, the modifications were approved and the compliance dates for certain of Georgia Power’s coal-fired generating units were changed as follows:

Branch 1	December 31, 2013
Branch 2	October 1, 2013
Branch 3	October 1, 2015
Branch 4	December 31, 2015

See “State PSC Matters — Georgia Power Retail Regulatory Matters — 2011 Integrated Resource Plan Update” herein for additional information.

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 regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn

23

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at many of Southern Company’s subsidiaries’ existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of the facilities of Southern Company’s subsidiaries may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

State PSC Matters

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In previous years, the traditional operating companies have experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and uranium and volatile price swings in natural gas. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Alabama Power, Georgia Power, and Gulf Power of approximately $260 million at September 30, 2011. Mississippi Power collected all previously under recovered fuel costs and, as of September 30, 2011, had a total over recovered fuel balance of approximately $41 million. At December 31, 2010, total under recovered fuel costs included in the balance sheets of Alabama Power, Georgia Power, and Gulf Power were approximately $420 million and Mississippi Power had a total over recovered fuel balance of $55 million. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on Southern Company’s revenues or net income, but does impact annual cash flow. The traditional operating companies continuously monitor the under or over recovered fuel cost balances.

On May 24, 2011, the Georgia PSC approved Georgia Power’s request to decrease fuel rates by 0.61%. The decrease reduced Georgia Power’s annual billings by approximately $43 million effective June 1, 2011. 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.

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

Alabama Power Retail Regulatory Matters

Environmental Accounting Order

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — General” of Southern Company in Item 7 of the Form 10-K for additional information regarding environmental regulations. Proposed environmental regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions. On September 7, 2011, the Alabama PSC approved an order allowing for the establishment of a regulatory asset to record the unrecovered investment costs associated with any such decisions, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure. These costs would be amortized over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement.

24

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Rate Adjustments

See BUSINESS — “Rate Matters — Rate Structure and Cost Recovery Plans” of Southern Company in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Alabama Power — Rate RSE” and “PSC Matters — Alabama Power — Natural Disaster Reserve” of Southern Company in Item 7 of the Form 10-K for information regarding the rate structure of Alabama Power. On July 12, 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under Alabama Power’s rate structure effective with October 2011 billings. Alabama Power anticipates the elimination of this adjustment will result in additional revenues of approximately $30 million for the remainder of 2011 and is expected to have an annual effect of approximately $150 million beginning in 2012.

In accordance with the order, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues from the elimination of the tax-related adjustment to replenish the NDR, which was impacted as a result of operations and maintenance expenses incurred in connection with the April 2011 storms in Alabama. Alabama Power expects that the additional revenue in 2012 will preclude the need for a rate adjustment under Rate Stabilization and Equalization (Rate RSE). Accordingly, Alabama Power agreed to a moratorium on any increase in 2012 under Rate RSE.

Natural Disaster Reserve

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.

During the first half of 2011, multiple storms caused varying degrees of damage to Alabama Power’s transmission and distribution facilities. The most significant storm occurred on April 27, 2011, causing over 400,000 of Alabama Power’s 1.4 million customers to be without electrical service. The estimated cost of repairing the damage to facilities and restoring electrical service to customers, as a result of these storms, is approximately $45 million for operations and maintenance expenses and approximately $163 million for capital-related expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.

At September 30, 2011, the NDR had an accumulated balance of $75 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.

In accordance with the order discussed above that was issued by the Alabama PSC on July 12, 2011 to eliminate a tax-related adjustment under Alabama Power’s rate structure, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues, which are expected to be approximately $30 million.

Georgia Power Retail Regulatory Matters

2011 Integrated Resource Plan Update

See “Environmental Matters — Air Quality” and “— Water Quality” herein and BUSINESS — “Rate Matters — Integrated Resource Planning” of Southern Company in Item 1, 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 — Retail Rate Plans” in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility

25

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MACT rule for coal- and oil-fired EGUs, 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; and the 2010 ARP.

On August 4, 2011, Georgia Power filed an update to its IRP (2011 IRP Update). The filing included Georgia Power’s application to decertify Plant Branch Units 1 and 2 as of December 31, 2013 and October 1, 2013, the compliance dates for the respective units under the Georgia Multi-Pollutant Rule. However, as a result of the considerable uncertainty regarding pending state and federal environmental regulations, Georgia Power is continuing to defer decisions to add controls, switch fuel, or retire its remaining fossil generating units where environmental controls have not yet been installed, representing approximately 2,600 MWs of capacity. Georgia Power expects to update its economic analysis of these units once the Utility MACT rule is finalized. Georgia Power currently expects that certain units, representing approximately 600 MWs of capacity, are more likely than others to switch fuel or be controlled in time to comply with the Utility MACT rule. However, even if the updated economic analysis shows more positive benefits associated with adding controls or switching fuel for more units, it is unlikely that all of the required controls could be completed by 2015, the expected effective date of the Utility MACT rule. As a result, Georgia Power currently cannot rely on the availability of approximately 2,000 MWs of capacity in 2015. As such, the 2011 IRP Update also includes Georgia Power’s application requesting that the Georgia PSC certify the purchase of a total of 1,562 MWs of capacity beginning in 2015, from four PPAs selected through the 2015 request for proposal process.

Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets resulting from new or revised environmental regulations through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. In connection with the retirement decision, Georgia Power reclassified the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net. Georgia Power is continuing to depreciate these units using the current composite straight-line rates previously approved by the Georgia PSC and upon actual retirement has requested that the Georgia PSC approve the continued deferral and amortization of the units’ remaining net carrying value. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Southern Company’s financial statements.

The Georgia PSC is expected to vote on these requests in March 2012. The ultimate outcome of these matters cannot be determined at this time.

Storm Damage Recovery

During April 2011, severe storms in Georgia caused significant damage to Georgia Power’s distribution and transmission facilities. Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2011, the balance in the regulatory asset related to storm damage was $45 million. As a result of this regulatory treatment, the costs related to the storms are not expected to have a material impact on Southern Company’s financial statements. See Note 1 to the financial statements of Southern Company under “Storm Damage Reserves” in Item 8 of the Form 10-K for additional information.

Gulf Power Retail Regulatory Matters

Retail Base Rate Case

On July 8, 2011, 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 $93.5 million. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail rate of return on common equity of 11.7%. The Florida PSC is expected to make a decision on this matter in the first quarter 2012.

26

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On August 23, 2011, the Florida PSC approved Gulf Power’s request for an interim retail rate increase of $38.5 million per year, effective beginning with billings based on meter readings on and after September 22, 2011 and continuing through the effective date of the Florida PSC’s decision on Gulf Power’s petition for the permanent increase. The interim rates are subject to refund pending the outcome of the permanent retail base rate proceeding.

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

Income Tax Matters

Legislation

On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On June 10, 2011, Georgia Power and the Georgia DOR agreed to a settlement resolving the claims. As a result, Georgia Power recorded additional tax benefits of approximately $64 million and, in accordance with the 2010 ARP, also recorded a related regulatory liability of approximately $62 million. In addition, Georgia Power recorded a reduction of approximately $23 million in related interest expense. See Notes 3 and 5 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, for additional information.

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 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 construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction 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 March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Southern Company estimates the potential increased cash flow for 2011 to be between approximately $500 million and $600 million. The ultimate outcome of this matter cannot be determined at this time.

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. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including natural gas, biomass, and potentially solar units at Southern Power, natural gas and new nuclear units at Georgia Power, and the Kemper IGCC facility at Mississippi Power, as well as 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. See Note 7 to the financial statements of

27

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company under “Construction Program” in Item 8 of the Form 10-K for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Nuclear Construction,” “Retail Regulatory Matters — Georgia Power — Other Construction,” and “Retail Regulatory Matters — Mississippi Power Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” and “State PSC Matters — Mississippi Power — Integrated Coal Gasification Combined Cycle” herein for additional information.

On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. While the Southern Company system will continue to monitor this situation, it has not identified any immediate impact to the licensing and construction of Plant Vogtle Units 3 and 4 or the operation of the existing nuclear generating units of Alabama Power and Georgia Power.

The events in Japan have created uncertainties that may affect transportation of materials, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. On July 12, 2011, a special NRC task force issued a report with initial recommendations for enhancing nuclear reactor safety in the U.S., including potential changes in emergency planning, onsite backup generation, and spent fuel pools for existing reactors. The final form and resulting impact of any changes to safety requirements for existing nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. The task force report supported completion of the certification of the AP1000 reactor design being used at Plant Vogtle Units 3 and 4, noting that the design has many of the features necessary to address the task force’s recommendations.

See RISK FACTORS of Southern Company 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 events cannot be determined at this time.

Investments in Leveraged Leases

Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements of Southern Company under “Leveraged Leases” in Item 8 of the Form 10-K for additional information.

The recent financial and operational performance of one of Southern Company’s lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the asset. Southern Company will continue to monitor the performance of the underlying assets and to evaluate the ability of the lessee to continue to make the required lease payments. While there are strategic options that Southern Company may pursue to recover its investment in the leveraged lease, the potential impairment loss that would be incurred if there is an abandonment of the project is expected to be approximately $80 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.

28

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company’s financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition remained stable at September 30, 2011. 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 “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $4.60 billion for the first nine months of 2011, an increase of $1.07 billion from the corresponding period in 2010. Significant changes in operating cash flow for the first nine months of 2011 as compared to the corresponding period in 2010 include an increase in net income as previously discussed. Also contributing to the increase was an increase in deferred income taxes related to bonus depreciation and an increase in accrued income taxes primarily due to the timing of tax payments. Net cash used for investing activities totaled $2.90 billion for the first nine months of 2011, a decrease of $108 million from the corresponding period in 2010 due to timing of capital expenditures. Net cash used for financing activities totaled $631 million for the first nine months of 2011, compared to $48 million provided from financing activities in the corresponding period in 2010. This change was primarily due to a decrease in notes payable and redemptions of long-term debt, partially offset by long-term debt issuances. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

29

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant balance sheet changes for the first nine months of 2011 include an increase in cash of $1.07 billion due to increased cash collection from operations during the summer months, higher cash balances at Alabama Power, and an increase of $1.79 billion in total property, plant, and equipment for the installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other significant changes include a decrease in notes payable of $1.16 billion and an increase in equity of $1.43 billion.

The market price of Southern Company’s common stock at September 30, 2011 was $42.37 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $20.46 per share, representing a market-to-book ratio of 207%, compared to $38.23, $19.21, and 199%, respectively, at the end of 2010. The dividend for the third quarter 2011 was $0.4725 per share compared to $0.455 per share in the third quarter 2010.

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 its subsidiaries and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $1.89 billion will be required through September 30, 2012 to fund maturities of long-term debt.

The construction programs of Southern Company’s subsidiaries are estimated to include a base level investment of $4.9 billion, $5.1 billion, and $4.5 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. In addition, Southern Company estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million for 2011, $191 million to $670 million for 2012, and $476 million to $1.9 billion for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Southern Company estimates the potential investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants, including unit retirements and replacements, to meet new 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.

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 2011, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities.

Except as described below with respect to potential DOE loan guarantees, 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.

30

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In June 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 receipt of the combined construction and operating licenses for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.

In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees for Mississippi Power.

Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. 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, 2011, Southern Company and its subsidiaries had approximately $1.5 billion of cash and cash equivalents and approximately $5.13 billion of unused committed credit arrangements with banks, of which $96 million expire in 2011, $316 million expire in 2012, $60 million expire in 2013, $860 million expire in 2014, and $3.80 billion expire in 2016. Of the credit arrangements expiring on or before September 30, 2012, $41 million contain provisions allowing two-year term loans executable at expiration and $216 million contain provisions allowing one-year term loans executable at expiration. Subsequent to September 30, 2011, Alabama Power replaced a $20 million credit arrangement expiring in 2011 with a $30 million credit arrangement which will expire in 2014. At September 30, 2011, approximately $1.8 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. 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. 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. At September 30, 2011, the Southern Company system had approximately $132 million of short-term borrowings outstanding, comprised of commercial paper, with a weighted average interest rate of 0.27% per annum. During the third quarter 2011, Southern Company had an average of $510 million of short-term borrowings outstanding with a weighted average interest rate of 0.29% per annum and the maximum amount outstanding was $903 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” of Southern Company in Item 7 and Note 7 to the financial statements of Southern Company under “Operating Leases” in Item 8 of the Form 10-K for information relating to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel (Facility).

Mississippi Power was required to provide notice of its intent to either renew the lease or purchase the Facility by July 22, 2011. On July 20, 2011, Mississippi Power provided notice to the lessor of its intent to purchase the Facility. Mississippi Power’s right to purchase the Facility was approved by the Mississippi PSC in its order dated January 7, 1998, as amended on February 19, 1999, which granted Mississippi Power a Certificate of Public Convenience and Necessity for the Facility.

31

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On October 20, 2011, Mississippi Power purchased the Facility for approximately $85 million in cash and the assumption of debt obligations of the lessor related to the Facility, which mature in 2021, have a face value of $270 million and a fixed stated interest rate of 7.13%, and are secured by the Facility and certain personal property, accounts, and proceeds related thereto. Accounting rules require that the Facility be reflected on Southern Company’s financial statements at the time of the purchase at the fair value of the consideration rendered. Based on interest rates as of October 20, 2011, the fair value of the debt assumed was approximately $346 million. Accordingly, the Facility will be reflected in Southern Company’s financial statements at approximately $431 million. Mississippi Power intends to maintain its traditional capital structure by adding equity to support the additional debt.

In connection with the purchase of the Facility, Mississippi Power filed a request on July 25, 2011 for an accounting order from the Mississippi PSC. If the accounting order is approved as requested, the retail revenue requirements under the purchase option will be comparable to those otherwise required under operating lease accounting treatment for the extended lease term, with any differences deferred as a regulatory asset over the 10-year period ending October 2021. At the conclusion of the proposed deferral period in 2021, the unamortized deferral balance will be amortized into rates over the remaining life of the Facility. On November 2, 2011, Mississippi Power filed a request with the FERC seeking authorization to defer as a regulatory asset, for the 10-year period ending October 2021, the difference between the revenue requirement under the purchase of the Facility (assuming a remaining 30-year life) and the revenue requirement assuming the continuation of the operating lease regulatory treatment. At the conclusion of the proposed deferral period in 2021, the accumulated deferred balance will be amortized into wholesale rates over the remaining life of the Facility. The ultimate outcome of these matters cannot be determined at this time.

Credit Rating Risk

Southern Company 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 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. At September 30, 2011, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $606 million. At September 30, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.8 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

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

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

32

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

electricity prices, the traditional operating companies enter into physical fixed-price contracts or heat-rate contracts for the purchase and sale of electricity through the wholesale electricity market. 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 2011 when compared with the December 31, 2010 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, 2011 were as follows:

	Third Quarter			Year-to-Date
	2011			2011
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(136	)	$	(196	)
Contracts realized or settled		51			137
Current period changes(a)		(66	)		(92	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(151	)	$	(151	)

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

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2011 was a decrease of $15 million and an increase of $45 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At September 30, 2011, Southern Company had a net hedge volume of 160 million mmBtu with a weighted average contract cost approximately $1.10 per mmBtu above market prices, compared to 154 million mmBtu at June 30, 2011 with a weighted average contract cost approximately $0.97 per mmBtu above market prices and compared to 149 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.35 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses.

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

Asset (Liability) Derivatives	September 30, 2011			December 31, 2010
	(in millions)
Regulatory hedges	$	(147	)	$	(193	)
Cash flow hedges		—			(1	)
Not designated		(4	)		(2	)
Total fair value	$	(151	)	$	(196	)

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 used 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 income were $(1) million and $(2) million, respectively, for the three and nine months ended September 30, 2011 and will continue to be marked to market until the settlement date. For the three and nine months ended September 30, 2010, the total net unrealized pre-tax gains (losses) recognized in the statements of income were $(4) million and $(2) million, respectively.

33

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 and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:

				September 30, 2011
				Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(151	)		(117	)		(33	)		(1	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(151	)	$	(117	)	$	(33	)	$	(1	)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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 2011, Southern Company issued approximately 18.6 million shares of common stock for $620 million through the Southern Investment Plan and employee and director stock plans. The proceeds were primarily used for general corporate purposes, including the investment by Southern Company in its subsidiaries, and to repay short-term indebtedness. While Southern Company continues to issue additional equity through its employee and director equity compensation plans, Southern Company is not currently issuing additional shares of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by the independent plan administrators.

34

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following table outlines the debt financing activities for Southern Company, the traditional operating companies, and Southern Power for the first nine months of 2011:

			Senior Note		Pollution Control Bond		Pollution Control Bond		Other Long-		Other Long- Term Debt
	Senior Note		Redemptions		Issuances and		Redemptions		Term Debt		Redemptions
Company	Issuances		and Maturities		Remarketings(*)		and Maturities		Issuances		and Maturities
					(in millions)
Southern Company	$	500	$	—	$	—	$	—	$	—	$	—
Alabama Power		700		650		—		4		—		—
Georgia Power		550		277		604		286		250		509
Gulf Power		125		—		—		—		—		110
Mississippi Power		—		—		—		—		115		130
Southern Power		300		—		—		—		—		3
Total	$	2,175	$	927	$	604	$	290	$	365	$	752

(*) Includes the remarketing by Georgia Power of pollution control bonds that had been purchased and held by Georgia Power.

In August 2011, Southern Company issued $500 million aggregate principal amount of Series 2011A 1.95% Senior Notes due September 1, 2016. The net proceeds from the sale of the Series 2011A Senior Notes were used to repay 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 the redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their respective continuous construction programs.

In March 2011, Alabama Power settled $200 million of interest rate hedges related to its Series 2011A 5.50% Senior Note issuance at a gain of approximately $4 million. The gain will be amortized to interest expense, in earnings, over 10 years.

In August 2011, Alabama Power entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $300 million.

In September 2011, Mississippi Power entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swaps totaled $600 million.

Subsequent to September 30, 2011, Alabama Power announced the redemption that will occur on November 14, 2011 of approximately $100 million aggregate principal amount of its Series EE 5.75% Senior Notes due January 15, 2036.

Subsequent to September 30, 2011, Georgia Power announced the redemption that will occur on November 21, 2011 of $53 million aggregate principal amount of the Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Third Series 1999.

Subsequent to September 30, 2011, Mississippi Power issued $150 million aggregate principal amount of Series 2011A 2.35% Senior Notes due October 15, 2016 and $150 million aggregate principal amount of Series 2011B 4.75% Senior Notes due October 15, 2041. Mississippi Power also settled hedges totaling $150 million related to the Series 2011A issuance at a gain of approximately $1.4 million. This gain will be amortized to interest expense, in earnings, over five years. Mississippi Power settled hedges totaling $150 million related to the Series 2011B issuance at a loss of approximately $0.54 million. This loss will be amortized to interest expense, in earnings, over 10 years.

35

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to September 30, 2011, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 21, 2021, issued for the benefit of the lessor as described under “Off-Balance Sheet Financing Arrangements” herein. These bonds are secured by the Facility and certain personal property, accounts, and proceeds related thereto.

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.

36

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.

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

     (b) Changes in internal controls.

There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’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 2011 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

37

ALABAMA POWER COMPANY

38

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,489		$	1,527		$	3,859		$	3,925
Wholesale revenues, non-affiliates		80			86			218			395
Wholesale revenues, affiliates		52			43			202			194
Other revenues		50			50			152			149
Total operating revenues		1,671			1,706			4,431			4,663
Operating Expenses:
Fuel		512			500			1,335			1,455
Purchased power, non-affiliates		34			35			62			66
Purchased power, affiliates		49			57			152			161
Other operations and maintenance		309			379			896			997
Depreciation and amortization		160			153			476			451
Taxes other than income taxes		84			85			254			248
Total operating expenses		1,148			1,209			3,175			3,378
Operating Income		523			497			1,256			1,285
Other Income and (Expense):
Allowance for equity funds used during construction		7			9			18			29
Interest income		4			4			13			12
Interest expense, net of amounts capitalized		(73	)		(76	)		(224	)		(227	)
Other income (expense), net		(7	)		(7	)		(20	)		(18	)
Total other income and (expense)		(69	)		(70	)		(213	)		(204	)
Earnings Before Income Taxes		454			427			1,043			1,081
Income taxes		180			158			407			399
Net Income		274			269			636			682
Dividends on Preferred and Preference Stock		10			10			30			30
Net Income After Dividends on Preferred and Preference Stock	$	264		$	259		$	606		$	652

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2011			2010		2011			2010
	(in millions)						(in millions)
Net Income After Dividends on Preferred and Preference Stock	$	264		$	259	$	606		$	652
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(4), $-, $(3), and $-, respectively		(8	)		—		(5	)		—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $(1), and $-, respectively		—			—		(2	)		—
Total other comprehensive income (loss)		(8	)		—		(7	)		—
Comprehensive Income	$	256		$	259	$	599		$	652

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

39

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2011			2010
	(in millions)
Operating Activities:
Net income	$	636		$	682
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		562			519
Deferred income taxes		350			301
Allowance for equity funds used during construction		(18	)		(29	)
Pension, postretirement, and other employee benefits		(17	)		(9	)
Stock based compensation expense		5			4
Other, net		6			29
Changes in certain current assets and liabilities —
-Receivables		(74	)		(110	)
-Fossil fuel stock		75			21
-Materials and supplies		(13	)		(10	)
-Other current assets		(19	)		(34	)
-Accounts payable		(120	)		(66	)
-Accrued taxes		215			(48	)
-Accrued compensation		(35	)		8
-Other current liabilities		5			(103	)
Net cash provided from operating activities		1,558			1,155
Investing Activities:
Property additions		(694	)		(685	)
Distribution of restricted cash from pollution control revenue bonds		11			18
Nuclear decommissioning trust fund purchases		(301	)		(126	)
Nuclear decommissioning trust fund sales		301			126
Cost of removal, net of salvage		(52	)		(26	)
Change in construction payables		(13	)		(34	)
Other investing activities		14			(9	)
Net cash used for investing activities		(734	)		(736	)
Financing Activities:
Proceeds —
Capital contributions from parent company		10			19
Senior notes issuances		700			—
Redemptions —
Pollution control revenue bonds		(4	)		—
Senior notes		(650	)		—
Payment of preferred and preference stock dividends		(30	)		(30	)
Payment of common stock dividends		(415	)		(407	)
Other financing activities		(13	)		(1	)
Net cash used for financing activities		(402	)		(419	)
Net Change in Cash and Cash Equivalents		422			—
Cash and Cash Equivalents at Beginning of Period		154			368
Cash and Cash Equivalents at End of Period	$	576		$	368
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $7 and $11 capitalized for 2011 and 2010, respectively)	$	207		$	214
Income taxes (net of refunds)		(95	)		212
Noncash transactions — accrued property additions at end of period		15			39

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

40

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2011			2010
	(in millions)
Current Assets:
Cash and cash equivalents	$	576		$	154
Restricted cash and cash equivalents		3			18
Receivables —
Customer accounts receivable		419			362
Unbilled revenues		126			153
Under recovered regulatory clause revenues		11			5
Other accounts and notes receivable		48			35
Affiliated companies		47			57
Accumulated provision for uncollectible accounts		(10	)		(10	)
Fossil fuel stock, at average cost		316			391
Materials and supplies, at average cost		355			346
Vacation pay		55			55
Prepaid expenses		77			208
Other regulatory assets, current		33			38
Other current assets		11			10
Total current assets		2,067			1,822
Property, Plant, and Equipment:
In service		20,530			19,966
Less accumulated provision for depreciation		7,247			6,931
Plant in service, net of depreciation		13,283			13,035
Nuclear fuel, at amortized cost		316			283
Construction work in progress		485			547
Total property, plant, and equipment		14,084			13,865
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		62			64
Nuclear decommissioning trusts, at fair value		502			552
Miscellaneous property and investments		73			71
Total other property and investments		637			687
Deferred Charges and Other Assets:
Deferred charges related to income taxes		528			488
Prepaid pension costs		287			257
Deferred under recovered regulatory clause revenues		39			4
Other regulatory assets, deferred		680			675
Other deferred charges and assets		193			196
Total deferred charges and other assets		1,727			1,620
Total Assets	$	18,515		$	17,994

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

41

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2011			2010
	(in millions)
Current Liabilities:
Securities due within one year	$	—		$	200
Accounts payable —
Affiliated		195			210
Other		198			273
Customer deposits		85			86
Accrued taxes —
Accrued income taxes		13			2
Other accrued taxes		103			32
Accrued interest		71			63
Accrued vacation pay		45			45
Accrued compensation		73			99
Liabilities from risk management activities		24			31
Over recovered regulatory clause revenues		25			22
Other current liabilities		35			41
Total current liabilities		867			1,104
Long-term Debt		6,232			5,987
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,148			2,747
Deferred credits related to income taxes		81			85
Accumulated deferred investment tax credits		151			157
Employee benefit obligations		323			311
Asset retirement obligations		544			520
Other cost of removal obligations		702			701
Other regulatory liabilities, deferred		92			217
Other deferred credits and liabilities		92			87
Total deferred credits and other liabilities		5,133			4,825
Total Liabilities		12,232			11,916
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		2,177			2,156
Retained earnings		2,213			2,022
Accumulated other comprehensive loss		(14	)		(7	)
Total common stockholder’s equity		5,598			5,393
Total Liabilities and Stockholder’s Equity	$	18,515		$	17,994

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

42

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Alabama Power’s primary 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 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$5	1.9	$(46)	(7.1)

Alabama Power’s net income after dividends on preferred and preference stock for the third quarter 2011 was $264 million compared to $259 million for the corresponding period in 2010. Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2011 was $606 million compared to $652 million for the corresponding period in 2010. For the third quarter 2011, the increase in net income when compared to the corresponding period in 2010 was not material. The decrease for year-to-date 2011 when compared to the corresponding period in 2010 was primarily due to reductions in wholesale revenues from sales to non-affiliates, relatively cooler weather primarily in the month of September compared to the third quarter 2010, significantly colder weather in the first quarter 2010, an increase in depreciation and amortization, and a reduction in AFUDC equity. The decreases in income were partially offset by a decrease in other operations and maintenance expenses, an increase in revenues under Rate CNP Environmental associated with the completion of construction projects related to environmental projects, and an increase in industrial KWH sales.

Retail Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(38)	(2.5)	$(66)	(1.7)

In the third quarter 2011, retail revenues were $1.49 billion compared to $1.53 billion for the corresponding period in 2010. For year-to-date 2011, retail revenues were $3.86 billion compared to $3.93 billion for the corresponding period in 2010.

43

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues are as follows:

	Third Quarter						Year-to-Date
	2011						2011
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	1,527					$	3,925
Estimated change in –
Rates and pricing		3			0.2			49			1.2
Sales growth (decline)		19			1.2			23			0.6
Weather		(61	)		(4.0	)		(97	)		(2.5	)
Fuel and other cost recovery		1			0.1			(41	)		(1.0	)
Retail – current year	$	1,489			(2.5	)%	$	3,859			(1.7	)%

Revenues associated with changes in rates and pricing increased in the third quarter 2011 and year-to-date 2011, when compared to the corresponding periods in 2010, primarily due to increased revenues associated with Rate CNP Environmental. The increase was due to the completion of construction projects related to environmental mandates, although there was no increase in the Rate CNP Environmental billing factors in 2011.

Revenues attributable to changes in sales increased in the third quarter 2011 when compared to the corresponding period in 2010. Industrial KWH energy sales increased 3.1% due to an increase in demand resulting from changes in production levels primarily in the primary metals sector. Weather-adjusted residential and commercial KWH energy sales increased 1.3% and 1.2%, respectively, driven by an increase in demand.

Revenues attributable to changes in sales increased year-to-date 2011 when compared to the corresponding period in 2010. Industrial KWH energy sales increased 5.7% due to an increase in demand resulting from changes in production levels primarily in the chemical and primary metals sectors. The decreases in weather-adjusted residential and commercial KWH energy sales were not material.

Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010. In the third quarter 2011, residential and commercial sales revenues decreased 6.4% and 3.3%, respectively, as a result of relatively cooler weather primarily in the month of September compared to the third quarter 2010. For year-to-date 2011, residential and commercial sales revenues decreased 4.5% and 1.5%, respectively, as a result of relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010.

In the third quarter 2011, the increase in fuel and other cost recovery revenues when compared to the corresponding period in 2010 was not material. Fuel and other cost recovery revenues decreased year-to-date 2011 when compared to the corresponding period in 2010 primarily due to a decrease in fuel costs and a decrease in costs associated with PPAs certificated by the Alabama PSC. 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 impact net income.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

44

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(7.0)	$(177)	(44.8)

Wholesale revenues from non-affiliates will vary depending on the market prices of wholesale energy compared to the cost of Alabama Power and Southern Company system-owned generation, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.

In the third quarter 2011, wholesale revenues from non-affiliates were $80 million compared to $86 million for the corresponding period in 2010, reflecting a $9 million decrease in revenue from energy sales and a $3 million increase in capacity revenue. The decrease was primarily due to a 9.0% decrease in KWH sales, partially offset by a 2.4% increase in the price of energy.

For year-to-date 2011, wholesale revenues from non-affiliates were $218 million compared to $395 million for the corresponding period in 2010, reflecting a $101 million decrease in revenue from energy sales and a $76 million decrease in capacity revenue. The decrease was primarily due to a 51.3% decrease in KWH sales, partially offset by a 13.3% increase in the price of energy.

In May 2010, the long-term unit power sales contracts expired and the unit power energy sales and capacity revenues ceased. In the third quarter 2011, the revenue reduction when compared to the corresponding period in 2010 was not material. For year-to-date 2011, there was a $178 million revenue reduction when compared to the corresponding period in 2010. Beginning in June 2010, such capacity subject to the unit power sales contracts became available for retail service. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Operating Revenues” of Alabama Power in Item 7 of the Form 10-K for additional information.

Wholesale Revenues – Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$9	20.9	$8	4.1

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

In the third quarter 2011, wholesale revenues from affiliates were $52 million compared to $43 million for the corresponding period in 2010. The increase was primarily due to a 25.0% increase in KWH sales, partially offset by a 3.1% decrease in price.

For year-to-date 2011, the increase in wholesale revenues from affiliates when compared to the corresponding period in 2010 was not material.

45

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Third Quarter 2011						Year-to-Date 2011
	vs.						vs.
	Third Quarter 2010						Year-to-Date 2010
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel *	$	12			2.4		$	(120	)		(8.2	)
Purchased power – non-affiliates		(1	)		(2.9	)		(4	)		(6.1	)
Purchased power – affiliates		(8	)		(14.0	)		(9	)		(5.6	)
Total fuel and purchased power expenses	$	3					$	(133	)

* Fuel includes fuel purchased by Alabama Power for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.

In the third quarter 2011, the increase in total fuel and purchased power expenses when compared to the corresponding period in 2010 was not material.

For year-to-date 2011, total fuel and purchased power expenses were $1.55 billion compared to $1.68 billion for the corresponding period in 2010. The decrease was primarily due to a $78 million decrease related to lower KWHs generated as a result of relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010 and a $42 million decrease in the cost of fuel and the average cost of purchased power.

Fuel and purchased power transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Rate ECR. See FUTURE EARNINGS POTENTIAL – “Alabama PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

Details of Alabama Power’s cost of generation and purchased power are as follows:

	Third Quarter		Third Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2011		2010		Change			2011		2010		Change
	(cents per net KWH)							(cents per net KWH)
Fuel *		2.89		2.72		6.3			2.75		2.78		(1.1	)
Purchased power		6.97		7.11		(2.0	)		6.14		6.83		(10.1	)

* KWHs generated by hydro are excluded from the average cost of fuel.

In the third quarter 2011, the increase in fuel expense when compared to the corresponding period in 2010 was not material.

For year-to-date 2011, fuel expense was $1.34 billion compared to $1.46 billion for the corresponding period in 2010. The $120 million decrease was due to a 12.3% decrease in KWHs generated by coal and an 11.7% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements. The decreases were partially offset by a 5.4% increase in the average cost of coal.

Non-Affiliates

The decreases for the third quarter and year-to-date 2011 in purchased power expense from non-affiliates, when compared to the corresponding periods in 2010, were not material.

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

46

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Affiliates

In the third quarter 2011, purchased power expense from affiliates was $49 million compared to $57 million for the corresponding period in 2010. The decrease was related to a 14.8% decrease in the average cost per KWH.

For year-to-date 2011, purchased power expense from affiliates was $152 million compared to $161 million for the corresponding period in 2010. The decrease was related to a 25.5% decrease in the average cost per KWH, partially offset by a 12.1% increase in the amount of energy 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 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(70)	(18.5)	$(101)	(10.1)

In the third quarter 2011, other operations and maintenance expenses were $309 million compared to $379 million for the corresponding period in 2010. Distribution and transmission expenses decreased $57 million primarily due to an additional accrual of $40 million to the NDR in the third quarter 2010 and reductions in overhead line costs due to storm restoration efforts. See FUTURE EARNINGS POTENTIAL – “Alabama PSC Matters – Natural Disaster Reserve” herein for additional information. Administrative and general expenses decreased $5 million primarily related to decreases in injuries and damages expenses and affiliated service companies’ expenses. Nuclear production expenses decreased $5 million primarily due to a change to the nuclear maintenance outage accounting process associated with the routine refueling activities, as approved by the Alabama PSC in August 2010. As a result, no nuclear maintenance outage expenses will be recognized in 2011, reducing nuclear production expense by approximately $50 million as compared to 2010. 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. In addition, the decrease in nuclear production expenses was partially offset by an increase in operations costs related to increases in labor.

For year-to-date 2011, other operations and maintenance expenses were $896 million compared to $997 million for the corresponding period in 2010. Distribution and transmission expenses decreased $69 million primarily due to an additional accrual of $40 million to the NDR in 2010 and reductions in overhead line costs due to storm restoration efforts. See FUTURE EARNINGS POTENTIAL – “Alabama PSC Matters – Natural Disaster Reserve” herein for additional information. Administrative and general expenses decreased $17 million primarily related to decreases in injuries and damages expenses and affiliated service companies’ expenses. Nuclear production expenses decreased $16 million primarily due to a change to the nuclear maintenance outage accounting process, as discussed above, partially offset by an increase in operations costs related to increases in labor.

Depreciation and Amortization

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$7	4.6	$25	5.5

In the third quarter 2011, depreciation and amortization was $160 million compared to $153 million for the corresponding period in 2010. The increase was due to additions of property, plant, and equipment related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.

47

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2011, depreciation and amortization was $476 million compared to $451 million for the corresponding period in 2010. The increase was due to additions of property, plant, and equipment primarily related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.

Allowance for Equity Funds Used During Construction

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(22.2)	$(11)	(37.9)

In the third quarter 2011, the decrease in AFUDC equity when compared to the corresponding period in 2010 was not material.

For year-to-date 2011, AFUDC equity was $18 million compared to $29 million for the corresponding period in 2010. The decrease was primarily due to the completion of construction projects related to environmental mandates at Plants Barry, Gaston, and Miller.

Income Taxes

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$22	13.9	$8	2.0

In the third quarter 2011, income taxes were $180 million compared to $158 million for the corresponding period in 2010. The increase was primarily due to higher pre-tax earnings, an increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid, and prior year tax return actualization.

For year-to-date 2011, income taxes were $407 million compared to $399 million for the corresponding period in 2010. The increase was primarily due to an increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid, partially offset by 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, 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 area. Changes in economic conditions impact sales for Alabama Power and 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.

48

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. 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.

Alabama Power has completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. 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 proposed coal combustion byproducts rule. Although its analysis is preliminary, Alabama Power estimates that the aggregate capital costs for compliance with these rules could range from $5 billion to $7 billion through 2020 if the rules are adopted as proposed. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Alabama Power’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.

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 regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has appealed the decision to the U.S. Court of Appeals for the Eleventh Circuit. The ultimate outcome of this matter cannot be determined at this time.

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Alabama Power in Item 7 and Note 3 of the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.

49

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Alabama Power in Item 7 and Note 3 of the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies, including Alabama Power, and includes many of the same defendants that were involved in the earlier case. Alabama Power believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.

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 regulation of air quality.

On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Alabama Power’s facilities which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.

In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. On April 6, 2011, the EPA attempted to rescind its previous approval of the Alabama SIP revision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s attempted rescission pending judicial review. The EPA’s decision became effective May 6, 2011 and the court denied Alabama Power’s requested stay on May 12, 2011. Unless the court resolves Alabama Power’s appeal in its favor, the EPA’s rescission will continue to affect Alabama Power’s operations. The EPA’s rescission has affected unit availability

50

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

and increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.

On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. The State of Alabama is subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program and to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for the State of Alabama. The rule could have significant effects on Alabama Power, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including Alabama Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at many of Alabama Power’s existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Alabama Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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 June 8, 2011, Alabama Power filed an application with the FERC to relicense the Martin hydroelectric project located on the Tallapoosa River. The current license will expire in 2013. The ultimate outcome of this matter cannot be determined at this time.

51

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Alabama PSC Matters

Environmental Accounting Order

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 regarding environmental regulations. Proposed environmental regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions. On September 7, 2011, the Alabama PSC approved an order allowing for the establishment of a regulatory asset to record the unrecovered investment costs associated with any such decisions, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure. These costs would be amortized over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement.

Retail Rate Adjustments

See BUSINESS – “Rate Matters – Rate Structure and Cost Recovery Plans” of Alabama Power in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” and “PSC Matters – Natural Disaster Reserve” of Alabama Power in Item 7 of the Form 10-K for information regarding the rate structure of Alabama Power. On July 12, 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under Alabama Power’s rate structure effective with October 2011 billings. Alabama Power anticipates the elimination of this adjustment will result in additional revenues of approximately $30 million for the remainder of 2011 and is expected to have an annual effect of approximately $150 million beginning in 2012.

In accordance with the order, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues from the elimination of the tax-related adjustment to replenish the NDR, which was impacted as a result of operations and maintenance expenses incurred in connection with the April 2011 storms in Alabama. Alabama Power expects that the additional revenue in 2012 will preclude the need for a rate adjustment under Rate Stabilization and Equalization (Rate RSE). Accordingly, Alabama Power agreed to a moratorium on any increase in 2012 under Rate RSE.

Natural Disaster Reserve

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 under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for additional information.

During the first half of 2011, multiple storms caused varying degrees of damage to Alabama Power’s transmission and distribution facilities. The most significant storm occurred on April 27, 2011, causing over 400,000 of Alabama Power’s 1.4 million customers to be without electrical service. The estimated cost of repairing the damage to facilities and restoring electrical service to customers, as a result of these storms, is approximately $45 million for operations and maintenance expenses and approximately $163 million for capital-related expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.

At September 30, 2011, the NDR had an accumulated balance of $75 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.

52

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In accordance with the order discussed above that was issued by the Alabama PSC on July 12, 2011 to eliminate a tax-related adjustment under Alabama Power’s rate structure, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues, which are expected to be approximately $30 million.

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s under recovered fuel costs as of September 30, 2011 totaled $39 million as compared to $4 million at December 31, 2010. These under recovered fuel costs at September 30, 2011 are included in deferred under recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. This classification is based on an estimate which includes 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 recovery of the under recovered fuel costs.

Income Tax Matters

Legislation

On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 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 construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Alabama Power through 2013. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Alabama Power estimates the potential increased cash flow for 2011 to be between approximately $150 million and $200 million. The ultimate outcome of this matter cannot be determined at this time.

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 opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and

53

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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 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.

On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. The events in Japan have created uncertainties that may affect transportation of materials, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of existing nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. On July 12, 2011, a special NRC task force issued a report with initial recommendations for enhancing nuclear reactor safety in the U.S., including potential changes in emergency planning, onsite backup generation, and spent fuel pools for existing reactors. The final form and resulting impact of any changes to safety requirements for existing nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time.

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

See the Notes to the Condensed Financial Statements herein for 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, Unbilled Revenues, and Pension and Other Postretirement Benefits.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Alabama Power’s financial condition remained stable at September 30, 2011. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $1.56 billion for the first nine months of 2011, an increase of $403 million as compared to the first nine months of 2010. The increase in cash provided from operating activities was primarily due to accrued taxes and deferred income taxes related to benefits associated with bonus depreciation and other current liabilities. This increase was partially offset by decreases in accounts payable and net income. Net cash used for investing activities totaled $734 million for the first nine months of 2011 primarily due to gross property additions related to steam and nuclear generation equipment, nuclear fuel, transmission, and distribution expenditures. Net cash used for financing activities totaled $402 million for the first nine months of 2011 primarily due to issuances, redemptions, and a maturity of

54

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

senior notes and payment of common stock dividends. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2011 include increases in cash and cash equivalents and accumulated deferred income taxes of $422 million and $401 million, respectively, related to additional bonus depreciation, $219 million in property, plant, and equipment associated with routine property additions and nuclear fuel, and $191 million in retained earnings, partially offset by decreases of $131 million in prepaid expenses related to income taxes and $125 million in other regulatory liabilities, deferred.

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, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. There are no requirements through September 30, 2012 to fund maturities of long-term debt.

As of September 30, 2011, the approved construction program of Alabama Power included a base level investment of $0.9 billion for 2011, $0.9 billion for 2012, and $1.1 billion for 2013. Included in Alabama Power’s approved construction program are estimated environmental expenditures to comply with existing statutes and regulations of $47 million, $26 million, and $53 million for 2011, 2012, and 2013, respectively. Alabama Power anticipates that additional expenditures may be required to comply with anticipated statutes and regulations. Such additional expenditures are estimated to be in amounts up to $48 million, $108 million, and $354 million for 2011, 2012, and 2013, respectively. If the EPA’s proposed Utility MACT rule is finalized as proposed, Alabama Power estimates that the potential incremental investments for new environmental regulations may exceed these estimates. 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; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; 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 utilized in the past. Alabama Power has primarily utilized funds from operating cash flows, unsecured debt, common stock, preferred stock, and preference stock. 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. To meet short-term cash needs and contingencies, Alabama Power had at September 30, 2011 cash and cash equivalents of approximately $576 million and unused committed credit arrangements with banks of approximately $1.3 billion. Of the unused credit arrangements, $60 million expire in 2011, $121 million expire in 2012, $35 million expire in 2013, $280 million expire in 2014, and $800 million expire in 2016. Of the credit arrangements expiring on or before September 30, 2012, $111 million contain provisions allowing for one-year term loans executable at expiration. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Alabama

55

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Power’s commercial paper borrowings and $794 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Subsequent to September 30, 2011, Alabama Power replaced a $20 million credit arrangement expiring in 2011 with a $30 million credit arrangement which will expire in 2014. 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. 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 other Southern Company subsidiaries. At September 30, 2011, Alabama Power had no commercial paper borrowings outstanding. During the third quarter 2011, Alabama Power had an average of $1 million of commercial paper outstanding at a weighted average interest rate of 0.10% per annum and the maximum amount outstanding was $25 million. 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

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, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $311 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Alabama Power’s market risk exposure relative to interest rate changes for the third quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness remains 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. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power had no material change in market risk exposure for the third quarter 2011 when compared with the December 31, 2010 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, 2011 were as follows:

	Third Quarter			Year-to-Date
	2011			2011
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(24	)	$	(38	)
Contracts realized or settled		9			29
Current period changes(a)		(14	)		(20	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(29	)	$	(29	)

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

56

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2011 was a decrease of $5 million and an increase of $9 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At September 30, 2011, Alabama Power had a net hedge volume of 31 million mmBtu with a weighted average contract cost approximately $1.04 per mmBtu above market prices, compared to 31 million mmBtu at June 30, 2011 with a weighted average contract cost approximately $0.79 per mmBtu above market prices and compared to 34 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.14 per mmBtu above market prices.

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 the fuel cost recovery clause.

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2011 and 2010 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 and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:

				September 30, 2011
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(29	)		(24	)		(5	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(29	)	$	(24	)	$	(5	)	$	—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Alabama Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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” 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

In February 2011, Alabama Power’s $200 million Series HH 5.10% Senior Notes due February 1, 2011 matured.

In March 2011, Alabama Power issued $250 million aggregate principal amount of Series 2011A 5.50% Senior Notes due March 15, 2041. The proceeds were used for general corporate purposes, including Alabama Power’s continuous construction program. Alabama Power settled $200 million of interest rate hedges related to its Series 2011A 5.50% Senior Note issuance at a gain of approximately $4 million. The gain will be amortized to interest expense, in earnings, over 10 years.

57

ALABAMA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In May 2011, Alabama Power issued $200 million aggregate principal amount of Series 2011B 3.950% Senior Notes due June 1, 2021 and $250 million aggregate principal amount of Series 2011C 5.200% Senior Notes due June 1, 2041. The net proceeds were used by Alabama Power for the redemption of $100 million aggregate principal amount of the Series GG 5 7/8% Senior Notes due February 1, 2046, $200 million aggregate principal amount of the Series II 5.875% Senior Notes due March 15, 2046, and $150 million aggregate principal amount of the Series JJ 6.375% Senior Notes due June 15, 2046.

In August 2011, Alabama Power entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $300 million.

In September 2011, Alabama Power redeemed approximately $4 million of The Industrial Development Board of the Town of Wilsonville, Alabama Solid Waste Disposal Revenue Bonds (Alabama Power Company Plant Gaston), Series 2008.

Subsequent to September 30, 2011, Alabama Power announced the redemption that will occur on November 14, 2011 of approximately $100 million aggregate principal amount of its Series EE 5.75% Senior Notes due January 15, 2036.

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.

58

GEORGIA POWER COMPANY

59

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	2,609		$	2,418		$	6,494		$	6,036
Wholesale revenues, non-affiliates		90			109			270			307
Wholesale revenues, affiliates		4			17			31			43
Other revenues		85			84			247			226
Total operating revenues		2,788			2,628			7,042			6,612
Operating Expenses:
Fuel		838			928			2,299			2,443
Purchased power, non-affiliates		127			128			297			294
Purchased power, affiliates		193			143			513			437
Other operations and maintenance		453			435			1,294			1,224
Depreciation and amortization		180			182			531			426
Taxes other than income taxes		102			98			283			264
Total operating expenses		1,893			1,914			5,217			5,088
Operating Income		895			714			1,825			1,524
Other Income and (Expense):
Allowance for equity funds used during construction		26			34			73			105
Interest expense, net of amounts capitalized		(90	)		(95	)		(257	)		(275	)
Other income (expense), net		(4	)		(5	)		(10	)		(12	)
Total other income and (expense)		(68	)		(66	)		(194	)		(182	)
Earnings Before Income Taxes		827			648			1,631			1,342
Income taxes		303			224			583			433
Net Income		524			424			1,048			909
Dividends on Preferred and Preference Stock		4			4			13			13
Net Income After Dividends on Preferred and Preference Stock	$	520		$	420		$	1,035		$	896

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2011		2010		2011		2010
	(in millions)				(in millions)
Net Income After Dividends on Preferred and Preference Stock	$	520	$	420	$	1,035	$	896
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $1, and $5, respectively		1		2		2		8
Comprehensive Income	$	521	$	422	$	1,037	$	904

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

60

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2011			2010
	(in millions)
Operating Activities:
Net income	$	1,048		$	909
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		646			551
Deferred income taxes		422			225
Deferred revenues		—			(77	)
Deferred expenses		(30	)		(54	)
Allowance for equity funds used during construction		(73	)		(105	)
Pension, postretirement, and other employee benefits		2			20
Stock based compensation expense		7			5
Other, net		(47	)		(10	)
Changes in certain current assets and liabilities —
-Receivables		(68	)		(126	)
-Fossil fuel stock		115			153
-Prepaid income taxes		81			2
-Other current assets		(2	)		4
-Accounts payable		(46	)		61
-Accrued taxes		(1	)		66
-Accrued compensation		(18	)		45
-Other current liabilities		43			38
Net cash provided from operating activities		2,079			1,707
Investing Activities:
Property additions		(1,363	)		(1,628	)
Nuclear decommissioning trust fund purchases		(1,645	)		(570	)
Nuclear decommissioning trust fund sales		1,641			546
Cost of removal, net of salvage		(21	)		(46	)
Change in construction payables, net of joint owner portion		108			27
Other investing activities		(9	)		5
Net cash used for investing activities		(1,289	)		(1,666	)
Financing Activities:
Decrease in notes payable, net		(575	)		(321	)
Proceeds —
Capital contributions from parent company		199			681
Pollution control revenue bonds issuances		604			—
Senior notes issuances		550			1,950
Other long-term debt issuances		250			—
Redemptions —
Pollution control revenue bonds		(286	)		—
Senior notes		(277	)		(1,112	)
Other long-term debt		(509	)		(3	)
Payment of preferred and preference stock dividends		(13	)		(13	)
Payment of common stock dividends		(672	)		(615	)
Other financing activities		(3	)		(32	)
Net cash provided from (used for) financing activities		(732	)		535
Net Change in Cash and Cash Equivalents		58			576
Cash and Cash Equivalents at Beginning of Period		8			14
Cash and Cash Equivalents at End of Period	$	66		$	590
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $27 and $39 capitalized for 2011 and 2010, respectively)	$	240		$	231
Income taxes (net of refunds)		(2	)		107
Noncash transactions — accrued property additions at end of period		375			261

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

61

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2011			2010
	(in millions)
Current Assets:
Cash and cash equivalents	$	66		$	8
Receivables —
Customer accounts receivable		764			580
Unbilled revenues		235			172
Under recovered regulatory clause revenues		189			184
Joint owner accounts receivable		52			60
Other accounts and notes receivable		58			67
Affiliated companies		28			21
Accumulated provision for uncollectible accounts		(17	)		(11	)
Fossil fuel stock, at average cost		509			624
Materials and supplies, at average cost		379			371
Vacation pay		77			78
Prepaid income taxes		1			99
Other regulatory assets, current		94			105
Other current assets		144			80
Total current assets		2,579			2,438
Property, Plant, and Equipment:
In service		26,918			26,397
Less accumulated provision for depreciation		10,198			9,966
Plant in service, net of depreciation		16,720			16,431
Other utility plant, net		57			—
Nuclear fuel, at amortized cost		427			386
Construction work in progress		3,774			3,287
Total property, plant, and equipment		20,978			20,104
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		63			70
Nuclear decommissioning trusts, at fair value		657			818
Miscellaneous property and investments		39			42
Total other property and investments		759			930
Deferred Charges and Other Assets:
Deferred charges related to income taxes		747			723
Prepaid pension costs		122			91
Deferred under recovered regulatory clause revenues		25			214
Other regulatory assets, deferred		1,282			1,207
Other deferred charges and assets		213			207
Total deferred charges and other assets		2,389			2,442
Total Assets	$	26,705		$	25,914

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

62

GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2011			2010
	(in millions)
Current Liabilities:
Securities due within one year	$	254		$	415
Notes payable		1			576
Accounts payable —
Affiliated		328			243
Other		580			574
Customer deposits		206			198
Accrued taxes —
Accrued income taxes		105			1
Unrecognized tax benefits		9			187
Other accrued taxes		252			328
Accrued interest		117			94
Accrued vacation pay		56			58
Accrued compensation		100			109
Liabilities from risk management activities		53			77
Other cost of removal obligations, current		31			31
Nuclear decommissioning trust securities lending collateral		37			144
Other current liabilities		162			134
Total current liabilities		2,291			3,169
Long-term Debt		8,422			7,931
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		4,256			3,718
Deferred credits related to income taxes		124			129
Accumulated deferred investment tax credits		222			229
Employee benefit obligations		716			684
Asset retirement obligations		729			705
Other cost of removal obligations		123			131
Other deferred credits and liabilities		237			211
Total deferred credits and other liabilities		6,407			5,807
Total Liabilities		17,120			16,907
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		5,504			5,291
Retained earnings		3,426			3,063
Accumulated other comprehensive loss		(9	)		(11	)
Total common stockholder’s equity		9,319			8,741
Total Liabilities and Stockholder’s Equity	$	26,705		$	25,914

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

63

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010

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 rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. Georgia Power is currently constructing two new nuclear and three new combined cycle generating units. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.

On May 24, 2011, the Georgia PSC approved Georgia Power’s request to decrease fuel rates by 0.61%. The decrease reduced Georgia Power’s annual billings by approximately $43 million effective June 1, 2011. However, this has no impact on earnings as fuel cost recovery revenues generally equal fuel expenses.

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.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$100	23.8	$139	15.5

Georgia Power’s net income after dividends on preferred and preference stock for the third quarter 2011 was $520 million compared to $420 million for the corresponding period in 2010. Georgia Power’s year-to-date 2011 net income after dividends on preferred and preference stock was $1.04 billion compared to $896 million for the corresponding period in 2010. The increases were primarily due to increases in retail base revenues as authorized under the 2010 ARP and the NCCR tariff, which both became effective January 1, 2011, partially offset by relatively cooler weather primarily in the month of September compared to the third quarter 2010, higher non-fuel operating expenses, and higher income taxes. The year-to-date increase was also due to a reduction in interest expense arising from the settlement of tax litigation with the Georgia Department of Revenue (DOR), partially offset by a decrease in the amortization of the regulatory liability related to other cost of removal obligations.

Retail Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$191	7.9	$458	7.6

In the third quarter 2011, retail revenues were $2.61 billion compared to $2.42 billion for the corresponding period in 2010. For year-to-date 2011, retail revenues were $6.49 billion compared to $6.04 billion for the corresponding period in 2010.

64

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues are as follows:

	Third Quarter						Year-to-Date
	2011						2011
	(in millions)			(% change)			(in millions)			(% change)
Retail — prior year	$	2,418					$	6,036
Estimated change in —
Rates and pricing		225			9.3			546			9.0
Sales growth (decline)		(11	)		(0.4	)		(7	)		(0.1	)
Weather		(26	)		(1.1	)		(55	)		(0.9	)
Fuel cost recovery		3			0.1			(26	)		(0.4	)
Retail – current year	$	2,609			7.9	%	$	6,494			7.6	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 due to increases in retail base revenues as authorized under the 2010 ARP and the NCCR tariff, which both became effective January 1, 2011.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010. Weather-adjusted residential KWH sales decreased 1.3%, weather-adjusted commercial KWH sales increased 0.1%, and weather-adjusted industrial KWH sales were flat in the third quarter 2011 when compared to the corresponding period in 2010. Weather-adjusted residential and commercial KWH sales each decreased 0.3% and weather-adjusted industrial KWH sales increased 1.8% year-to-date 2011 when compared to the corresponding period in 2010. Increased demand in the primary metals sector was the main contributor to the increase in weather-adjusted industrial KWH sales for year-to-date 2011.

Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 due to relatively cooler weather primarily in the month of September compared to the third quarter 2010 and significantly colder weather in the first quarter 2010.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $3 million in the third quarter 2011 when compared to the corresponding period in 2010 due to higher KWHs purchased, partially offset by lower KWHs generated. Retail fuel cost recovery revenues decreased $26 million for year-to-date 2011 when compared to the corresponding period in 2010 due to the lower cost of purchased power per KWH purchased and lower KWHs generated. See Note (B) to the Condensed Financial Statements under “Retail Regulatory Matters – Fuel Cost Recovery” herein for additional information.

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 fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(19)	(17.4)	$(37)	(12.1)

Wholesale revenues from non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power and Southern Company system-owned generation, demand for energy within the Southern Company system service territory, and the availability of Southern Company system generation.

65

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the third quarter 2011, wholesale revenues from non-affiliates were $90 million compared to $109 million for the corresponding period in 2010, reflecting a $24 million decrease in energy revenues, partially offset by a $5 million increase in capacity revenues. The decrease in the third quarter 2011 was primarily due to a 31.7% decrease in KWH sales from lower demand as a result of less favorable weather in the third quarter 2011 and current economic conditions.

For year-to-date 2011, wholesale revenues from non-affiliates were $270 million compared to $307 million for the corresponding period in 2010. The decrease was primarily due to a $38 million decrease in energy revenues, slightly offset by an increase in capacity revenues. The decrease in year-to-date 2011 was primarily due to a 19.8% decrease in KWH sales from lower demand resulting from more favorable weather in the first quarter 2010, lower market costs of available energy compared to Georgia Power-owned generation, and the expiration of a long-term unit power sales contract in May 2010.

Wholesale Revenues — Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(76.5)	$(12)	(27.9)

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

In the third quarter 2011, wholesale revenues from affiliates were $4 million compared to $17 million for the corresponding period in 2010. For year-to-date 2011, wholesale revenues from affiliates were $31 million compared to $43 million for the corresponding period in 2010. These decreases were due to an 80.8% decrease and a 26.2% decrease in KWH sales due to lower demand in the third quarter and year-to-date 2011, respectively, primarily because the market cost of available energy was lower than the cost of Georgia Power-owned generation.

Other Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$1	1.2	$21	9.3

In the third quarter 2011, other revenues were $85 million compared to $84 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material. For year-to-date 2011, other revenues were $247 million compared to $226 million for the corresponding period in 2010. The increase was primarily due to a $21 million increase in transmission revenues as a result of new contracts that replaced the transmission component of a unit power sales contract that expired in May 2010 and increased usage of Georgia Power’s transmission system by non-affiliate companies.

66

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Third Quarter 2011						Year-to-Date 2011
	vs.						vs.
	Third Quarter 2010						Year-to-Date 2010
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	(90	)		(9.7	)	$	(144	)		(5.9	)
Purchased power — non-affiliates		(1	)		(0.8	)		3			1.0
Purchased power — affiliates		50			35.0			76			17.4
Total fuel and purchased power expenses	$	(41	)				$	(65	)

* Fuel includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.

In the third quarter 2011, total fuel and purchased power expenses were $1.16 billion compared to $1.20 billion for the corresponding period in 2010. The decrease was primarily due to a 5.6% decrease in total KWHs generated and purchased to meet demand, partially offset by a 0.4% increase in the average cost of fuel and purchased power.

For year-to-date 2011, total fuel and purchased power expenses were $3.11 billion compared to $3.17 billion for the corresponding period in 2010. The decrease was primarily due to a 3.6% decrease in total KWHs generated and purchased primarily due to lower customer demand as a result of significantly colder weather in the first quarter 2010 and a 0.7% decrease in the average cost of fuel and purchased power.

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

Details of Georgia Power’s cost of generation and purchased power are as follows:

	Third Quarter		Third Quarter		Percent		Year-to-Date		Year-to-Date		Percent
Average Cost	2011		2010		Change		2011		2010		Change
	(cents per net KWH)						(cents per net KWH)
Fuel		3.99		3.97		0.5		3.90		3.84		1.6
Purchased power		5.51		5.50		0.2		5.61		5.90		(4.9	)

In the third quarter 2011, fuel expense was $838 million compared to $928 million for the corresponding period in 2010. This decrease was due to a 12.2% decrease in KWHs generated, partially offset by a 0.5% increase in the average cost of fuel per KWH generated. The decrease in KWHs generated and the increase in cost are primarily due to lower customer demand and increased global demand for coal as well as an increase in the price of nuclear fuel.

For year-to-date 2011, fuel expense was $2.30 billion compared to $2.44 billion for the corresponding period in 2010. The decrease was primarily due to a 9.8% decrease in KWHs generated, partially offset by a 1.6% increase in the average cost of fuel per KWH generated. The decrease in KWHs generated and the increase in cost are primarily the result of higher prices as described above.

Affiliates

In the third quarter 2011, purchased power expense from affiliates was $193 million compared to $143 million for the corresponding period in 2010. The increase was due to a 17.1% increase in the volume of KWHs purchased, as system resources dispatched at lower cost than Georgia Power units and a 7.4% increase in the average cost per KWH purchased, reflecting a higher level of purchases during peaking hours in 2011.

67

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2011, purchased power expense from affiliates was $513 million compared to $437 million in the corresponding period in 2010. The increase was due to a 23.8% increase in the volume of KWHs purchased, primarily as the result of a new PPA that began in June 2010, partially offset by a 5.5% decrease in the average cost per KWH purchased, reflecting lower gas prices.

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

Other Operations and Maintenance Expenses

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$18	4.1	$70	5.7

In the third quarter 2011, other operations and maintenance expenses were $453 million compared to $435 million for the corresponding period in 2010. The increase was primarily due to a $5 million increase in distribution maintenance expense, a $6 million increase in customer assistance expense related to new demand side management programs in 2011, and a $2 million increase in uncollectible account expense as a result of higher revenues and the current economic conditions.

For year-to-date 2011, other operations and maintenance expenses were $1.29 billion compared to $1.22 billion for the corresponding period in 2010. The increase was primarily due to a $23 million increase in scheduled outages and maintenance for generating units, a $10 million increase in overhead line maintenance, an $8 million increase in customer assistance expense related to new demand side management programs in 2011, and a $6 million increase in uncollectible account expense as a result of higher revenues and the current economic conditions.

Depreciation and Amortization

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(1.1)	$105	24.6

In the third quarter 2011, depreciation and amortization was $180 million compared to $182 million for the corresponding period in 2010. The decrease when compared to the corresponding period in 2010 was not material.

For year-to-date 2011, depreciation and amortization was $531 million compared to $426 million for the corresponding period in 2010. The increase was primarily due to a $94 million decrease in the amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC. See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters — Rate Plans” in Item 8 of the Form 10-K for additional information on the other cost of removal regulatory liability.

Taxes Other Than Income Taxes

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$4	4.1	$19	7.2

In the third quarter 2011, taxes other than income taxes were $102 million compared to $98 million for the corresponding period in 2010. The increase when compared to the corresponding period in 2010 was not material.

For year-to-date 2011, taxes other than income taxes were $283 million compared to $264 million for the corresponding period in 2010. The increase was due to a $10 million increase in property taxes and an $8 million increase in franchise fees related to higher operating revenues.

68

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(23.5)	$(32)	(30.5)

In the third quarter 2011, AFUDC equity was $26 million compared to $34 million for the corresponding period in 2010. For year-to-date 2011, AFUDC equity was $73 million compared to $105 million for the corresponding period in 2010. The decreases were primarily due to the inclusion of Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011, which reduced the amount of AFUDC capitalized. See Note 3 to the financial statements of Georgia Power under “Construction – Nuclear” in Item 8 of the Form 10-K, Note (B) to the Condensed Financial Statements herein under “State PSC Matters – Georgia Power – Nuclear Construction,” and FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” herein for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(5.3)	$(18)	(6.5)

In the third quarter 2011, interest expense, net of amounts capitalized was $90 million compared to $95 million for the corresponding period in 2010. The decrease in third quarter 2011 compared to the corresponding period in 2010 was primarily due to lower interest expense on variable rate pollution control bonds. For year-to-date 2011, interest expense, net of amounts capitalized was $257 million compared to $275 million for the corresponding period in 2010. The decrease was primarily due to a reduction of $23 million in interest expense related to the settlement of tax litigation with the Georgia DOR, partially offset by a reduction in interest capitalized due to the inclusion of Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011, as described above. See FUTURE EARNINGS POTENTIAL – “Income Tax Matters” herein, Notes 3 and 5 to the financial statements of Georgia Power under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, in Item 8 of the Form 10-K, and Note (G) herein for additional information.

Income Taxes

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$79	35.3	$150	34.6

In the third quarter 2011, income taxes were $303 million compared to $224 million for the corresponding period in 2010. The increase in income taxes was primarily due to higher pre-tax earnings and a decrease in non-taxable AFUDC equity, as described previously.

For year-to-date 2011, income taxes were $583 million compared to $433 million for the corresponding period in 2010. The increase in income taxes was primarily due to higher pre-tax earnings, the recognition in the first quarter 2010 of certain state income tax credits, and a decrease in non-taxable AFUDC equity.

69

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power’s future earnings potential. The level of Georgia Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include Georgia Power’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. 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 area. Changes in economic conditions impact sales for Georgia Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. 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.

Georgia Power has completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. 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 proposed coal combustion byproducts rule. Although its analysis is preliminary, Georgia Power estimates that the aggregate capital costs for compliance with these rules could range from $5 billion to $7 billion through 2020 if the rules are adopted as proposed. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Georgia Power’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Georgia Power in Item 7 and Note 3 of the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.

70

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Georgia Power in Item 7 and Note 3 of the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies, including Georgia Power, and includes many of the same defendants that were involved in the earlier case. Georgia Power believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.

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 regulation of air quality.

On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Georgia Power’s facilities which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.

In April 2010, the EPA proposed an Industrial Boiler MACT rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA published the final rule on March 21, 2011 and, at the same time, issued a notice of intent to reconsider the final rule to allow for additional public review and comment. The EPA has announced plans to finalize the rule by April 30, 2012. The effect of the regulatory proceedings will depend on the final form of the revised regulations and the outcome of any legal challenges and cannot be determined at this time. On October 18, 2011, the Georgia PSC approved Georgia Power’s request to further delay the decision to convert Plant Mitchell Unit 3 from coal to biomass for two to four years, until there is greater clarity regarding the Industrial Boiler MACT rule and other proposed and recently adopted regulations. Georgia Power will file semi-annual construction monitoring reports on March 1 and August 15 throughout the delay period.

71

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On June 23, 2011, the EPA published its determination that the 20-county area within metropolitan Atlanta has air quality which attains the 1997 eight-hour ozone air quality standard. In March 2008, the EPA adopted a more stringent eight-hour ozone air quality standard, which it began to implement in September 2011. The 2008 standard is expected to result in designation of new nonattainment areas within Georgia Power’s service territory and could result in additional required reductions in nitrogen oxide emissions. The ultimate outcome of this matter cannot be determined at this time.

On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. The State of Georgia is subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program and to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for the State of Georgia. Georgia Power may need to purchase allowances to demonstrate compliance with the CSAPR. The rule could have significant effects on Georgia Power, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including Georgia Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.

On March 22, 2011, the Board of the Georgia Department of Natural Resources began consideration of modifications to the Georgia Multi-Pollutant Rule, which is designed to reduce emissions of mercury, sulfur dioxide, and nitrogen oxides statewide. On June 29, 2011, the modifications were approved and the compliance dates for certain of Georgia Power’s coal-fired generating units were changed as follows:

Branch 1	December 31, 2013
Branch 2	October 1, 2013
Branch 3	October 1, 2015
Branch 4	December 31, 2015

See “Georgia PSC Matters – 2011 Integrated Resource Plan Update” herein for additional information.

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 regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at

72

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

many of Georgia Power’s existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Georgia Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

Georgia 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, 2011, Georgia Power had a total under recovered fuel cost balance of approximately $214 million compared to $398 million at December 31, 2010.

On May 24, 2011, the Georgia PSC approved Georgia Power’s request to decrease fuel rates by 0.61%. The decrease reduced Georgia Power’s annual billings by approximately $43 million effective June 1, 2011. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.

2011 Integrated Resource Plan Update

See “Environmental Matters – Air Quality” and “– Water Quality” herein and BUSINESS – “Rate Matters – Integrated Resource Planning” of Georgia Power in Item 1, 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” in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility MACT rule for coal- and oil-fired EGUs, 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; and the 2010 ARP.

On August 4, 2011, Georgia Power filed an update to its IRP (2011 IRP Update). The filing included Georgia Power’s application to decertify Plant Branch Units 1 and 2 as of December 31, 2013 and October 1, 2013, the compliance dates for the respective units under the Georgia Multi-Pollutant Rule. However, as a result of the considerable uncertainty regarding pending state and federal environmental regulations, Georgia Power is continuing to defer decisions to add controls, switch fuel, or retire its remaining fossil generating units where environmental controls have not yet been installed, representing approximately 2,600 MWs of capacity. Georgia Power expects to update its economic analysis of these units once the Utility MACT rule is finalized. Georgia Power currently expects that certain units, representing approximately 600 MWs of capacity, are more likely than others to switch fuel or be controlled in time to comply with the Utility MACT rule. However, even if the updated economic analysis shows more positive benefits associated with adding controls or switching fuel for more units, it is unlikely that all of the required controls could be completed by 2015, the expected effective date of the Utility MACT rule. As a result, Georgia Power currently cannot rely on the availability of approximately 2,000 MWs of capacity in 2015. As such, the 2011 IRP Update also includes Georgia Power’s application requesting that the Georgia PSC certify the purchase of a total of 1,562 MWs of capacity beginning in 2015, from four PPAs selected through the 2015 request for proposal process.

73

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets resulting from new or revised environmental regulations through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. In connection with the retirement decision, Georgia Power reclassified the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net. Georgia Power is continuing to depreciate these units using the current composite straight-line rates previously approved by the Georgia PSC and upon actual retirement has requested that the Georgia PSC approve the continued deferral and amortization of the units’ remaining net carrying value. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Georgia Power’s financial statements.

The Georgia PSC is expected to vote on these requests in March 2012. The ultimate outcome of these matters cannot be determined at this time.

Storm Damage Recovery

During April 2011, severe storms in Georgia caused significant damage to Georgia Power’s distribution and transmission facilities. Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2011, the balance in the regulatory asset related to storm damage was $45 million. As a result of this regulatory treatment, the costs related to the storms are not expected to have a material impact on Georgia Power’s financial statements. See Note 1 to the financial statements of Georgia Power under “Storm Damage Reserve” in Item 8 of the Form 10-K for additional information.

Income Tax Matters

Legislation

On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On June 10, 2011, Georgia Power and the Georgia DOR agreed to a settlement resolving the claims. As a result, Georgia Power recorded additional tax benefits of approximately $64 million and, in accordance with the 2010 ARP, also recorded a related regulatory liability of approximately $62 million. In addition, Georgia Power recorded a reduction of approximately $23 million in related interest expense. See Notes 3 and 5 to the financial statements of Georgia Power in Item 8 of the Form 10-K under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, for additional information.

74

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 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 construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Georgia Power through 2013. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Georgia Power estimates the potential increased cash flow for 2011 to be between approximately $275 million and $350 million. The ultimate outcome of this matter cannot be determined at this time.

Construction

Nuclear

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” of Georgia Power in Item 7 of the Form 10-K for information regarding the construction of Plant Vogtle Units 3 and 4, which are expected to attain commercial operation in 2016 and 2017, respectively.

In December 2010, Westinghouse submitted a revision to the supporting documents for the AP1000 Design Certification Amendment (DCA) to the NRC. On January 24, 2011, the Advisory Committee on Reactor Safeguards endorsed the issuance of the Construction and Operating Licenses (COLs) for Plant Vogtle Units 3 and 4. In addition, on March 25, 2011, the NRC submitted to the EPA the final environmental impact statement for Plant Vogtle Units 3 and 4. On September 27 and 28, 2011, the NRC held the mandatory hearing for the COLs and Georgia Power’s request for a second limited work authorization. On October 18, 2011, the Atomic Safety and Licensing Board (ASLB) denied the remaining motions seeking to re-open the Plant Vogtle Units 3 and 4 licensing proceeding; however, on October 27, 2011, the petitioners requested reconsideration of this decision and, on November 2, 2011, further appealed to the NRC to admit their contentions, should they again be denied by the ASLB. The remaining steps in the regulatory process are to address the status of these petitions and to obtain the NRC approvals of the DCA and the COLs, which Georgia Power expects in late 2011. Issuance of the COLs by the NRC staff generally would be expected to occur within 10 days after the NRC’s decision. However, due to certain administrative procedural requirements, it is possible that the effective date of the DCA and issuance of the COLs could occur in early 2012. In this case, the NRC could approve Georgia Power’s request for a second limited work authorization, which would allow Georgia Power to perform additional construction activities related to the nuclear island in late 2011.

In connection with its certification of Plant Vogtle Units 3 and 4, the Georgia PSC ordered Georgia Power and the Georgia PSC Public Interest Advocacy Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize Georgia Power’s earnings if and when overruns are due to mandates from governing agencies. In May 2011, the Georgia PSC initiated a separate proceeding to address the issue. On August 2, 2011, the Georgia PSC voted to approve a settlement agreement between Georgia Power and the Georgia PSC Public Interest Advocacy Staff whereby the proposed risk sharing mechanisms were withdrawn. On August 16, 2011, the Georgia PSC voted to approve Georgia Power’s fourth semi-annual construction monitoring report including total costs of $1.3 billion for Plant Vogtle Units 3 and 4 incurred through December 31, 2010. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

In December 2010, the Georgia PSC approved the NCCR tariff, which became effective January 1, 2011. The NCCR tariff was established to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period in accordance with the Georgia Nuclear Energy Financing Act. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected

75

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. 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, 2011, approximately $78 million of these 2009 and 2010 costs were included in construction work in progress.

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 (collectively, Owners), and a consortium consisting of Westinghouse and Stone & Webster, Inc. have established both informal and formal dispute resolution procedures in order to resolve issues that commonly arise during the course of constructing a project of this magnitude. Southern Nuclear, on behalf of the Owners, has initiated both formal and informal claims through these procedures, including ongoing claims. During the course of construction activities, issues have materialized that may impact the project budget and schedule, including potential costs associated with compressing the project schedule to meet the projected commercial operation dates. The Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. While Georgia Power will continue to monitor this situation, it has not identified any immediate impact to the licensing and construction of Plant Vogtle Units 3 and 4 or the operation of its existing nuclear generating units.

The events in Japan have created uncertainties that may affect transportation of materials, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. On July 12, 2011, a special NRC task force issued a report with initial recommendations for enhancing nuclear reactor safety in the U.S., including potential changes in emergency planning, onsite backup generation, and spent fuel pools for existing reactors. The final form and resulting impact of any changes to safety requirements for existing nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. The task force report supported completion of the certification of the AP1000 reactor design being used at Plant Vogtle Units 3 and 4, noting that the design has many of the features necessary to address the task force’s recommendations.

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.

There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including petitions filed at the NRC in response to the events in Japan. Similar additional challenges at the state and federal level are expected as construction proceeds.

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

Other Construction

Georgia Power is currently constructing Plant McDonough Units 4, 5, and 6 which are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. The Georgia PSC has approved Georgia Power’s quarterly construction monitoring reports, including actual project expenditures incurred, through December 31, 2010. Georgia Power filed its second quarter 2011 construction monitoring report on August 26, 2011, including actual project expenditures incurred through June 30, 2011 as well as a request to approve a 4.6% increase in the current certified

76

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

amount. The Georgia PSC is scheduled to issue its decision on February 16, 2012. Georgia Power will continue to file quarterly construction monitoring reports throughout the construction period. The ultimate outcome of this matter 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 opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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 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 discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Georgia Power’s financial condition remained stable at September 30, 2011. 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 “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $2.08 billion for the first nine months of 2011, compared to $1.71 billion for the corresponding period in 2010. The $372 million increase in cash provided from operating activities is primarily due to higher retail operating revenues and increased deferred income taxes in 2011. Net cash used for investing activities totaled $1.29 billion primarily due to gross property additions to utility plant in the first nine months of 2011. Net cash used for financing activities totaled $732 million for the first nine months of 2011, compared to $535 million net cash provided from financing activities for the corresponding period in 2010. The $1.27 billion decrease is primarily due to higher capital contributions from Southern Company and an increased amount of debt issued in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

77

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant balance sheet changes for the first nine months of 2011 include an increase of $874 million in total property, plant, and equipment, an increase of $538 million in accumulated deferred income taxes related to bonus depreciation and repairs accounting, an increase of $491 million in long-term debt primarily to replace short-term debt, and an increase in paid in capital of $213 million reflecting equity contributions from Southern Company. See FUTURE EARNINGS POTENTIAL – “Income Tax Matters – Bonus Depreciation” herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $254 million will be required through September 30, 2012 to fund maturities of long-term debt.

The construction program of Georgia Power is estimated to include a base level investment of $2.1 billion, $2.2 billion, and $2.0 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $73 million, $79 million, and $58 million for 2011, 2012, and 2013, respectively. In addition, Georgia Power estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $69 million to $289 million for 2011, $191 million to $651 million for 2012, and $476 million to $1.4 billion for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Georgia Power estimates that the potential incremental investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. 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; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Georgia 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.

In June 2011, Georgia Power entered into four PPAs totaling 1,562 MWs annually, which are subject to certification by the Georgia PSC. See FUTURE EARNINGS POTENTIAL – “Georgia PSC Matters – 2011 Integrated Resource Plan Update” herein for additional information. If approved, these PPAs are expected to result in additional obligations of approximately $84 million in 2015, $102 million in 2016, and $1.41 billion thereafter. However, the PPAs include an early termination provision through March 27, 2012 that allows Georgia Power to terminate one or more of the PPAs if Georgia Power does not retire certain coal-fired units as a result of the potential rules and regulations being developed by the EPA. Of the total capacity, 564 MWs will expire in 2027 and 998 MWs in 2030. Three of the PPAs are with Southern Power and are also subject to FERC approval.

Also in June 2011, Georgia Power renewed two rail car leases that contain obligations upon expiration with respect to the residual value of the leased property. These operating leases expire in 2014 and 2018 and Georgia Power’s maximum obligation is approximately $11 million and $20 million, respectively. At the termination of the leases, at Georgia Power’s option, Georgia Power may either exercise its purchase option or the property can be sold to a third party. Estimated annual commitments for the three-year lease and seven-year lease are approximately $1 million and $2 million, respectively.

78

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 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 receipt of the COLs for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. See FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” 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. To meet short-term cash needs and contingencies, Georgia Power had at September 30, 2011 approximately $66 million of cash and cash equivalents and approximately $1.74 billion of unused committed credit arrangements with banks. As of September 30, 2011, of the unused credit arrangements, $250 million expire in 2014 and $1.50 billion expire in 2016. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. At September 30, 2011, the credit arrangements were dedicated to providing liquidity support to Georgia Power’s commercial paper program and approximately $868 million of purchase obligations related to variable rate pollution control revenue bonds. 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. 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 other Southern Company subsidiaries. At September 30, 2011, Georgia Power had no commercial paper borrowings outstanding. During the third quarter 2011, Georgia Power had an average of $110 million of commercial paper outstanding with a weighted average interest rate of 0.2% per annum and the maximum amount outstanding was $364 million. 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

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. At September 30, 2011, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $68 million. At September 30, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.5 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

79

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Market Price Risk

Georgia Power’s market risk exposure relative to interest rate changes for the third quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. Georgia Power continues to manage a natural gas hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power had no material change in market risk exposure for the third quarter 2011 relative to fuel and electricity prices when compared with the December 31, 2010 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, 2011 were as follows:

	Third Quarter			Year-to-Date
	2011			2011
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net		$(67	)		$(100	)
Contracts realized or settled		26			72
Current period changes(a)		(25	)		(38	)
Contracts outstanding at the end of the period, assets (liabilities), net		$(66	)		$(66	)

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

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2011 was an increase of $1 million and an increase of $34 million, respectively, all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At September 30, 2011, Georgia Power had a net hedge volume of 66 million mmBtu with a weighted average contract cost approximately $1.24 per mmBtu above market prices, compared to 65 million mmBtu at June 30, 2011 with a weighted average contract cost approximately $1.18 per mmBtu above market prices and compared to 59 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.74 per mmBtu above market prices.

Regulatory hedges relate to Georgia Power’s natural gas 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 the fuel cost recovery mechanism.

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.

80

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:

				September 30, 2011
				Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
				(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(66	)		(53	)		(13	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(66	)	$	(53	)	$	(13	)	$	—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Georgia Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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 December 2010, the Development Authority of Floyd County issued $53 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2010 for the benefit of Georgia Power. These bonds were purchased and held by Georgia Power. In January 2011, Georgia Power remarketed these bonds to investors.

In January 2011, Georgia Power’s $100 million aggregate principal amount of Series S 4.0% Senior Notes due January 15, 2011 matured.

In January 2011, Georgia Power issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.

In March 2011, Georgia Power’s $300 million variable rate bank term loan due on March 4, 2011 matured and was partially replaced by two one-year $125 million aggregate principal amount variable rate bank loans that bear interest based on one-month LIBOR.

In April 2011, Georgia Power issued $250 million aggregate principal amount of Series 2011B 3.0% Senior Notes due April 15, 2016. The proceeds were used to repay short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.

In April 2011, Georgia Power purchased and held $113.5 million of pollution control revenue bonds. In June 2011, the bonds were remarketed to investors.

In July 2011, Georgia Power redeemed $67 million of the Development Authority of Appling County Pollution Control Revenue Bonds (Georgia Power Company Plant Hatch Project), First Series 2006.

81

GEORGIA POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In July 2011, approximately $8 million of Georgia Power’s Development Authority of Cobb County Pollution Control Revenue Bonds (Georgia Power Company Plant McDonough Project), First Series 1991 matured.

In September 2011, Georgia Power redeemed (i) $140.7 million aggregate principal amount of Series M 5.40% Senior Insured Notes due March 1, 2033, (ii) $35 million aggregate principal amount of Savannah Electric Series F 5.50% Senior Notes due December 12, 2028, (iii) approximately $14.1 million aggregate principal amount of Development Authority of Coweta County Pollution Control Revenue Bonds (Georgia Power Company Plant Yates Project), Second Series 2001, and (iv) $200 million aggregate principal amount of Series G 5-7/8% Junior Subordinated Notes due January 15, 2044 and the related Trust Preferred Securities of Georgia Power Capital Trust VII (as well as approximately $6.2 million of such Series G Junior Subordinated Notes related to Georgia Power’s ownership of the common securities of Georgia Power Capital Trust VII).

In September 2011, Georgia Power remarketed $173 million aggregate principal amount of the Development Authority of Bartow County Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009 and $114.3 million aggregate principal amount of the Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2009 to investors.

In September 2011, the Development Authority of Appling County issued $67 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Hatch Project), First Series 2011 for the benefit of Georgia Power.

Subsequent to September 30, 2011, Georgia Power announced the redemption that will occur on November 21, 2011 of $53 million aggregate principal amount of the Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Third Series 1999.

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.

82

GULF POWER COMPANY

83

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	362,109		$	396,671		$	957,409		$	1,021,530
Wholesale revenues, non-affiliates		33,921			31,211			103,814			86,041
Wholesale revenues, affiliates		52,833			37,995			79,825			88,386
Other revenues		19,167			17,578			50,855			47,381
Total operating revenues		468,030			483,455			1,191,903			1,243,338
Operating Expenses:
Fuel		220,305			237,003			530,773			585,167
Purchased power, non-affiliates		20,046			12,771			37,938			34,615
Purchased power, affiliates		9,941			20,282			39,108			51,725
Other operations and maintenance		74,144			67,178			227,236			202,202
Depreciation and amortization		32,673			34,032			96,733			90,651
Taxes other than income taxes		29,467			29,293			79,230			78,586
Total operating expenses		386,576			400,559			1,011,018			1,042,946
Operating Income		81,454			82,896			180,885			200,392
Other Income and (Expense):
Allowance for equity funds used during construction		2,434			1,424			7,091			4,504
Interest income		22			31			56			87
Interest expense, net of amounts capitalized		(15,156	)		(13,764	)		(43,208	)		(38,286	)
Other income (expense), net		(451	)		(471	)		(1,461	)		(1,355	)
Total other income and (expense)		(13,151	)		(12,780	)		(37,522	)		(35,050	)
Earnings Before Income Taxes		68,303			70,116			143,363			165,342
Income taxes		25,535			25,658			52,451			60,166
Net Income		42,768			44,458			90,912			105,176
Dividends on Preference Stock		1,551			1,551			4,652			4,652
Net Income After Dividends on Preference Stock	$	41,217		$	42,907		$	86,260		$	100,524

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
	2011		2010		2011		2010
	(in thousands)				(in thousands)
Net Income After Dividends on Preference Stock	$	41,217	$	42,907	$	86,260	$	100,524
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, and $(542), respectively		—		—		—		(863	)
Reclassification adjustment for amounts included in net income, net of tax of $90, $90, $270, and $286, respectively		143		143		430		455
Total other comprehensive income (loss)		143		143		430		(408	)
Comprehensive Income	$	41,360	$	43,050	$	86,690	$	100,116

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

84

GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2011			2010
	(in thousands)
Operating Activities:
Net income	$	90,912		$	105,176
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		101,335			95,491
Deferred income taxes		56,869			55,355
Allowance for equity funds used during construction		(7,091	)		(4,504	)
Pension, postretirement, and other employee benefits		(179	)		2,883
Stock based compensation expense		1,055			959
Other, net		(5,787	)		2,570
Changes in certain current assets and liabilities —
-Receivables		(13,605	)		(67,814	)
-Prepayments		7,745			2,667
-Fossil fuel stock		36,802			29,483
-Materials and supplies		(6,382	)		(1,363	)
-Prepaid income taxes		36,081			(9,558	)
-Property damage cost recovery		—			34
-Other current assets		(571	)		—
-Accounts payable		(65	)		12,003
-Accrued taxes		22,186			18,166
-Accrued compensation		(4,290	)		2,695
-Other current liabilities		10,284			10,776
Net cash provided from operating activities		325,299			255,019
Investing Activities:
Property additions		(228,696	)		(203,911	)
Distribution of restricted cash from pollution control revenue bonds		—			6,347
Cost of removal, net of salvage		(9,137	)		(750	)
Change in construction payables		636			(17,792	)
Payments pursuant to long-term service agreements		(6,173	)		(4,211	)
Other investing activities		303			(295	)
Net cash used for investing activities		(243,067	)		(220,612	)
Financing Activities:
Decrease in notes payable, net		(56,607	)		(88,733	)
Proceeds —
Common stock issued to parent		50,000			50,000
Capital contributions from parent company		1,569			3,571
Pollution control revenue bonds		—			21,000
Senior notes		125,000			300,000
Redemptions —
Senior notes		(553	)		(140,413	)
Other long-term debt		(110,000	)		—
Payment of preference stock dividends		(4,652	)		(4,652	)
Payment of common stock dividends		(82,500	)		(78,225	)
Other financing activities		(3,593	)		(3,280	)
Net cash provided from (used for) financing activities		(81,336	)		59,268
Net Change in Cash and Cash Equivalents		896			93,675
Cash and Cash Equivalents at Beginning of Period		16,434			8,677
Cash and Cash Equivalents at End of Period	$	17,330		$	102,352
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $2,826 and $1,795 capitalized for 2011 and 2010, respectively)	$	36,427		$	28,394
Income taxes (net of refunds)		(46,319	)		13,862
Noncash transactions — accrued property additions at end of period		15,820			28,670

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

85

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2011			2010
	(in thousands)
Current Assets:
Cash and cash equivalents	$	17,330		$	16,434
Receivables —
Customer accounts receivable		91,252			74,377
Unbilled revenues		58,813			64,697
Under recovered regulatory clause revenues		9,840			19,690
Other accounts and notes receivable		14,829			9,867
Affiliated companies		15,429			7,859
Accumulated provision for uncollectible accounts		(1,863	)		(2,014	)
Fossil fuel stock, at average cost		128,283			167,155
Materials and supplies, at average cost		51,111			44,729
Other regulatory assets, current		22,491			20,278
Prepaid expenses		22,342			58,412
Other current assets		1,838			3,585
Total current assets		431,695			485,069
Property, Plant, and Equipment:
In service		3,813,901			3,634,255
Less accumulated provision for depreciation		1,108,710			1,069,006
Plant in service, net of depreciation		2,705,191			2,565,249
Construction work in progress		231,156			209,808
Total property, plant, and equipment		2,936,347			2,775,057
Other Property and Investments		16,343			16,352
Deferred Charges and Other Assets:
Deferred charges related to income taxes		52,219			46,357
Prepaid pension costs		9,414			7,291
Other regulatory assets, deferred		259,136			219,877
Other deferred charges and assets		35,318			34,936
Total deferred charges and other assets		356,087			308,461
Total Assets	$	3,740,472		$	3,584,939

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

86

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2011			2010
	(in thousands)
Current Liabilities:
Securities due within one year	$	—		$	110,000
Notes payable		36,577			93,183
Accounts payable —
Affiliated		62,464			46,342
Other		53,842			68,840
Customer deposits		35,859			35,600
Accrued taxes —
Accrued income taxes		8,587			3,835
Other accrued taxes		25,014			7,944
Accrued interest		18,175			13,393
Accrued compensation		10,169			14,459
Other regulatory liabilities, current		33,080			27,060
Liabilities from risk management activities		10,205			9,415
Other current liabilities		21,015			19,766
Total current liabilities		314,987			449,837
Long-term Debt		1,235,344			1,114,398
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		454,530			382,876
Accumulated deferred investment tax credits		7,097			8,109
Employee benefit obligations		76,695			76,654
Other cost of removal obligations		213,113			204,408
Other regulatory liabilities, deferred		43,399			42,915
Other deferred credits and liabilities		164,752			132,708
Total deferred credits and other liabilities		959,586			847,670
Total Liabilities		2,509,917			2,411,905
Preference Stock		97,998			97,998
Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - September 30, 2011: 4,142,717 shares
- December 31, 2010: 3,642,717 shares		353,060			303,060
Paid-in capital		541,706			538,375
Retained earnings		240,088			236,328
Accumulated other comprehensive loss		(2,297	)		(2,727	)
Total common stockholder’s equity		1,132,557			1,075,036
Total Liabilities and Stockholder’s Equity	$	3,740,472		$	3,584,939

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

87

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010

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 rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.

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.

On July 8, 2011, Gulf Power filed a petition with the Florida PSC requesting an increase in retail rates and charges to the extent necessary to generate additional gross annual revenues in the amount of $93.5 million. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail rate of return on common equity of 11.7%. The Florida PSC is expected to make a decision on this matter in the first quarter 2012.

On August 23, 2011, the Florida PSC approved Gulf Power’s request for an interim retail rate increase of $38.5 million per year, to be operative beginning with billings based on meter readings on and after September 22, 2011 and continuing through the effective date of the Florida PSC’s decision on Gulf Power’s petition for the permanent increase. The interim rates are subject to refund pending the outcome of the permanent retail base rate proceeding.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(1.7)	(3.9)	$(14.2)	(14.2)

Gulf Power’s net income after dividends on preference stock for the third quarter 2011 was $41.2 million compared to $42.9 million for the corresponding period in 2010. The decrease was primarily due to an increase in other operations and maintenance expenses for the third quarter 2011, partially offset by higher wholesale capacity revenues from non-affiliates.

Gulf Power’s net income after dividends on preference stock for year-to-date 2011 was $86.3 million compared to $100.5 million for the corresponding period in 2010. The decrease was primarily due to an increase in other operations and maintenance expenses for year-to-date 2011, relatively cooler weather in the third quarter 2011 primarily in the month of September compared to the third quarter 2010, and significantly colder weather in the first quarter 2010. These decreases were partially offset by an increase in AFUDC equity, which is non-taxable.

88

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(34.6)	(8.7)	$(64.1)	(6.3)

In the third quarter 2011, retail revenues were $362.1 million compared to $396.7 million for the corresponding period in 2010. For year-to-date 2011, retail revenues were $957.4 million compared to $1.02 billion for the corresponding period in 2010.

Details of the change to retail revenues are as follows:

	Third Quarter						Year-to-Date
	2011						2011
	(in millions)			(% change)			(in millions)			(% change)
Retail - prior year	$	396.7					$	1,021.5
Estimated change in -
Rates and pricing		(0.1	)		(0.0	)		(4.0	)		(0.4	)
Sales growth (decline)		2.4			0.6			5.7			0.6
Weather		(3.1	)		(0.8	)		(11.0	)		(1.1	)
Fuel and other cost recovery		(33.8	)		(8.5	)		(54.8	)		(5.4	)
Retail - current year	$	362.1			(8.7	)%	$	957.4			(6.3	)%

Revenues associated with changes in rates and pricing was relatively flat in the third quarter 2011 due to lower recoverable costs under Gulf Power’s environmental cost recovery clause due to lower coal generation in the third quarter 2011, partially offset by an increase related to interim retail rate revenues. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Retail Base Rate Case” herein for additional information.

Revenues associated with changes in rates and pricing decreased year-to-date 2011 when compared to the corresponding period in 2010 primarily due to lower recoverable costs under Gulf Power’s environmental cost recovery clause due to lower coal generation, partially offset by an increase related to interim retail rate revenues.

Annually, Gulf Power petitions the Florida PSC for recovery of projected environmental compliance costs including any true-up amount from prior periods, and approved rates are implemented each January. These recovery provisions include related expenses and a return on average net investment. See Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Environmental Remediation” and “Retail Regulatory Matters – Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales increased in the third quarter 2011 when compared to the corresponding period in 2010. Weather-adjusted KWH energy sales to residential and commercial customers decreased 0.3% and 2.2%, respectively, due to lower use per customer. KWH energy sales to industrial customers increased 9.8% primarily due to the addition of a new large customer and a billing adjustment recorded in July 2011.

Revenues attributable to changes in sales increased for year-to-date 2011 when compared to the corresponding period in 2010. Weather-adjusted KWH energy sales to residential customers increased 1.1% due to an increase in customers and higher use per customer. The change in weather-adjusted KWH energy sales to commercial customers was relatively flat. KWH energy sales to industrial customers increased 8.8% primarily due to the addition of a new large customer and changes in customer production levels.

89

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues attributable to changes in weather decreased in the third quarter 2011 when compared to the corresponding period for 2010 due to relatively cooler weather in the third quarter 2011 primarily in the month of September compared to the third quarter 2010.

Revenues attributable to changes in weather decreased year-to-date 2011 when compared to the corresponding period for 2010 due to relatively cooler weather in the third quarter 2011 primarily in the month of September compared to the third quarter 2010, and significantly colder weather in the first quarter 2010.

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 primarily due to lower recoverable fuel and purchased power expenses. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, and purchased power capacity costs. Annually, Gulf Power petitions the Florida PSC for recovery of projected fuel and purchased power costs including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material effect on net income. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Fuel Cost Recovery” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” 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 – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$2.7	8.7	$17.8	20.7

Wholesale revenues from non-affiliates are predominantly unit power sales under long-term contracts to other Florida and Georgia utilities. 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. Wholesale revenues from non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Power and Southern Company system-owned generation, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.

In the third quarter 2011, wholesale revenues from non-affiliates were $33.9 million compared to $31.2 million for the corresponding period in 2010. The increase was primarily due to higher energy revenues related to a 7.2% increase in KWH energy sales and a 12.9% increase in price related to higher capacity rates in the third quarter 2011.

For year-to-date 2011, wholesale revenues from non-affiliates were $103.8 million compared to $86.0 million for the corresponding period in 2010. The increase was primarily due to higher energy revenues related to a 9.2% increase in KWH energy sales and a 30.2% increase in price related to higher capacity rates as a result of contracts effective in June 2010.

Wholesale Revenues – Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$14.8	39.1	$(8.6)	(9.7)

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

90

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the third quarter 2011, wholesale revenues from affiliates were $52.8 million compared to $38.0 million for the corresponding period in 2010. The increase was primarily due to higher energy revenues related to a 63.9% increase in KWH energy sales as a result of increased utilization of Gulf Power generation to serve Southern Company system territorial demand. The increase was partially offset by a 15.1% decrease in price related to lower Gulf Power energy rates in the third quarter 2011.

For year-to-date 2011, wholesale revenues from affiliates were $79.8 million compared to $88.4 million for the corresponding period in 2010. The decrease was primarily due to decreased energy revenues related to a 6.7% decrease in KWH sales as a result of less Gulf Power generation being utilized to serve Southern Company system territorial demand and a 2.9% decrease in price related to lower Gulf Power energy rates for year-to-date 2011.

Other Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$1.6	9.0	$3.5	7.3

In the third quarter 2011, other revenues were $19.2 million compared to $17.6 million for the corresponding period in 2010. For year-to-date 2011, other revenues were $50.9 million compared to $47.4 million for the corresponding period in 2010. The increases were primarily due to increases in revenues from other energy services.

Fuel and Purchased Power Expenses

	Third Quarter 2011						Year-to-Date 2011
	vs.						vs.
	Third Quarter 2010						Year-to-Date 2010
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	(16.7	)		(7.0	)	$	(54.4	)		(9.3	)
Purchased power – non-affiliates		7.3			57.0			3.3			9.6
Purchased power – affiliates		(10.3	)		(51.0	)		(12.6	)		(24.4	)
Total fuel and purchased power expenses	$	(19.7	)				$	(63.7	)

* Fuel includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider and is included in purchased power when determining the average cost of purchased power.

In the third quarter 2011, total fuel and purchased power expenses were $250.3 million compared to $270.0 million for the corresponding period in 2010. The net decrease in fuel and purchased power expenses was due to a $55.7 million decrease in the average cost of purchased power and a $10.6 million decrease in the average cost of fuel, partially offset by a $46.6 million net increase related to total KWHs generated and purchased.

For year-to-date 2011, total fuel and purchased power expenses were $607.8 million compared to $671.5 million for the corresponding period in 2010. The net decrease in fuel and purchased power expenses was due to a $35.6 million decrease in the average cost of purchased power, a $26.1 million decrease in the average cost of fuel, and a $2.0 million net decrease related to total KWHs generated and purchased.

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

91

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of Gulf Power’s cost of generation and purchased power are as follows:

	Third Quarter		Third Quarter		Percent		Year-to-Date		Year-to-Date		Percent
Average Cost	2011		2010		Change		2011		2010		Change
	(cents per net KWH)						(cents per net KWH)
Fuel		4.79		5.09		(5.9)		4.77		5.04		(5.4)
Purchased power		4.70		7.93		(40.7)		4.86		5.99		(18.9)

In the third quarter 2011, fuel expense was $220.3 million compared to $237.0 million for the corresponding period in 2010. The decrease was primarily due to a 24.0% decrease in KWHs generated from Gulf Power’s coal-fired resources and a 7.5% decrease in the average cost of natural gas per KWH generated.

For year-to-date 2011, fuel expense was $530.8 million compared to $585.2 million for the corresponding period in 2010. The decrease was primarily due to a 21.0% decrease in KWHs generated from Gulf Power’s coal-fired resources and a 15.3% decrease in the average cost of natural gas per KWH generated.

Non-Affiliates

In the third quarter 2011, purchased power expense from non-affiliates was $20.0 million compared to $12.7 million for the corresponding period in 2010. The increase was primarily due to a 168.8% increase in the volume of KWHs purchased, partially offset by a 27.4% decrease in the average cost per KWH purchased.

For year-to-date 2011, purchased power expense from non-affiliates was $37.9 million compared to $34.6 million for the corresponding period in 2010. The increase was primarily due to a 36.4% increase in the volume of KWHs purchased, partially offset by a 12.8% decrease in the average cost per KWH purchased.

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

Affiliates

In the third quarter 2011, purchased power expense from affiliates was $10.0 million compared to $20.3 million for the corresponding period in 2010. The decrease was primarily due to a 61.6% decrease in the volume of KWHs purchased, partially offset by a 26.7% increase in the average cost per KWH purchased.

For year-to-date 2011, purchased power expense from affiliates was $39.1 million compared to $51.7 million for the corresponding period in 2010. The decrease was primarily due to a 25.0% 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.

92

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$6.9	10.4	$25.0	12.4

In the third quarter 2011, other operations and maintenance expenses were $74.1 million compared to $67.2 million for the corresponding period in 2010. The increase was primarily due to increases in expenses for labor, routine and planned outage maintenance at generation facilities, energy service projects, and marketing programs. The increased expenses from energy service projects did not have a material impact on earnings since they were offset by associated revenues.

For year-to-date 2011, other operations and maintenance expenses were $227.2 million compared to $202.2 million for the corresponding period in 2010. The increase was primarily due to increases in expenses for routine and planned outage maintenance at generation facilities, labor, and energy service projects. The increased expenses from energy service projects did not have a material impact on earnings since they were offset by associated revenues.

Depreciation and Amortization

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(1.3)	(4.0)	$6.1	6.7

In the third quarter 2011, depreciation and amortization was $32.7 million compared to $34.0 million for the corresponding period in 2010. The decrease was primarily due to new depreciation rates implemented in August 2010, partially offset by net additions to transmission and distribution facilities.

For year-to-date 2011, depreciation and amortization was $96.7 million compared to $90.6 million for the corresponding period in 2010. The increase was primarily due to the addition of environmental control projects and other net additions to transmission and distribution facilities.

Allowance for Equity Funds Used During Construction

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$1.0	70.9	$2.6	57.4

In the third quarter 2011, AFUDC equity was $2.4 million compared to $1.4 million for the corresponding period in 2010. For year-to-date 2011, AFUDC equity was $7.1 million compared to $4.5 million for the corresponding period in 2010. The increases were primarily due to construction of environmental control projects at generating facilities.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$1.4	10.1	$4.9	12.9

In the third quarter 2011, interest expense, net of amounts capitalized was $15.2 million compared to $13.8 million for the corresponding period in 2010. For year-to-date 2011, interest expense, net of amounts capitalized was $43.2 million compared to $38.3 million for the corresponding period in 2010. The increases were primarily due to increased long-term debt levels resulting from the issuance of additional senior notes.

93

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(0.2)	(0.5)	$(7.6)	(12.8)

In the third quarter 2011, income taxes were $25.5 million compared to $25.7 million for the corresponding period in 2010. For year-to-date 2011, income taxes were $52.5 million compared to $60.1 million for the corresponding period in 2010. The decreases were primarily due to lower pre-tax earnings.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. 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 completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. 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 proposed coal combustion byproducts rule. Although its analysis is preliminary, Gulf Power estimates the aggregate capital costs for compliance with these rules to be $1.9 billion through 2020 if the rules are adopted as proposed. Included in this amount is $373 million of estimated expenditures included in Gulf Power’s 2011-2013 base level capital budget described herein in anticipation of these rules. See FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein for additional information. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Gulf Power’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.

94

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Gulf Power in Item 7 and Note 3 of the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Gulf Power in Item 7 and Note 3 of the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies, including Gulf Power, and includes many of the same defendants that were involved in the earlier case. Gulf Power believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.

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 regulation of air quality.

On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-

95

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Gulf Power’s facilities which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.

On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. The States of Alabama, Florida, Georgia, and Mississippi are subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program. The States of Alabama and Georgia are subject to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for the States of Alabama, Florida, Georgia, and Mississippi. The rule could have significant effects on Gulf Power, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including Gulf Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at many of Gulf Power’s existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Gulf Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

96

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Florida PSC Matters

Retail Base Rate Case

On July 8, 2011, 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 $93.5 million. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail rate of return on common equity of 11.7%. The Florida PSC is expected to make a decision on this matter in the first quarter 2012. Gulf Power has calculated its revenue deficiency based on the projected period January 1, 2012 through December 31, 2012 which serves as the test year.

On August 23, 2011, the Florida PSC approved Gulf Power’s request for an interim retail rate increase of $38.5 million per year, effective beginning with billings based on meter readings on and after September 22, 2011 and continuing through the effective date of the Florida PSC’s decision on Gulf Power’s petition for the permanent increase. The interim rates are subject to refund pending the outcome of the permanent retail base rate proceeding.

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

General

On November 1, 2011, the Florida PSC approved Gulf Power’s annual rate clause requests for its fuel, purchased power capacity, conservation, and environmental compliance cost recovery factors for 2012. The net effect of the approved changes is a 1.1% rate decrease for residential customers using 1,000 KWHs per month. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – General,” respectively, in Item 8 of the Form 10-K for additional information.

Fuel Cost Recovery

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. If the projected fuel cost over or under recovery balance at year-end exceeds 10% of the projected fuel revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the fuel cost recovery factor is being requested.

In previous years, Gulf Power has experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and volatile price swings in natural gas. Under recovered fuel costs at September 30, 2011 totaled $7.5 million, compared to $17.4 million at December 31, 2010. This amount is included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor will have no significant effect on Gulf Power’s revenues or net income, but will affect cash flow. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – 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 – Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

Purchased Power Capacity Recovery

Gulf Power has established purchased power capacity recovery cost rates as approved by the Florida PSC. If the projected purchased power capacity cost over or under recovery balance at year-end exceeds 10% of the projected purchased power capacity revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the purchased power capacity cost recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on August 19, 2011, but no adjustment to the 2011 factor was requested.

97

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Over recovered purchased power capacity costs at September 30, 2011 totaled $3.5 million compared to $4.4 million at December 31, 2010. This amount is included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein. Purchased power capacity cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor will have no significant effect on Gulf Power’s revenues or net income, but will affect cash flow. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Purchased Power Capacity Recovery” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – Purchased Power Capacity Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

Environmental Cost Recovery

In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million and is scheduled for completion in early 2015. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011. On May 5, 2011, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in additional spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in December 2011. The ultimate outcome of this matter cannot be determined at this time.

Over recovered environmental costs at September 30, 2011 totaled $16.9 million compared to $10.4 million at December 31, 2010. This amount is included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Environmental Cost Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.

Energy Conservation Cost Recovery

Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the Energy Conservation Cost Recovery clause.

The most recent goal setting process established new DSM goals for the period 2010-2019. The new goals are significantly larger than the goals established in the previous five-year cycle due to a change in the cost-effectiveness test on which the Florida PSC relies to set the goals. Throughout 2010, Gulf Power engaged in a process at the Florida PSC to develop plans and programs to meet the new DSM goals. The DSM program standards were approved in April 2011, which allow Gulf Power to implement its DSM programs designed to meet the new goals. Higher cost recovery rates and achievement of the new DSM goals may result in reduced sales of electricity which could negatively impact results of operations, cash flows, and financial condition if base rates cannot be adjusted on a timely basis.

See BUSINESS under “Rate Matters – Integrated Resource Planning – Gulf Power” in Item 1 of the Form 10-K for a discussion of Gulf Power’s 10-year site plan filed on an annual basis with the Florida PSC.

98

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Tax Matters

Legislation

On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 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 construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Gulf Power through 2013. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Gulf Power estimates the potential increased cash flow for 2011 to be between approximately $40 million and $50 million. The ultimate outcome of this matter cannot be determined at this time.

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 opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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 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 discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

99

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Gulf Power’s financial condition remained stable at September 30, 2011. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $325.3 million for the first nine months of 2011 compared to $255.0 million for the corresponding period in 2010. The $70.3 million increase was primarily due to a $41.6 million increase from prepaid income taxes primarily related to bonus depreciation and a $27.9 million increase related to payments from customer receivables. Net cash used for investing activities totaled $243.1 million in the first nine months of 2011 compared to $220.6 million for the corresponding period in 2010. The $22.4 million increase in cash used was primarily due to gross property additions. Net cash used for financing activities totaled $81.3 million for the first nine months of 2011 compared to $59.3 million provided from financing activities for the corresponding period in 2010. The $140.6 million change was primarily due to a $175.0 million decrease in issuances of pollution control revenue bonds and a $110.0 million increase in redemptions of other long-term debt in 2011, partially offset by $139.9 million fewer redemptions of senior notes in 2010. 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 2011 include a net increase of $161.3 million in property, plant, and equipment, primarily related to environmental control projects; the issuance of $125.0 million in senior notes; an increase of $71.7 million in accumulated deferred income taxes related to property; the issuance of common stock to Southern Company for $50 million; a decrease of $110.0 million in securities due within one year; and a decrease of $36.1 million in prepaid expenses, primarily related to prepaid income taxes.

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, maturities of long-term debt, as well as the related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. There are no requirements through September 30, 2012 to fund maturities of long-term debt.

100

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The construction program of Gulf Power is estimated to include a base level investment of $381.5 million, $395.5 million, and $384.1 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $175.9 million, $227.8 million, and $214.0 million for 2011, 2012, and 2013, respectively. In addition, Gulf Power estimates that potential incremental investments to comply with anticipated new environmental regulations are up to $17.1 million for 2011, up to $55.6 million for 2012, and up to $107.3 million for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Gulf Power estimates the potential investments for new environmental regulations may exceed these estimates. 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; changes in generating plants, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, a long-term bank note, 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. To meet short-term cash needs and contingencies, Gulf Power had at September 30, 2011 cash and cash equivalents of approximately $17.3 million and unused committed credit arrangements with banks of $240 million. During the third quarter, Gulf Power reviewed its lines of credit program and made changes resulting in a net decrease of $40 million. The changes also included the renewal of two lines of credit totaling $60 million for an extended term of three years. Of the unused credit arrangements, $20 million expire in 2011, $55 million expire in 2012, and $165 million expire in 2014. Of the credit arrangements expiring on or before September 30, 2012, $55 million contain provisions allowing one-year term loans executable at expiration. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. During the third quarter 2011, Gulf Power repaid a $30 million draw on a line of credit. These credit arrangements provide liquidity support to Gulf Power’s commercial paper borrowings and $69 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. 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. 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 other Southern Company subsidiaries. At September 30, 2011, Gulf Power had $33 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.2% per annum. During the third quarter 2011, Gulf Power had an average of $58 million of short-term borrowings outstanding with a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $99 million. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

101

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. 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. At September 30, 2011, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $125 million. At September 30, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $538 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Gulf Power’s market risk exposure relative to interest rate changes for the third quarter 2011 has not changed materially compared with the December 31, 2010 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. 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 such, Gulf Power had no material change in market risk exposure for the third quarter 2011 when compared with the December 31, 2010 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, 2011 were as follows:

	Third Quarter			Year-to-Date
	2011			2011
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(9	)	$	(11	)
Contracts realized or settled		3			8
Current period changes(a)		(11	)		(14	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(17	)	$	(17	)

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

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2011 was a decrease of $8 million and a decrease of $6 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At September 30, 2011, Gulf Power had a net hedge volume of 26.1 million mmBtu with a weighted average contract cost approximately $0.67 per mmBtu above market prices, compared to 22.9 million mmBtu at June 30, 2011 with a weighted average contract cost approximately $0.42 per mmBtu above market prices and compared to 19.6 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $0.67 per mmBtu above market prices.

102

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 the fuel cost recovery clause.

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.

Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:

	September 30, 2011
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(17	)		(10	)		(6	)		(1	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(17	)	$	(10	)	$	(6	)	$	(1	)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Gulf Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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 January 2011, Gulf Power issued to Southern Company 500,000 shares of common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of Gulf Power’s short-term indebtedness and for other general corporate purposes, including Gulf Power’s continuous construction program.

In May 2011, Gulf Power issued $125 million aggregate principal amount of Series 2011A 5.75% Senior Notes due June 1, 2051. The net proceeds from the sale of the Series 2011A Senior Notes were used to repay a $110 million bank note, to repay a portion of Gulf Power’s outstanding short-term indebtedness, 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.

103

MISSISSIPPI POWER COMPANY

104

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	233,298		$	230,977		$	620,777		$	620,658
Wholesale revenues, non-affiliates		78,147			78,409			215,811			223,499
Wholesale revenues, affiliates		9,804			13,025			25,407			31,636
Other revenues		4,517			4,672			13,088			11,749
Total operating revenues		325,766			327,083			875,083			887,542
Operating Expenses:
Fuel		157,961			154,607			402,689			388,979
Purchased power, non-affiliates		2,314			2,547			4,660			7,666
Purchased power, affiliates		8,504			10,902			36,721			60,113
Other operations and maintenance		65,851			65,953			200,730			205,055
Depreciation and amortization		19,668			20,106			59,876			57,567
Taxes other than income taxes		18,297			17,935			53,029			53,568
Total operating expenses		272,595			272,050			757,705			772,948
Operating Income		53,171			55,033			117,378			114,594
Other Income and (Expense):
Allowance for equity funds used during construction		7,291			1,490			15,413			2,018
Interest income		167			49			910			122
Interest expense, net of amounts capitalized		(3,856	)		(4,886	)		(15,401	)		(17,011	)
Other income (expense), net		257			1,099			(759	)		3,272
Total other income and (expense)		3,859			(2,248	)		163			(11,599	)
Earnings Before Income Taxes		57,030			52,785			117,541			102,995
Income taxes		18,578			18,759			38,323			37,631
Net Income		38,452			34,026			79,218			65,364
Dividends on Preferred Stock		433			433			1,299			1,299
Net Income After Dividends on Preferred Stock	$	38,019		$	33,593		$	77,919		$	64,065

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2011			2010		2011			2010
	(in thousands)					(in thousands)
Net Income After Dividends on Preferred Stock	$	38,019		$	33,593	$	77,919		$	64,065
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(5,630), $4, $(5,624), and $8, respectively		(9,090	)		7		(9,079	)		13
Comprehensive Income	$	28,929		$	33,600	$	68,840		$	64,078

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

105

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2011			2010
	(in thousands)
Operating Activities:
Net income	$	79,218		$	65,364
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		64,329			60,959
Deferred income taxes		35,225			(4,557	)
Investment tax credits received		51,761			14,352
Allowance for equity funds used during construction		(15,413	)		(2,018	)
Pension, postretirement, and other employee benefits		3,327			6,657
Generation construction screening costs		—			(50,554	)
Stock based compensation expense		1,302			1,053
Other, net		(7,642	)		(720	)
Changes in certain current assets and liabilities —
-Receivables		(5,295	)		(21,003	)
-Fossil fuel stock		2,345			10,163
-Materials and supplies		(1,442	)		(222	)
-Prepaid income taxes		(18,762	)		—
-Other current assets		2,295			(2,503	)
-Accounts payable		21,711			25,819
-Accrued taxes		(3,751	)		7,630
-Accrued compensation		(4,514	)		427
-Over recovered regulatory clause revenues		(17,754	)		14,939
-Other current liabilities		(296	)		(442	)
Net cash provided from operating activities		186,644			125,344
Investing Activities:
Property additions		(605,710	)		(125,980	)
Cost of removal, net of salvage		(6,931	)		(7,613	)
Construction payables		70,909			6,903
Capital grant proceeds		139,921			—
Distribution of restricted cash		50,000			—
Other investing activities		(3,399	)		(6,693	)
Net cash used for investing activities		(355,210	)		(133,383	)
Financing Activities:
Proceeds —
Capital contributions from parent company		199,782			3,920
Other long-term debt issuances		115,000			125,000
Redemptions —
Capital leases		(1,067	)		(988	)
Other long-term debt		(130,000	)		—
Payment of preferred stock dividends		(1,299	)		(1,299	)
Payment of common stock dividends		(56,625	)		(51,450	)
Other financing activities		(377	)		(614	)
Net cash provided from financing activities		125,414			74,569
Net Change in Cash and Cash Equivalents		(43,152	)		66,530
Cash and Cash Equivalents at Beginning of Period		160,779			65,025
Cash and Cash Equivalents at End of Period	$	117,627		$	131,555
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $5,136 and $1,482 capitalized for 2011 and 2010, respectively)	$	13,956		$	16,726
Income taxes (net of refunds)		(33,276	)		11,345
Noncash transactions — accrued property additions at end of period		109,732			10,592

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

106

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2011			2010
	(in thousands)
Current Assets:
Cash and cash equivalents	$	117,627		$	160,779
Restricted cash and cash equivalents		—			50,000
Receivables —
Customer accounts receivable		45,269			37,532
Unbilled revenues		28,753			31,010
Other accounts and notes receivable		7,765			11,220
Affiliated companies		22,282			17,837
Accumulated provision for uncollectible accounts		(709	)		(638	)
Fossil fuel stock, at average cost		109,895			112,240
Materials and supplies, at average cost		30,114			28,671
Other regulatory assets, current		59,143			63,896
Prepaid income taxes		71,749			59,596
Other current assets		28,602			19,057
Total current assets		520,490			591,200
Property, Plant, and Equipment:
In service		2,445,523			2,392,477
Less accumulated provision for depreciation		988,073			971,559
Plant in service, net of depreciation		1,457,450			1,420,918
Construction work in progress		676,762			274,585
Total property, plant, and equipment		2,134,212			1,695,503
Other Property and Investments		6,231			5,900
Deferred Charges and Other Assets:
Deferred charges related to income taxes		28,988			18,065
Other regulatory assets, deferred		128,049			132,420
Other deferred charges and assets		22,086			33,233
Total deferred charges and other assets		179,123			183,718
Total Assets	$	2,840,056		$	2,476,321

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

107

MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2011			2010
	(in thousands)
Current Liabilities:
Securities due within one year	$	241,002		$	256,437
Accounts payable —
Affiliated		54,353			51,887
Other		148,391			59,295
Customer deposits		13,445			12,543
Accrued taxes —
Accrued income taxes		9,636			4,356
Other accrued taxes		42,964			51,709
Accrued interest		5,502			5,933
Accrued compensation		11,563			16,076
Other regulatory liabilities, current		5,523			6,177
Over recovered regulatory clause liabilities		59,292			77,046
Liabilities from risk management activities		43,179			27,525
Other current liabilities		18,651			20,115
Total current liabilities		653,501			589,099
Long-term Debt		461,531			462,032
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		316,675			281,967
Deferred credits related to income taxes		11,660			11,792
Accumulated deferred investment tax credits		84,449			33,678
Employee benefit obligations		115,282			113,964
Other cost of removal obligations		121,972			111,614
Other regulatory liabilities, deferred		60,574			58,814
Other deferred credits and liabilities		30,162			43,213
Total deferred credits and other liabilities		740,774			655,042
Total Liabilities		1,855,806			1,706,173
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		594,677			392,790
Retained earnings		328,179			306,885
Accumulated other comprehensive income (loss)		(9,077	)		2
Total common stockholder’s equity		951,470			737,368
Total Liabilities and Stockholder’s Equity	$	2,840,056		$	2,476,321

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

108

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010

OVERVIEW

Mississippi Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area 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, fuel prices, capital expenditures, and restoration following major storms. 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.

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.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$4.4	13.2	$13.8	21.6

Mississippi Power’s net income after dividends on preferred stock for the third quarter 2011 was $38.0 million compared to $33.6 million for the corresponding period in 2010. The increase in net income after dividends on preferred stock for the third quarter 2011 was primarily due to an increase in AFUDC equity and an increase in wholesale energy revenues, partially offset by a decrease in retail base revenues.

Mississippi Power’s net income after dividends on preferred stock for year-to-date 2011 was $77.9 million compared to $64.1 million for the corresponding period in 2010. The increase in net income after dividends on preferred stock for year-to-date 2011 was primarily due to an increase in AFUDC equity, a decrease in other operations and maintenance expenses, and an increase in wholesale energy revenues, partially offset by a decrease in retail base revenues and a decrease in other income (expense), net.

109

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$2.3	1.0	$0.1	N/M
N/M — Not meaningful

In the third quarter 2011, retail revenues were $233.3 million compared to $231.0 million for the corresponding period in 2010. For year-to-date 2011, retail revenues were $620.8 million compared to $620.7 million for the corresponding period in 2010.

Details of the change to retail revenues are as follows:

	Third Quarter						Year-to-Date
	2011						2011
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	231.0					$	620.7
Estimated change in –
Rates and pricing		(0.2	)		(0.1	)		1.3			0.2
Sales growth (decline)		(1.4	)		(0.6	)		2.9			0.5
Weather		(2.4	)		(1.1	)		(6.4	)		(1.0	)
Fuel and other cost recovery		6.3			2.7			2.3			0.4
Retail – current year	$	233.3			0.9	%	$	620.8			0.1	%

Revenues associated with changes in rates and pricing in the third quarter 2011 when compared to the corresponding period in 2010 were not material.

Revenues associated with changes in rates and pricing increased year-to-date 2011 when compared to the corresponding period in 2010 due to an increase of $1.3 million related to the ECO Plan rate.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Environmental Compliance Overview Plan” of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Mississippi PSC Matters – Retail Regulatory Matters – Environmental Compliance Overview Plan” herein for additional information.

Revenues attributable to changes in sales decreased in the third quarter 2011 when compared to the corresponding period in 2010, primarily resulting from fewer retail customers and lower sales. Weather-adjusted KWH energy sales to the residential and commercial customers decreased 1.6% and 3.3%, respectively, when compared to the corresponding period in 2010 primarily due to a decrease in residential customers and continuing weak economic conditions. KWH energy sales to industrial customers increased 3.7% due to the continued recovery of some large industrial customers.

Revenues attributable to changes in sales increased for year-to-date 2011 when compared to the corresponding period in 2010 primarily due to an increase in sales to commercial and industrial customers. Weather-adjusted KWH energy sales to residential customers decreased 0.1% when compared to the corresponding period in 2010. Weather-adjusted KWH energy sales to commercial customers increased 2.5% when compared to the corresponding period in 2010. The increase in commercial sales was primarily due to lower commercial demand in early 2010. KWH energy sales to industrial customers increased 4.3% due to increased production for some of the larger customers.

Revenues attributable to changes in weather decreased in the third quarter 2011 when compared to the corresponding period for 2010 primarily due to relatively cooler weather primarily in the month of September compared to the third quarter 2010.

110

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues attributable to changes in weather decreased year-to-date 2011 when compared to the corresponding period for 2010 primarily due to significantly colder weather in the first quarter 2010.

Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2011 when compared to the corresponding periods in 2010 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 fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(0.3)	(0.3)	$(7.7)	(3.4)

Wholesale revenues from non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power and Southern Company system-owned generation, demand for energy within the Southern Company system service territory, and the availability of Southern Company system 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 2011, wholesale revenues from non-affiliates were $78.1 million compared to $78.4 million for the corresponding period in 2010. The decrease was primarily due to a $2.6 million decrease in sales and a $0.4 million decrease in capacity revenues, partially offset by a $2.7 million increase associated with higher prices resulting from the higher marginal cost of fuel.

For year-to-date 2011, wholesale revenues from non-affiliates were $215.8 million compared to $223.5 million for the corresponding period in 2010. The decrease was primarily due to a $6.8 million decrease in sales, a $0.6 million decrease associated with lower prices resulting from the lower marginal cost of fuel, and a $0.3 million decrease in capacity revenues.

Wholesale Revenues – Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(3.2)	(24.7)	$(6.2)	(19.7)

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

In the third quarter 2011, wholesale revenues from affiliates were $9.8 million compared to $13.0 million for the corresponding period in 2010. The decrease was primarily due to a $2.9 million decrease in energy revenues, of which $2.1 million was associated with decreased sales and $0.8 million was associated with lower prices. Capacity revenues decreased $0.3 million.

For year-to-date 2011, wholesale revenues from affiliates were $25.4 million compared to $31.6 million for the corresponding period in 2010. The decrease was primarily due to a $3.7 million decrease in energy revenues, of which $2.8 million was associated with lower prices and $0.9 million was associated with decreased sales. Capacity revenues decreased $2.5 million.

111

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Revenues

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(0.2)	(3.3)	$1.4	11.4

In the third quarter 2011, other revenues were $4.5 million compared to $4.7 million for the corresponding period in 2010. The decrease was primarily due to a $0.5 million gain on the sale of equipment which occurred in 2010, partially offset by a $0.4 million increase in transmission revenues.

For year-to-date 2011, other revenues were $13.1 million compared to $11.7 million for the corresponding period in 2010. The increase was primarily due to a $1.4 million increase in transmission revenues.

Fuel and Purchased Power Expenses

	Third Quarter 2011						Year-to-Date 2011
	vs.						vs.
	Third Quarter 2010						Year-to-Date 2010
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	3.4			2.2		$	13.7			3.5
Purchased power — non-affiliates		(0.2	)		(9.1	)		(3.0	)		(39.2	)
Purchased power — affiliates		(2.4	)		(22.0	)		(23.4	)		(38.9	)
Total fuel and purchased power expenses	$	0.8					$	(12.7	)

In the third quarter 2011, total fuel and purchased power expenses were $168.8 million compared to $168.0 million for the corresponding period in 2010. The increase was primarily due to a $5.1 million increase in the cost of fuel and purchased power, partially offset by a $4.3 million decrease in total KWHs generated and purchased.

For year-to-date 2011, total fuel and purchased power expenses were $444.1 million compared to $456.8 million for the corresponding period in 2010. The decrease was primarily due to an $11.6 million decrease in the cost of fuel and purchased power and a $1.1 million decrease related to total KWHs generated and purchased.

Fuel and purchased power 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 — “Mississippi PSC Matters — Retail Regulatory Matters” herein for additional information.

Details of Mississippi Power’s cost of generation and purchased power are as follows:

	Third Quarter		Third Quarter		Percent		Year-to-Date		Year-to-Date		Percent
Average Cost	2011		2010		Change		2011		2010		Change
	(cents per net KWH)						(cents per net KWH)
Fuel		4.22		4.08		3.4		4.11		4.21		(2.4	)
Purchased power		4.05		4.04		0.2		3.60		3.72		(3.2	)

In the third quarter 2011, fuel expense was $158.0 million compared to $154.6 million for the corresponding period in 2010. The increase was primarily due to a 3.4% increase in the average cost of fuel generated per KWH primarily resulting from higher coal prices in the third quarter 2011 compared to the corresponding period in 2010, partially offset by a 1.1% decrease in generation from Mississippi Power facilities resulting from lower energy demand.

112

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2011, fuel expense was $402.6 million compared to $388.9 million for the corresponding period in 2010. The increase was primarily due to a 6.1% increase in generation from Mississippi Power facilities resulting from higher energy demand, partially offset by a 2.4% decrease in the average cost of fuel generated per KWH resulting from lower gas prices.

Non-Affiliates

In the third quarter 2011, purchased power expense from non-affiliates was $2.3 million compared to $2.5 million for the corresponding period in 2010. The decrease was primarily the result of a 47.1% decrease in the average cost of purchased power per KWH, partially offset by a 71.8% increase in KWH volume purchased. The decrease in prices was due to a lower marginal cost of fuel while the increase in KWH volume purchased was a result of lower cost opportunity purchases.

For year-to-date 2011, purchased power expense from non-affiliates was $4.7 million compared to $7.7 million for the corresponding period in 2010. The decrease was primarily the result of an 11.1% decrease in KWH volume purchased and a 31.7% decrease in the average cost of purchased power per KWH. The decrease in KWH volume purchased was a result of higher cost opportunity purchases while the decrease in prices was due to a lower marginal cost of fuel.

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

Affiliates

In the third quarter 2011, purchased power expense from affiliates was $8.5 million compared to $10.9 million for the corresponding period in 2010. The decrease was primarily due to a 29.2% decrease in KWH volume purchased, partially offset by a 10.2% increase in the average cost of purchased power per KWH.

For year-to-date 2011, purchased power expense from affiliates was $36.7 million compared to $60.1 million for the corresponding period in 2010. The decrease was primarily due to a 39.3% decrease in KWH volume purchased, partially offset by a 0.7% increase in the average cost of purchased power per KWH.

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, as approved by the FERC.

Other Operations and Maintenance Expenses

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(0.1)	(0.2)	$(4.3)	(2.1)

In the third quarter 2011, other operations and maintenance expenses were $65.9 million compared to $66.0 million for the corresponding period in 2010. The decrease was primarily due to a $1.9 million decrease in labor costs, offset by a $1.8 million increase in generation-related environmental expenses.

For year-to-date 2011, other operations and maintenance expenses were $200.7 million compared to $205.0 million for the corresponding period in 2010. The decrease was primarily due to a $3.9 million decrease in generation maintenance expenses for several major scheduled outages and a $3.9 million decrease in labor costs, partially offset by a $1.1 million increase in transmission and distribution expenses related to overhead line maintenance and vegetation management costs, a $1.3 million increase in generation-related environmental expenses, and a $1.1 million increase in administrative and general expenses.

113

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Depreciation and Amortization

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(0.4)	(2.2)	$2.3	4.0

In the third quarter 2011, depreciation and amortization was $19.7 million compared to $20.1 million for the corresponding period in 2010. The decrease was primarily due to a $1.0 million decrease in ECO Plan amortization, partially offset by a $0.7 million increase in depreciation resulting from an increase in plant in service.

For year-to-date 2011, depreciation and amortization was $59.9 million compared to $57.6 million for the corresponding period in 2010. The increase was primarily due to a $2.6 million increase in depreciation resulting from an increase in plant in service and a $0.5 million increase in asset retirement obligations (ARO) amortization resulting from the deferral of the gain on the settlement of an ARO, partially offset by a $0.6 million decrease in ECO Plan amortization.

Allowance for Equity Funds Used During Construction

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$5.8	N/M	$13.4	N/M
N/M — Not meaningful

In the third quarter 2011, AFUDC equity was $7.3 million compared to $1.5 million for the corresponding period in 2010. For year-to-date 2011, AFUDC equity was $15.4 million compared to $2.0 million for the corresponding period in 2010. These increases were primarily due to the construction of the Kemper IGCC which began in June 2010.

See Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL — “Integrated Coal Gasification Combined Cycle” herein for additional information regarding the Kemper IGCC.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(1.0)	(21.1)	$(1.6)	(9.5)

In the third quarter 2011, interest expense, net of amounts capitalized was $3.9 million compared to $4.9 million for the corresponding period in 2010. The decrease was primarily due to a $0.9 million increase in capitalized AFUDC debt primarily associated with the Kemper IGCC, a $0.3 million increase in capitalized interest on the Kemper IGCC regulatory asset, a $0.2 million decrease in interest expense related to the assessment of interest in conjunction with a tax audit, and a $0.2 million decrease due to the redemption of long-term debt in March 2011, partially offset by a $0.6 million increase in interest expense associated with the issuances of new long-term debt in September 2010, December 2010, April 2011, and September 2011.

For year-to-date 2011, interest expense, net of amounts capitalized was $15.4 million compared to $17.0 million for the corresponding period in 2010. The decrease was primarily due to a $3.3 million increase in capitalized AFUDC debt primarily associated with the Kemper IGCC, a $0.3 million increase in capitalized interest on the Kemper IGCC regulatory asset, and a $0.3 million decrease due to the redemption of long-term debt in March 2011, partially offset by a $1.6 million increase in interest expense associated with the issuances of new long-term debt in September 2010, December 2010, April 2011, and September 2011, and a $0.5 million increase in amortized debt issuance cost.

114

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL — “Integrated Coal Gasification Combined Cycle” herein for additional information regarding the Kemper IGCC.

Other Income (Expense), Net

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(0.8)	(76.6)	$(4.1)	N/M
N/M — Not meaningful

In the third quarter 2011, other income (expense), net was $0.3 million compared to $1.1 million for the corresponding period in 2010. The decrease was primarily due to a $0.7 million decrease in amounts collected from customers for contributions in aid of construction and a $0.5 million decrease in customer projects, partially offset by a $0.5 million decrease in miscellaneous expenses.

For year-to-date 2011, other income (expense), net was $(0.8) million compared to $3.3 million for the corresponding period in 2010. The decrease was primarily due to a $2.9 million decrease in amounts collected from customers for contributions in aid of construction and a $1.7 million decrease in customer projects, partially offset by a $0.5 million decrease in miscellaneous expenses.

Income Taxes

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(0.2)	(1.0)	$0.7	1.8

In the third quarter 2011, income taxes were $18.6 million compared to $18.8 million for the corresponding period in 2010. The decrease was primarily due to a $2.2 million decrease due to increased AFUDC equity, which is non-taxable, and a $0.3 million decrease due to higher State of Mississippi manufacturing investment tax credits, partially offset by a $1.5 million increase resulting from higher pre-tax earnings and a $0.5 million increase due to a higher unrecognized tax benefits reserve.

For year-to-date 2011, income taxes were $38.3 million compared to $37.6 million for the corresponding period in 2010. The increase was primarily due to a $5.5 million increase resulting from higher pre-tax earnings, a $1.0 million increase due to a higher unrecognized tax benefits reserve, and a $0.3 million increase due to the actualization of the 2010 tax return in the third quarter 2011, partially offset by a $5.1 million decrease due to increased AFUDC equity, which is non-taxable, and a $1.1 million decrease due to higher State of Mississippi manufacturing investment tax credits.

See Note (G) to the Condensed Financial Statements herein under “Effective Tax Rate” for additional information.

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. 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 area. Changes in economic conditions impact

115

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

sales for Mississippi Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

Mississippi Power has completed a preliminary assessment of the EPA’s proposed Utility Maximum Achievable Control Technology (MACT), water quality, and coal combustion byproduct rules. See “Air Quality” and “Water Quality” below for additional information regarding the proposed Utility MACT and water quality rules. 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 for additional information regarding the proposed coal combustion byproducts rule. Although its analysis is preliminary, Mississippi Power estimates that the aggregate capital costs for compliance with these rules could range from $1.0 billion to $2.0 billion through 2020 if the rules are adopted as proposed. Included in this amount is $313 million of estimated expenditures included in Mississippi Power’s 2011-2013 base level capital budget described herein in anticipation of these rules. See FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein for additional information. These costs may arise from existing unit retirements, installation of additional environmental controls, the addition of new generating resources, and changing fuel sources for certain existing units. Mississippi Power’s preliminary analysis further indicates that the short timeframe for compliance with these rules could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters will depend on the final form of the proposed rules and the outcome of any legal challenges to the rules and cannot be determined at this time.

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 for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has appealed the decision to the U.S. Court of Appeals for the Eleventh Circuit. The ultimate outcome of this matter cannot be determined at this time.

116

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — New York Case” of Mississippi Power in Item 7 and Note 3 of the financial statements of Mississippi Power under “Environmental Matters — Carbon Dioxide Litigation — New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” of Mississippi Power in Item 7 and Note 3 of the financial statements of Mississippi Power under “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies (including Alabama Power, Georgia Power, Gulf Power, and Southern Power) and includes many of the same defendants that were involved in the earlier case. Mississippi Power was not named as a defendant in the case. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality.

On May 3, 2011, the EPA published a proposed rule, called Utility MACT, which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule contains numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by December 16, 2011. Compliance for

117

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Mississippi Power’s facilities which could affect unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be affected if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the compliance period, and the limited compliance period could negatively affect electric system reliability. The outcome of this rulemaking will depend on the requirements in the final rule and the outcome of any legal challenges and cannot be determined at this time.

In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. On April 6, 2011, the EPA attempted to rescind its previous approval of the Alabama SIP revision. Mississippi Power’s jointly-owned facility with Alabama Power in Greene County, Alabama is impacted by this decision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s attempted rescission pending judicial review. The EPA’s decision became effective May 6, 2011 and the court denied Alabama Power’s requested stay on May 12, 2011. Unless the court resolves Alabama Power’s appeal in its favor, the EPA’s rescission will continue to affect Mississippi Power’s operations with respect to the Greene County, Alabama plant. The EPA’s rescission has affected unit availability and increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.

On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. The States of Alabama and Mississippi are subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program, and the State of Alabama is subject to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for the States of Alabama and Mississippi. The rule could have significant effects on Mississippi Power, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including Mississippi Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Water Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at

118

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

many of Mississippi Power’s existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Mississippi Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

FERC Matters

Wholesale Rate Filing

On November 2, 2011, Mississippi Power filed a request with the FERC for revised rates under its wholesale electric tariff. The requested revised rates provide for an increase in annual base wholesale revenues in the amount of approximately $32 million, effective January 1, 2012. In this filing, Mississippi Power is also (i) seeking approval to establish a regulatory asset for the portion of non-capitalizable Kemper IGCC-related costs which have been and will continue to be incurred during the construction period for the Kemper IGCC, (ii) seeking authorization to defer as a regulatory asset, for the 10-year period ending October 2021, the difference between the revenue requirement under the purchase option of the combined cycle generating facility at Plant Daniel (Facility) (assuming a remaining 30-year life) and the revenue requirement assuming the continuation of the operating lease regulatory treatment with the accumulated deferred balance at the end of the deferral being amortized into wholesale rates over the remaining life of the Facility, and (iii) seeking authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of the environmental compliance rules which are expected to be issued in December 2011. Mississippi Power is currently in negotiations with all of its customers who have service covered under the tariff. The ultimate outcome of these matters cannot be determined at this time. See Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and “Integrated Coal Gasification Combined Cycle” herein for additional information regarding the Kemper IGCC. See FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” herein for additional information regarding the purchase of the Facility.

Mississippi PSC Matters

Retail Regulatory Matters

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Performance Evaluation Plan” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s base rates.

In November 2010, Mississippi Power filed its annual PEP filing for 2011, which indicated a rate increase of 1.936%, or $16.1 million, annually. On January 10, 2011, the Mississippi Public Utilities Staff (MPUS) contested the filing. On June 7, 2011, the Mississippi PSC issued an order approving a joint stipulation between the MPUS and Mississippi Power resulting in no change in rates.

On March 15, 2011, Mississippi Power submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. On May 2, 2011, Mississippi Power received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. The ultimate outcome of this matter cannot be determined at this time.

119

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

System Restoration Rider

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — System Restoration Rider” of Mississippi Power in Item 7 of the Form 10-K for additional information.

On January 31, 2011, Mississippi Power submitted its 2011 System Restoration Rider rate filing to the Mississippi PSC, which proposed that Mississippi Power be allowed to accrue approximately $3.6 million to the property damage reserve in 2011. On May 5, 2011, the filing was approved by the Mississippi PSC.

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Environmental Compliance Overview Plan” in Item 8 of the Form 10-K for information on Mississippi Power’s annual environmental filing with the Mississippi PSC.

On February 14, 2011, Mississippi Power submitted its ECO Plan notice which proposed an immaterial decrease in annual revenues. In addition, Mississippi Power proposed to change the ECO Plan collection period to more appropriately match ECO Plan revenues with ECO Plan expenditures. On April 7, 2011, due to changes in ECO Plan cost projections, Mississippi Power submitted a revised 2011 ECO Plan which changed the requested annual revenues to a $0.9 million decrease. On May 5, 2011, hearings on the revised ECO Plan were held and the filing was approved by the Mississippi PSC with the new rates effective in May 2011.

In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million, with Mississippi Power’s portion being $312.5 million. As of September 30, 2011, total project expenditures were $35.8 million, with Mississippi Power’s portion being $17.9 million. The project is scheduled for completion in early 2015. Mississippi Power’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through the ECO Plan. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011. On May 5, 2011, in conjunction with the ECO Plan hearings, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in additional spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in December 2011. The ultimate outcome of this matter cannot be determined at this time.

Certificated New Plant

On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-A (CNP-A), a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. Annual CNP-A rate filings will be made with the first filing occurring by November 15, 2011. If approved by the Mississippi PSC, recovery through CNP-A will remain in place thereafter until the end of the calendar year that the Kemper IGCC is placed into commercial service, which is projected to be 2014. On August 9, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-B (CNP-B) to govern rates effective from the first calendar year after the Kemper IGCC is placed into commercial service through the first seven full calendar years of its operation. Under the proposed CNP-B, Mississippi Power’s allowed cost of capital would be adjusted based on certain operational performance indicators. The ultimate outcome of this matter cannot be determined at this time.

120

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 of the Form 10-K for additional information.

In March 2009, Mississippi Power filed with the Mississippi PSC its final accounting of the restoration cost relating to Hurricane Katrina and the storm operations center. On August 4, 2011, the Mississippi PSC issued an order approving this filing. The final net retail receivable of approximately $3.2 million was received on October 21, 2011.

Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. Mississippi Power establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. Mississippi Power is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred in November 2010. The Mississippi PSC approved the retail fuel cost recovery factor in December 2010, with the new rates effective in January 2011. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 5.0% of total 2010 retail revenue. At September 30, 2011, the amount of over recovered retail fuel costs included in the balance sheets was $41.4 million compared to $55.2 million at December 31, 2010. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2011, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 3.5% of total 2010 MRA revenue. Effective February 1, 2011, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 7.0% of total 2010 MB revenue. At September 30, 2011, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $14.6 million and $2.3 million compared to $17.5 million and $4.4 million, respectively, at December 31, 2010. In addition, at September 30, 2011, the amount of over recovered MRA emissions allowance cost included in the balance sheets was $1.0 million. See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information. 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, this decrease to the billing factors will have no significant effect on Mississippi Power’s revenues or net income, but will decrease annual cash flow.

In October 2010, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of Mississippi Power’s fuel-related expenditures included in the retail fuel adjustment clause and energy cost management clause (ECM) for 2010. The audit was completed in the first quarter 2011 with no audit findings. The 2011 audit of fuel-related expenditures began in the second quarter 2011. The ultimate outcome of this matter cannot be determined at this time.

On April 1, 2011, a portion of Mississippi Power’s MB customers transitioned to a PPA with South Mississippi Electric Power Association (SMEPA). On June 21, 2011, Mississippi Power and SMEPA reached an agreement to allocate $3.7 million of the over recovered fuel balance at March 31, 2011 to the PPA. This amount was subsequently refunded to SMEPA on June 27, 2011. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Other Matters” of Mississippi Power in Item 7 of the Form 10-K for additional information.

121

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Plant Daniel Combined Cycle Facility

See FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” herein for additional information regarding the purchase of the Facility. In connection with the purchase of the Facility, Mississippi Power filed a request on July 25, 2011 for an accounting order from the Mississippi PSC. If the accounting order is approved as requested, the retail revenue requirements under the purchase option will be comparable to those otherwise required under operating lease accounting treatment for the extended lease term, with any differences deferred as a regulatory asset over the 10-year period ending October 2021. At the conclusion of the proposed deferral period in 2021, the unamortized deferral balance will be amortized into rates over the remaining life of the Facility. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Integrated Coal Gasification Combined Cycle” and “PSC Matters — Mississippi Baseload Construction Legislation” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding the Kemper IGCC.

In June 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 2010 decision to grant the Certificate of Public Convenience and Necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, in July 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Club’s direct appeal. On February 28, 2011, the Chancery Court issued a judgment affirming the Mississippi PSC’s order authorizing the construction of the Kemper IGCC. On March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court.

In May 2009, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $133 million of Internal Revenue Code Section 48A tax credits (Phase I) to Mississippi Power. On April 19, 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II tax credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the carbon dioxide (CO₂) produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits. Through September 30, 2011, Mississippi Power received or accrued tax benefits totaling $73.9 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC.

In February 2008, Mississippi Power requested that the DOE transfer the remaining funds previously granted under the Clean Coal Power Initiative Round 2 (CCPI2) from a cancelled IGCC project of one of Southern Company’s subsidiaries that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. Mississippi Power will receive grant funds of $245 million during the construction of the Kemper IGCC and $25 million during its initial operation. Mississippi Power had received $158.6 million through September 30, 2011 and subsequently received an additional $20.9 million on October 19, 2011 associated with this grant.

On March 10, 2011, the Sierra Club filed a lawsuit in the U.S. District Court for the District of Columbia against the DOE regarding the National Environmental Policy Act review process asking for a preliminary and permanent injunction on the issuance of CCPI2 funds and loan guarantees and a stay to any related construction activities based upon alleged deficiencies in the DOE’s environmental impact statement. Mississippi Power intervened in this lawsuit on May 18, 2011.

122

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In March 2010, the Mississippi Department of Environmental Quality (MDEQ) issued the Prevention of Significant Deterioration (PSD) air permit modification for the plant, which modifies the original PSD air permit issued in October 2008. The Sierra Club requested a formal evidentiary hearing regarding the issuance of the modified permit. On April 4, 2011, the MDEQ Permit Board held an evidentiary hearing wherein it unanimously affirmed the PSD air permit. On June 30, 2011, the Sierra Club appealed the final PSD air permit issued by the MDEQ to the Chancery Court of Kemper County, Mississippi. Mississippi Power has intervened as a party in this appeal.

On March 4, 2011, Mississippi Power and Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., entered into a contract pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC. On May 19, 2011, Mississippi Power and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tenrgys, LLC, entered into a contract pursuant to which Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC.

On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing CNP-A, a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. On August 9, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing CNP-B to govern rates effective from the first calendar year after the Kemper IGCC is placed into commercial service through the first seven full calendar years of its operation. Under the proposed CNP-B, Mississippi Power’s allowed cost of capital would be adjusted based on certain operational performance indicators. See “Certificated New Plant” herein for additional information.

On June 7, 2011, consistent with the treatment of non-capital costs 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. The amortization period for the regulatory asset will be determined by the Mississippi PSC at a later date. In addition, Mississippi Power is authorized to accrue carrying costs for 2011 on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in connection with future proceedings regarding the cost recovery mechanism for the Kemper IGCC.

On September 9, 2011, Mississippi Power filed a request for confirmation of the Kemper IGCC’s Certificate of Public Convenience and Necessity with the Mississippi PSC authorizing the acquisition, construction, and operation of approximately 61 miles of CO₂ pipeline infrastructure at an estimated capital cost of $141 million.

The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. In conjunction with the plant, Mississippi Power will own a lignite mine and equipment and will acquire mineral reserves located around the plant site in Kemper County. The estimated capital cost of the mine is approximately $245.0 million. On January 18, 2011, Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations, submitted an application to the MDEQ for a surface mining permit for the mine.

As of September 30, 2011, Mississippi Power had spent a total of $664.9 million on the Kemper IGCC, including regulatory filing costs. Of this total, $463.8 million was included in construction work in progress (net of $179.5 million of CCPI2 grant funds), $19.0 million was recorded in other regulatory assets, $1.6 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

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

123

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Tax Matters

Legislation

On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 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 construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction 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 March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on recent discussions with the IRS, Mississippi Power estimates the potential increased cash flow for 2011 to be between approximately $20 million and $25 million. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, 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 herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power’s financial statements.

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

124

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Mississippi Power’s financial condition remained stable at September 30, 2011. 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 “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $186.6 million for the first nine months of 2011 compared to $125.3 million for the corresponding period in 2010. The $61.3 million increase in cash provided from operating activities is primarily due to a $37.4 million increase in investment tax credits related to the Kemper IGCC and a $50.6 million decrease in the use of funds related to the Kemper IGCC generation construction screening costs incurred during the first five months of 2010. The Mississippi PSC issued an order in June 2010 approving the Kemper IGCC. These increases in cash were partially offset by a $32.6 million decrease in over recovered regulatory clause revenues related to lower fuel rates in 2011 and 2010.

Net cash used for investing activities totaled $355.2 million for the first nine months of 2011 compared to $133.4 million for the corresponding period in 2010. The $221.8 million increase in net cash used for investing activities is primarily due to an increase in property additions of $479.7 million primarily related to the Kemper IGCC, partially offset by a $50.0 million decrease in restricted cash, a construction payable increase of $64.0 million, and the receipt of $139.9 million capital grant proceeds related to CCPI2 and smart grid investment grants.

Net cash provided from financing activities totaled $125.4 million for the first nine months of 2011 compared to $74.6 million for the corresponding period in 2010. The $50.8 million increase in net cash provided from financing activities was primarily due to a $195.9 million increase in capital contributions from Southern Company, partially offset by the redemption of $50.0 million in revenue bonds, an $80.0 million maturity of long-term debt, and a $10.0 million decrease in proceeds from other long-term debt. 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 2011 include a decrease in cash and cash equivalents of $43.2 million primarily due to an $80.0 million long-term debt maturity and increased capital spending, partially offset by the receipt of $135.5 million in DOE grant funds. Restricted cash and cash equivalents decreased $50.0 million due to the redemption of revenue bonds in February 2011. Total property, plant, and equipment increased $438.7 million primarily due to the increase in construction work in progress related to the Kemper IGCC. Other accounts payable increased $89.1 million primarily due to increases in construction projects. Accumulated deferred income taxes increased

125

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$34.7 million primarily due to an increase in property related deferred tax liabilities due to 100% bonus depreciation. Accumulated deferred investment tax credits increased $50.8 million primarily related to the Kemper IGCC. Paid-in capital increased $201.9 million primarily due to $200.0 million in capital contributions from Southern Company in the first nine months of 2011.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power’s capital requirements for its construction program, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $241 million will be required through September 30, 2012 to fund maturities of long-term debt.

The construction program of Mississippi Power is estimated to include a base level investment of $818 million, $1.0 billion, and $878 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are expenditures related to the Kemper IGCC of $685 million, $813 million, and $616 million in 2011, 2012, and 2013, respectively. Also included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $20 million, $93 million, and $127 million for 2011, 2012, and 2013, respectively. In addition, Mississippi Power estimates that potential incremental investments to comply with anticipated new environmental regulations are $0 for 2011, up to $18 million for 2012, and up to $55 million for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Mississippi Power estimates that the potential incremental investments in 2012 and 2013 for new environmental regulations will be closer to the upper end of the estimates set forth above. 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; changes in generating plants, including unit retirement and replacement decisions, to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi 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.

On July 20, 2011, Mississippi Power provided notice to Juniper Capital L.P. of its intent to purchase the Facility at the end of the initial lease and, on October 20, 2011, Mississippi Power purchased the Facility. See “Off-Balance Sheet Financing Arrangements” herein for additional information.

Sources of Capital

Except as described below with respect to potential DOE loan guarantees and DOE CCPI2 grant funds, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Mississippi Power has primarily utilized funds from operating cash flows, short-term borrowings, external security offerings, and capital 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. Mississippi Power received $200 million in capital contributions from Southern Company in the first nine months of 2011. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Sources of Capital” of Mississippi Power in Item 7 of the Form 10-K for additional information.

Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees to Mississippi Power. In addition, Mississippi Power has been awarded DOE CCPI2 grant funds of $245 million to be used for the construction of the Kemper IGCC and $25 million to be used

126

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

for the initial operation of the Kemper IGCC. Mississippi Power had received $158.6 million as of September 30, 2011 and subsequently received an additional $20.9 million on October 19, 2011 associated with this grant.

Mississippi Power’s current liabilities sometimes 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. To meet short-term cash needs and contingencies, Mississippi Power had at September 30, 2011 approximately $117.6 million of cash and cash equivalents and $296 million of unused committed credit arrangements with banks. Of the unused credit arrangements, $16 million expire in 2011, $115 million expire in 2012, and $165 million expire in 2014. Of the credit arrangements expiring on or before September 30, 2012, $41 million contain provisions allowing for two-year term loans executable at expiration and $25 million contain provisions allowing for one-year term loans executable at expiration. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Mississippi Power’s commercial paper program and $40 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Mississippi Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. 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 other Southern Company subsidiaries. At September 30, 2011, Mississippi Power had no commercial paper borrowings outstanding. During the third quarter 2011, Mississippi Power had an average of $6 million of commercial paper outstanding with a weighted average interest rate of 0.2% per annum and the maximum amount outstanding was $23 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” of Mississippi Power in Item 7 and Note 7 to the financial statements of Mississippi Power under “Operating Leases” in Item 8 of the Form 10-K for information relating to Mississippi Power’s lease of the Facility.

Mississippi Power was required to provide notice of its intent to either renew the lease or purchase the Facility by July 22, 2011. On July 20, 2011, Mississippi Power provided notice to the lessor of its intent to purchase the Facility. Mississippi Power’s right to purchase the Facility was approved by the Mississippi PSC in its order dated January 7, 1998, as amended on February 19, 1999, which granted Mississippi Power a Certificate of Public Convenience and Necessity for the Facility.

On October 20, 2011, Mississippi Power purchased the Facility for approximately $85 million in cash and the assumption of debt obligations of the lessor related to the Facility, which mature in 2021, have a face value of $270 million and a fixed stated interest rate of 7.13%, and are secured by the Facility and certain personal property, accounts, and proceeds related thereto. Accounting rules require that the Facility be reflected on Mississippi Power’s financial statements at the time of the purchase at the fair value of the consideration rendered. Based on interest rates as of October 20, 2011, the fair value of the debt assumed was approximately $346 million. Accordingly, the Facility will be reflected in Mississippi Power’s financial statements at approximately $431 million. Mississippi Power intends to maintain its traditional capital structure by adding equity to support the additional debt.

In connection with the purchase of the Facility, Mississippi Power filed a request on July 25, 2011 for an accounting order from the Mississippi PSC. If the accounting order is approved as requested, the retail revenue requirements under the purchase option will be comparable to those otherwise required under operating lease accounting treatment for the extended lease term, with any differences deferred as a regulatory asset over the 10-year period ending October 2021. At the conclusion of the proposed deferral period in 2021, the unamortized deferral balance will be amortized into rates over the remaining life of the Facility. On November 2, 2011, Mississippi Power filed a request with the FERC seeking authorization to defer as a regulatory asset, for the 10-year period ending October 2021, the difference between the

127

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

revenue requirement under the purchase of the Facility (assuming a remaining 30-year life) and the revenue requirement assuming the continuation of the operating lease regulatory treatment. At the conclusion of the proposed deferral period in 2021, the accumulated deferred balance will be amortized into wholesale rates over the remaining life of the Facility. The ultimate outcome of these matters cannot be determined at this time.

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, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $328 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Mississippi Power’s market risk exposure relative to interest rate changes for the third quarter 2011 has not changed materially compared with the December 31, 2010 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, commodity fuel prices, and prices of electricity. 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 such, Mississippi Power had no material change in market risk exposure for the third quarter 2011 when compared with the December 31, 2010 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, 2011 were as follows:

	Third Quarter			Year-to-Date
	2011			2011
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(33	)	$	(44	)
Contracts realized or settled		9			25
Current period changes(a)		(11	)		(16	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(35	)	$	(35	)

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

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2011 was a decrease of $2 million and an increase of $9 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and the price of natural gas. At September 30, 2011, Mississippi Power had a net hedge volume of 30.7 million mmBtu with a weighted average contract cost approximately $1.52 per mmBtu above market prices, compared to 25.6 million mmBtu at June 30, 2011 with a

128

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

weighted average contract cost approximately $1.60 per mmBtu above market prices and compared to 24.0 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.92 per mmBtu above market prices.

Regulatory hedges relate to Mississippi 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 the ECM.

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.

Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:

	September 30, 2011
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(35	)		(27	)		(8	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(35	)	$	(27	)	$	(8	)	$	—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Mississippi Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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 and Note (H) to the Condensed Financial Statements herein.

Financing Activities

In February 2011, Mississippi Power redeemed a $50 million series of revenue bonds issued in December 2010.

In March 2011, Mississippi Power’s $80 million long-term bank note with a variable interest rate based on one-month LIBOR matured.

In April 2011, Mississippi Power entered into a one-year $75 million aggregate principal amount long-term floating rate bank loan with a variable interest rate based on one-month LIBOR. The proceeds of this loan were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes, including Mississippi Power’s continuous construction program.

129

MISSISSIPPI POWER COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In September 2011, Mississippi Power entered into a one-year $40 million aggregate principal amount floating rate bank loan that bears interest based on one-month LIBOR. The proceeds were used to repay outstanding short-term debt and for general corporate purposes, including Mississippi Power’s continuous construction program.

In September 2011, Mississippi Power entered into a one-year extension of a $125 million aggregate principal amount floating rate bank loan that bears interest based on one-month LIBOR.

In September 2011, Mississippi Power entered into forward-starting interest rate swaps to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swaps totaled $600 million.

Subsequent to September 30, 2011, Mississippi Power issued $150 million aggregate principal amount of Series 2011A 2.35% Senior Notes due October 15, 2016 and $150 million aggregate principal amount of Series 2011B 4.75% Senior Notes due October 15, 2041. The net proceeds were used by Mississippi Power to repay at maturity all of the outstanding $50 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 6.62% Series 1999B due 2011 (Escatawpa Funding, Limited Partnership Project), to repay at maturity all of the outstanding $15.6 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2005 due 2011 (Escatawpa Funding, Limited Partnership Project), to pay amounts in connection with the purchase of the Facility as described herein under “Off-Balance Sheet Financing Arrangements,” and for general corporate purposes, including Mississippi Power’s continuous construction program. Mississippi Power also settled hedges totaling $150 million related to the Series 2011A issuance at a gain of approximately $1.4 million. This gain will be amortized to interest expense, in earnings, over five years. Mississippi Power settled hedges totaling $150 million related to the Series 2011B issuance at a loss of approximately $0.54 million. This loss will be amortized to interest expense, in earnings, over 10 years.

Subsequent to September 30, 2011, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 21, 2021, issued for the benefit of the lessor as described under “Off-Balance Sheet Financing Arrangements” herein. These bonds are secured by the Facility and certain personal property, accounts, and proceeds related thereto.

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

130

SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

131

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	274,980		$	261,551		$	705,106		$	568,877
Wholesale revenues, affiliates		85,177			93,062			239,020			287,603
Other revenues		2,408			2,217			5,435			5,314
Total operating revenues		362,565			356,830			949,561			861,794
Operating Expenses:
Fuel		141,968			120,466			345,841			294,658
Purchased power, non-affiliates		25,159			24,939			53,765			59,103
Purchased power, affiliates		11,423			31,454			48,700			79,874
Other operations and maintenance		39,571			34,886			122,372			112,132
Depreciation and amortization		31,558			29,361			92,530			87,362
Taxes other than income taxes		4,178			4,071			13,506			14,314
Total operating expenses		253,857			245,177			676,714			647,443
Operating Income		108,708			111,653			272,847			214,351
Other Income and (Expense):
Interest expense, net of amounts capitalized		(19,886	)		(18,801	)		(56,489	)		(58,408	)
Other income (expense), net		(158	)		(209	)		(359	)		(104	)
Total other income and (expense)		(20,044	)		(19,010	)		(56,848	)		(58,512	)
Earnings Before Income Taxes		88,664			92,643			215,999			155,839
Income taxes		32,593			30,067			77,584			46,972
Net Income	$	56,071		$	62,576		$	138,415		$	108,867

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2011			2010		2011		2010
	(in thousands)					(in thousands)
Net Income	$	56,071		$	62,576	$	138,415	$	108,867
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(135), $1,125, $265, and $1,536, respectively		(206	)		1,759		402		2,400
Reclassification adjustment for amounts included in net income, net of tax of $1,106, $1,018, $3,261, and $3,011, respectively		1,685			1,590		4,946		4,703
Total other comprehensive income (loss)		1,479			3,349		5,348		7,103
Comprehensive Income	$	57,550		$	65,925	$	143,763	$	115,970

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

132

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2011			2010
	(in thousands)
Operating Activities:
Net income	$	138,415		$	108,867
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		102,756			97,469
Deferred income taxes		474			10,001
Convertible investment tax credits received		62,298			22,150
Deferred revenues		8,114			18,846
Mark-to-market adjustments		1,479			2,435
Other, net		3,790			2,364
Changes in certain current assets and liabilities —
-Receivables		(24,799	)		(35,588	)
-Fossil fuel stock		305			6,097
-Materials and supplies		(1,826	)		3,216
-Prepaid income taxes		24,436			1,668
-Other current assets		219			598
-Accounts payable		(2,634	)		(1,988	)
-Accrued taxes		27,417			31,069
-Accrued interest		(11,601	)		(12,194	)
-Other current liabilities		(661	)		21
Net cash provided from operating activities		328,182			255,031
Investing Activities:
Property additions		(200,157	)		(211,519	)
Change in construction payables		(14,667	)		31,021
Payments pursuant to long-term service agreements		(46,065	)		(30,936	)
Other investing activities		(3,211	)		3,752
Net cash used for investing activities		(264,100	)		(207,682	)
Financing Activities:
Increase (decrease) in notes payable, net		(220,903	)		20,216
Proceeds —
Capital contributions		125,596			5,638
Senior notes		300,000			—
Repayments — Other long-term debt		(3,441	)		—
Payment of common stock dividends		(68,400	)		(80,325	)
Other financing activities		(5,629	)		426
Net cash provided from (used for) financing activities		127,223			(54,045	)
Net Change in Cash and Cash Equivalents		191,305			(6,696	)
Cash and Cash Equivalents at Beginning of Period		14,204			7,152
Cash and Cash Equivalents at End of Period	$	205,509		$	456
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $12,112 and $7,704 capitalized for 2011 and 2010, respectively)	$	65,201		$	63,560
Income taxes (net of refunds)		(26,555	)		(8,158	)
Noncash transactions — accrued property additions at end of period		36,971			36,576

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

133

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	At September 30,		At December 31,
Assets	2011		2010
	(in thousands)
Current Assets:
Cash and cash equivalents	$	205,509	$	14,204
Receivables —
Customer accounts receivable		73,979		77,033
Other accounts receivable		2,062		1,979
Affiliated companies		50,371		19,673
Fossil fuel stock, at average cost		13,529		13,663
Materials and supplies, at average cost		35,332		33,934
Prepaid service agreements — current		34,087		41,627
Prepaid income taxes		320		53,860
Other prepaid expenses		3,941		4,161
Assets from risk management activities		663		2,160
Other current assets		—		19
Total current assets		419,793		262,313
Property, Plant, and Equipment:
In service		3,162,965		3,143,919
Less accumulated provision for depreciation		628,547		536,107
Plant in service, net of depreciation		2,534,418		2,607,812
Construction work in progress		619,655		427,788
Total property, plant, and equipment		3,154,073		3,035,600
Other Property and Investments:
Goodwill		1,839		1,839
Other intangible assets, net of amortization of $1,280 and $693 at September 30, 2011 and December 31, 2010, respectively		47,839		48,426
Total other property and investments		49,678		50,265
Deferred Charges and Other Assets:
Prepaid long-term service agreements		105,953		69,740
Other deferred charges and assets — affiliated		3,091		3,275
Other deferred charges and assets — non-affiliated		24,611		16,541
Total deferred charges and other assets		133,655		89,556
Total Assets	$	3,757,199	$	3,437,734

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

134

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2011			2010
	(in thousands)
Current Liabilities:
Securities due within one year	$	575,510		$	—
Notes payable — affiliated		—			65,883
Notes payable — non-affiliated		48,884			203,904
Accounts payable —
Affiliated		64,739			69,783
Other		46,078			45,985
Accrued taxes —
Accrued income taxes		17,472			812
Other accrued taxes		12,619			2,775
Accrued interest		18,375			29,977
Liabilities from risk management activities		5,035			5,773
Other current liabilities		5,516			3,923
Total current liabilities		794,228			428,815
Long-term Debt		1,023,967			1,302,619
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		312,861			307,989
Deferred convertible investment tax credits		113,280			80,401
Deferred capacity revenues — affiliated		38,114			30,533
Other deferred credits and liabilities — affiliated		3,859			4,635
Other deferred credits and liabilities — non-affiliated		3,081			16,203
Total deferred credits and other liabilities		471,195			439,761
Total Liabilities		2,289,390			2,171,195
Redeemable Noncontrolling Interest		3,630			3,319
Common Stockholder’s Equity:
Common stock, par value $.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		1,026,565			900,969
Retained earnings		446,285			376,270
Accumulated other comprehensive loss		(8,671	)		(14,019	)
Total common stockholder’s equity		1,464,179			1,263,220
Total Liabilities and Stockholder’s Equity	$	3,757,199		$	3,437,734

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

135

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2011 vs. THIRD QUARTER 2010
AND
YEAR-TO-DATE 2011 vs. YEAR-TO-DATE 2010

OVERVIEW

Southern Power and its wholly-owned subsidiaries construct, acquire, own, and manage generation assets and sell electricity at market-based prices 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 with investor owned utilities, independent power producers, municipalities, and electric cooperatives.

Effective March 15, 2011, Southern Company transferred its ownership in its wholly-owned subsidiary, Southern Renewable Energy, Inc. (SRE) to Southern Power. SRE was formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. As a transfer of net assets among entities under common control, the assets and liabilities of SRE were transferred at historical cost. The consolidated financial statements of Southern Power have been revised to include the financial condition and the results of operations of SRE since its inception in January 2010.

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 (EFOR), contract availability, and net income. 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 that a unit was available. Net income is the primary measure of Southern Power’s financial performance. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS — OVERVIEW — “Key Performance Indicators” of Southern Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2011 vs. Third Quarter 2010			Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)		(change in millions)	(% change)
$(6.5)		(10.4)	$29.5	27.1

Southern Power’s net income for the third quarter 2011 was $56.1 million compared to $62.6 million for the corresponding period in 2010. The decrease was primarily due to higher fuel expenses, higher other operations and maintenance expenses, higher depreciation and amortization, and higher income taxes. The decrease was partially offset by higher energy and capacity revenues under new PPAs that began in December 2010 and January 2011, net of revenue reductions from PPAs expiring in December 2010 and May 2011.

Southern Power’s net income for year-to-date 2011 was $138.4 million compared to $108.9 million for the corresponding period in 2010. The increase was primarily due to higher energy and capacity revenues under new PPAs that began in June, July, and December 2010 and January 2011. The increase was partially offset by lower energy and capacity revenues under existing PPAs and the expiration of PPAs in May 2010, December 2010, and May 2011, as well as lower revenues from energy sales that were not covered by PPAs and lower energy and capacity revenues from power sales to affiliates under the IIC. The increase was also partially offset by higher fuel expenses, higher other operations and maintenance expenses, and higher income taxes.

136

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues — Non-Affiliates

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$13.4	5.1	$136.2	23.9

Wholesale energy 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.

Wholesale revenues from non-affiliates for the third quarter 2011 were $275.0 million compared to $261.6 million for the corresponding period in 2010. The increase was primarily due to $52.6 million of energy and capacity revenues under new non-affiliate PPAs that began in December 2010 and January 2011 and $4.1 million of higher revenues from energy sales that were not covered by PPAs. The increase was partially offset by $38.9 million of lower energy and capacity revenues associated with the expiration of non-affiliate PPAs in December 2010 and $4.4 million of lower energy and capacity revenues under existing non-affiliate PPAs.

Wholesale energy sales to non-affiliates for year-to-date 2011 were $705.1 million compared to $568.9 million for the corresponding period in 2010. The increase was primarily due to $237.5 million of energy and capacity revenues under new non-affiliate PPAs that began in June, July, and December 2010 and January 2011. The increase was partially offset by $71.7 million of lower revenues associated with the expiration of non-affiliate PPAs in December 2010, $4.4 million of lower energy and capacity revenues under existing PPAs, and $25.2 million of lower revenues from energy sales that were not covered by PPAs as a result of significantly more favorable weather in the first quarter 2010 compared to the corresponding period in 2011.

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 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$(7.9)	(8.5)	$(48.6)	(16.9)

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

Wholesale revenues from affiliates for the third quarter 2011 were $85.2 million compared to $93.1 million for the corresponding period in 2010. The decrease was primarily the result of $18.0 million of lower energy and capacity revenues associated with the expiration of affiliate PPAs in May 2011. The decrease was partially offset by $10.2 million related to higher revenues from power sales to affiliates under the IIC.

Wholesale revenues from affiliates for year-to-date 2011 were $239.0 million compared to $287.6 million for the corresponding period in 2010. The decrease was primarily the result of $68.2 million of lower energy and capacity revenues associated with the expiration of affiliate PPAs in May 2010 and May 2011 and $11.8 million related to lower revenues from power sales to affiliates under the IIC. The decrease was partially offset by $30.8 million of higher energy and capacity revenues associated with new affiliate PPAs that began in June 2010.

137

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2011 vs. Third Quarter 2010					Year-to-Date 2011 vs. Year-to-Date 2010
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	21.5			17.8		$51.2			17.4
Purchased power — non-affiliates		0.2			0.9		(5.3	)		(9.0	)
Purchased power — affiliates		(20.0	)		(63.7)		(31.2	)		(39.0	)
Total fuel and purchased power expenses	$	1.7				$	14.7

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 fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.

In the third quarter 2011, total fuel and purchased power expenses were $178.6 million compared to $176.9 million for the corresponding period in 2010. Fuel and purchased power expenses increased $26.4 million due to a 19.3% increase in volume of KWHs generated and purchased. The increase was partially offset by a decrease of $24.7 million due to a 30.5% decrease in the average cost of purchased power and a 5.8% decrease in the average cost of natural gas.

For year-to-date 2011, total fuel and purchased power expenses were $448.3 million compared to $433.6 million for the corresponding period in 2010. Fuel and purchased power expenses increased $106.1 million due to a 26.9% increase in the volume of KWHs generated and purchased. The increase was partially offset by a decrease of $91.4 million due to a 32.7% decrease in the average cost of purchased power and a 10.6% decrease in the average cost of natural gas.

In the third quarter 2011, fuel expense was $142.0 million compared to $120.5 million for the corresponding period in 2010. Fuel expense increased $30.2 million due to an increase in the volume of KWHs generated partially offset by $8.7 million due to a 5.8% decrease in the average cost of natural gas.

For year-to-date 2011, fuel expense was $345.8 million compared to $294.7 million for the corresponding period in 2010. Fuel expense increased $92.6 million due to an increase in the volume of KWHs generated partially offset by $41.4 million due to a 10.6% decrease in the average cost of natural gas.

In the third quarter 2011, purchased power expenses were $36.6 million compared to $56.4 million for the corresponding period in 2010. Purchased power expenses decreased $16.0 million due to a 30.5% decrease in the average cost of purchased power and $3.8 million due to a decrease in the volume of KWHs purchased.

For year-to-date 2011, purchased power expenses were $102.5 million compared to $139.0 million for the corresponding period in 2010. Purchased power expenses decreased $50.0 million due to a 32.7% decrease in the average cost of purchased power partially offset by a $13.5 million increase associated with an increase in the volume of KWHs purchased.

138

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$4.7	13.4	$10.3	9.1

In the third quarter 2011, other operations and maintenance expenses were $39.6 million compared to $34.9 million for the corresponding period in 2010. The increase was primarily due to an increase of $1.5 million related to generating plant outages and maintenance and a $1.4 million increase in administrative and general expenses primarily due to expenses associated with strategic planning, legal expenses, and additional expenses in 2011 due to information technology upgrades.

For year-to-date 2011, other operations and maintenance expenses were $122.4 million compared to $112.1 million for the corresponding period in 2010. The increase was primarily due to $8.9 million related to generating plant outages and maintenance.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$1.1	5.8	$(1.9)	(3.3)

In the third quarter 2011, interest expense, net of amounts capitalized was $19.9 million compared to $18.8 million for the corresponding period in 2010. The increase was primarily due to a $0.3 million increase in interest expense associated with the issuance of new long-term debt in September 2011, $0.3 million associated with settlements and changes in tax positions from prior periods, and $0.2 million associated with interest rate swaps on senior notes.

For year-to-date 2011, interest expense, net of amounts capitalized was $56.5 million compared to $58.4 million for the corresponding period in 2010. The decrease was primarily due to $4.4 million of additional capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant. This decrease was partially offset by $0.7 million associated with settlements and changes in tax positions from prior periods, $0.5 million associated with interest rate swaps on senior notes, $0.5 million associated with an affiliate loan related to SRE in the first quarter 2011, and a $0.3 million increase in interest expense associated with the issuance of new long-term debt in September 2011.

See FUTURE EARNINGS POTENTIAL — “Construction Projects” herein for additional information.

Income Taxes

Third Quarter 2011 vs. Third Quarter 2010		Year-to-Date 2011 vs. Year-to-Date 2010
(change in millions)	(% change)	(change in millions)	(% change)
$2.5	8.4	$30.6	65.2

In the third quarter 2011, income taxes were $32.6 million compared to $30.1 million for the corresponding period in 2010. This increase was primarily due to a $2.5 million decrease in tax benefits from the federal production activities deduction and a $0.8 million increase related to the impact of investment tax credits (ITCs) recognized in 2010 associated with the construction of the Cimarron solar plant. This increase was partially offset by $1.0 million associated with lower pre-tax earnings.

For year-to-date 2011, income taxes were $77.6 million compared to $47.0 million for the corresponding period in 2010. The increase was primarily due to higher pre-tax earnings and a $2.6 million increase related to the impact of ITCs recognized in 2010 associated with the construction of the Cimarron solar plant.

139

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of 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 available generating capacity, the successful remarketing of capacity as current contracts expire, and Southern Power’s ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. Recessionary conditions have lowered demand and have negatively impacted capacity revenues under Southern Power’s PPAs where the amounts purchased are based on demand. Southern Power is unable to predict whether demand under these PPAs will return to pre-recession levels. The timing and extent of the economic recovery is uncertain and will 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 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 affect earnings. 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.

Carbon Dioxide Litigation

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in a similar case, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” of Southern Power in Item 7 and Note 3 of the financial statements of Southern Power under “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought a previous common law nuisance case involving substantially similar allegations. The earlier case was ultimately dismissed by the trial and appellate courts on procedural grounds. The current litigation was filed against numerous chemical, coal, oil, and utility companies, including Southern Power, and includes many of the same defendants that were involved in the earlier case. Southern Power believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.

140

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Southern Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality.

In April 2010, the EPA proposed an Industrial Boiler Maximum Achievable Control Technology rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA published the final rule on March 21, 2011 and, at the same time, issued a notice of intent to reconsider the final rule to allow for additional public review and comment. The EPA has announced plans to finalize the rule by April 30, 2012. The effects of the regulatory proceedings will depend on the final form of the revised regulations and the outcome of any legal challenges and cannot be determined at this time.

On August 8, 2011, the EPA published the final Cross State Air Pollution Rule (CSAPR) requiring reductions of sulfur dioxide and nitrogen oxide emissions from power plants in 27 states located in the eastern half of the U.S. The CSAPR addresses interstate emissions of sulfur dioxide and nitrogen oxides that interfere with downwind states’ ability to meet or maintain national ambient air quality standards for ozone and/or particulate matter. The CSAPR takes effect quickly, with the first phase of compliance beginning January 1, 2012. The CSAPR replaces the 2005 Clean Air Interstate Rule. Each of the states within Southern Power’s service area is subject to the CSAPR’s summer ozone season nitrogen oxide allowance trading program, and the States of Alabama, Georgia, North Carolina, and Texas are subject to the annual sulfur dioxide and nitrogen oxide allowance trading programs for particulate matter. The CSAPR establishes unique emissions budgets for each state. The rule could have effects on Southern Power, including changes to the dispatch and operation of units and unit availability, depending on the cost and availability of emissions allowances. The final CSAPR has been challenged by numerous states, trade associations, and individual companies (including Southern Power), and many of those parties have also asked the EPA to reconsider the rule. In addition, on October 14, 2011, the EPA published proposed technical revisions to the CSAPR, including adjustments to certain state emissions budgets and delaying implementation of key limitations on interstate trading from January 2012 to January 2014. The ultimate outcome will depend on the outcome of any legal and administrative proceedings and proposed revisions and cannot be determined at this time.

Water Quality

On April 20, 2011, the EPA published a proposed rule that establishes standards for reducing effects on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse effects on fish and other aquatic life due to impingement (trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards and entrainment reduction requirements. The rule’s proposed impingement standards could require changes to cooling water intake structures at some of Southern Power’s existing generating facilities, including those with cooling towers. In addition, new generating units constructed at existing plants would have to meet the national impingement standards and closed cycle cooling towers would have to be installed. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Southern Power’s facilities may be subject to additional capital expenditures and compliance costs. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

141

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Construction Projects

Cleveland County Units 1-4

In December 2008, Southern Power announced that it will build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to begin commercial operation in 2012. Costs incurred through September 30, 2011 were $242.5 million. The total estimated construction cost is expected to be between $350 million and $400 million.

Nacogdoches Biomass Plant

In October 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power LLC (Nacogdoches) from American Renewables LLC, the original developer of the project. Nacogdoches is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in 2009 and the plant is expected to begin commercial operation in 2012. Costs incurred through September 30, 2011 were $371.9 million. The total estimated cost of the project is expected to be between $475 million and $500 million.

Power Sales Agreements

In June 2011, Southern Power entered into three PPAs with Georgia Power. Under the first agreement, Southern Power will provide Georgia Power with a total of 625 MWs of annual capacity for the period from June 2015 through May 2030 from Plant Franklin for the first seven months of the contract term and Plant Harris thereafter. Under the second agreement, Southern Power will provide Georgia Power with a total of 75 MWs of annual capacity for the period from January 2015 through May 2030 from Plant Dahlberg. Under the third agreement, Southern Power will provide Georgia Power with a total of 298 MWs of annual capacity for the period from January 2015 through May 2030 from the West Georgia generating facility. These contracts are subject to approval by the Georgia PSC and by the FERC. The PPAs also include an early termination provision through March 27, 2012 that allows Georgia Power to terminate one or more of the PPAs if Georgia Power does not need to retire certain coal-fired units as a result of EPA rules and regulations. Early termination will result in payment by Georgia Power of a fee of up to $20 million.

In August 2011, Southern Power entered into a PPA with an energy marketing firm to provide a total of 250 MWs of annual capacity from January 2016 through December 2025 from Plant Franklin.

Income Tax Matters

Legislation

On September 8, 2011, President Obama introduced the American Jobs Act (AJA). A major incentive in the AJA includes an extension of 100% bonus depreciation for property acquired and placed in service in 2012. Additional proposals are expected related to tax reform, which could include a reduction in the corporate income tax rate and a broadening of the tax base. The ultimate outcome of these matters cannot be determined at this time.

Other Matters

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power’s business activities are subject to extensive governmental regulation related to public health and the environment. 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 opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Power and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported 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.

142

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern 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 ITCs.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power’s financial condition remained stable at September 30, 2011. 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 $328.2 million for the first nine months of 2011, compared to $255.0 million for the corresponding period in 2010. This increase was mainly due to an increase in cash received for convertible ITCs and bonus depreciation. Net cash used for investing activities totaled $264.1 million for the first nine months of 2011, compared to $207.7 million for the corresponding period in 2010. This increase was primarily due to an increase in construction work in progress related to construction activities at Cleveland County and Nacogdoches. Net cash provided from financing activities totaled $127.2 million for the first nine months of 2011, compared to $54.0 million used for the corresponding period in 2010, primarily due to a capital contribution for funding of construction-related activities and the issuance of new long-term debt in September 2011, partially offset by a $155.0 million reduction of commercial paper and a $65.9 million repayment of an affiliate loan related to SRE.

Significant asset changes in the balance sheet for the first nine months of 2011 include an increase in cash and cash equivalents due to a capital contribution for funding of construction-related activities and the issuance of new long-term debt in September 2011, an increase in accounts receivable from affiliated companies primarily due to higher energy sales under PPAs due to seasonality, an increase in construction work in progress due to Cleveland County and Nacogdoches construction activities, and a decrease in prepaid income taxes mainly due to the receipt of an income tax refund from the IRS related to convertible ITCs and bonus depreciation.

Significant liability and stockholder’s equity changes in the balance sheet for the first nine months of 2011 include an increase in securities due within one year due to a maturity of long-term debt in July 2012, a decrease in notes payable due to a repayment of an affiliate loan related to SRE, a reclassification of a long-term senior note to current, partially offset by the issuance of new long-term debt in September 2011, and an increase in deferred convertible ITCs due to additional spending on the Nacogdoches project.

143

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Southern Power in Item 7 of the Form 10-K for a description of Southern Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. Approximately $575 million will be required through September 30, 2012 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. 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, 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, short-term bank loans, 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 indebtedness as a funding source to meet 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, 2011 cash and cash equivalents of approximately $205.5 million and committed credit arrangements with banks of $500 million, all of which expire in 2016. During May 2011, Southern Power terminated its existing credit arrangement and entered into a $500 million credit arrangement expiring in 2016. Borrowings under this credit arrangement 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. At September 30, 2011, Southern Power had $49 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.4% per annum. During the third quarter 2011, Southern Power had an average of $179 million of commercial paper outstanding with a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $256 million. 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 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. At September 30, 2011, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $436 million. At September 30, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or

144

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Baa3 were approximately $1.2 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact 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 (NCMPA1) that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power’s credit. The NCMPA1 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 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is 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.

The changes in fair value of energy-related derivative contracts for the three and nine months ended September 30, 2011 were as follows:

	Third Quarter			Year-to-Date
	2011			2011
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(3.3	)	$	(3.5	)
Contracts realized or settled		2.3			2.9
Current period changes(a)		(3.3	)		(3.7	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(4.3	)	$	(4.3	)

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

145

SOUTHERN POWER 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 for the three and nine months ended September 30, 2011 were a decrease of $1.0 million and a decrease of $0.8 million, respectively, which are due to both power and natural gas positions. These changes are attributable to both the volume and prices of power and natural gas as follows:

	September 30,			June 30,			December 31,
	2011			2011			2010
Power (net sold)
MWHs (in millions)		0.3			0.7			0.9
Weighted average contract cost per MWH above (below) market prices (in dollars)		$(3.95	)		$(2.39	)		$(2.33	)
Natural gas (net purchase)
Commodity — million mmBtu		6.8			9.2			13.0
Commodity — Weighted average contract cost per mmBtu above (below) market prices (in dollars)		$0.55			$0.24			$0.11

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

Asset (Liability) Derivatives		September 30, 2011		December 31, 2010
	(in millions)
Cash flow hedges		$(0.3	)	$(1.0	)
Not designated		(4.0	)	(2.5	)
Total fair value		$(4.3	)	$(3.5	)

Gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales 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, 2011 for energy-related derivative contracts that were not hedges were $(0.6) million and $(1.5) million, respectively, and will continue to be marked to market until the settlement date. For the three and nine months ended September 30, 2010, the total net unrealized pre-tax gains (losses) recognized in the statements of income were $(3.7) million and $(2.4) million, respectively.

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 and the level of the fair value hierarchy in which they fall at September 30, 2011 were as follows:

				September 30, 2011
				Fair Value Measurements
	Total						Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
				(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(4.3	)		(4.4	)		(0.4	)		0.5
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(4.3	)	$	(4.4	)	$	(0.4	)	$	0.5

146

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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, 2011, Southern Power paid $3.4 million on a long-term loan related to SRE.

In September 2011, Southern Power issued $300 million aggregate principal amount of Series 2011A 5.150% Senior Notes due September 15, 2041. The net proceeds from the sale of the Series 2011A Senior Notes were used to repay outstanding short-term debt and for 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.

147

NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

INDEX TO APPLICABLE NOTES TO
FINANCIAL STATEMENTS BY REGISTRANT

Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I
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

148

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, 2010 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, 2011 and 2010. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
	Effective March 15, 2011, Southern Company transferred its ownership in its wholly-owned subsidiary, Southern Renewable Energy, Inc. (SRE), to Southern Power. SRE was formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. As a transfer of net assets among entities under common control, the assets and liabilities of SRE were transferred at historical cost. The consolidated financial statements of Southern Power have been revised to include the financial condition and the results of operations of SRE since its inception in January 2010.
	Southern Company made separate guarantees to two counterparties regarding performance of contractual commitments by SRE. Southern Power assumed the guarantees in connection with the transfer of SRE. The total original notional amount of the guarantees was $120 million, approximately $12 million of which was outstanding at September 30, 2011. Of this amount, approximately $3 million is expected to expire in the first quarter 2012 and approximately $9 million is expected to expire in 2037.
	Leveraged Leases
	Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements of Southern Company under “Leveraged Leases” in Item 8 of the Form 10-K for additional information.
	The recent financial and operational performance of one of Southern Company’s lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the asset. Southern Company will continue to monitor the performance of the underlying assets and to evaluate the ability of the lessee to continue to make the required lease payments. While there are strategic options that Southern Company may pursue to recover its investment in the leveraged lease, the potential impairment loss that would be incurred if there is an abandonment of the project is expected to be approximately $80 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.

149

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

(B)	CONTINGENCIES AND REGULATORY MATTERS
	See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
	General Litigation Matters
	Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, each registrant’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 opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against each registrant and any of its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant’s financial statements.
	Environmental Matters
	New Source Review Actions
	In November 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 NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against Alabama Power is ongoing.
	In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In September 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to a facility co-owned by Mississippi Power. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has appealed the decision to the U.S. Court of Appeals for the Eleventh Circuit.
	Southern Company believes that the traditional operating companies complied with applicable laws and the EPA regulations and interpretations 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 at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time and could possibly require payment of substantial

150

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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.

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from several states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs did not seek monetary damages in connection with their claims. Southern Company believes these claims are without merit. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and in September 2009 that court reversed and remanded the case to the district court. In December 2010, Southern Company and the other defendants appealed the case to the U.S. Supreme Court. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit 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 are the governing bodies of an Inupiat village in Alaska. The plaintiffs allege that the village is being destroyed by erosion caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish legal standing by showing that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit, challenging the district court’s order dismissing the case. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the

151

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. In May 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. However, on May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought the previous common law nuisance case involving substantially similar allegations. The current litigation was filed against numerous chemical, coal, oil, and utility companies (including Alabama Power, Georgia Power, Gulf Power, and Southern Power) and includes many of the same defendants that were involved in the earlier case. Each Southern Company entity named in the lawsuit believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

The registrants 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 subsidiaries may also 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. Within limits approved by the state PSCs, these rates are adjusted annually or as necessary.

Georgia Power’s environmental remediation liability as of September 30, 2011 was $14 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 CERCLA NPL are anticipated; however, they are not expected to have a material impact on Georgia Power’s or Southern Company’s financial statements.

In September 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices regarding this site from the EPA. In addition, in April 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. Discovery is on-going in these cases.

On September 29, 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 Ward Transformer Superfund site. Georgia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. As a result, on November 7, 2011, Georgia Power filed a response with the EPA indicating that Georgia Power is not willing to undertake the work set forth in the UAO because Georgia Power has sufficient cause to believe it is not a liable party.

The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO.

The ultimate outcome of these matters will depend upon further environmental assessment, the ultimate number of PRPs, and a determination regarding Georgia Power’s status as a liable party under CERCLA and cannot be determined at this time. As a result, Southern Company and Georgia Power also cannot estimate the potential financial statement impacts at this time.

Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $62 million as of September 30, 2011. These estimated costs relate to site closure criteria by the Florida

152

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 will be 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. Amounts expensed related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter 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 now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, Southern Company, Georgia Power, Gulf Power, and Mississippi Power do not believe that additional liabilities, if any, at these sites would have a material impact on their respective financial statements.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including Mississippi Power, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and Mississippi Power believe they have complied with applicable laws and that the plaintiffs’ claims are without merit.

Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and the related cases have been dismissed. These agreements have not resulted in any material effects on Southern Company’s or Mississippi Power’s financial statements.

In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network Inc. a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. Southern Company and Mississippi Power believe that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. In August 2010, the defendants filed a motion to dismiss the suit for lack of prosecution. The court denied the defendants’ motion to dismiss the claim. On March 25, 2011, the plaintiffs filed an amended complaint asserting claims for breach of contract for failing to make the defendants’ facilities fully available to the plaintiffs and for failing to indemnify the plaintiffs in defending the underlying landowner litigation. An adverse outcome in this matter is not expected to be material to Southern Company or Mississippi Power; however, the final outcome cannot now be determined.

153

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Nuclear Fuel Disposal Cost Litigation

See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 of the Form 10-K for information regarding the litigation brought by Alabama Power and Georgia Power against the government for breach of contracts related to the disposal of spent nuclear fuel.

In July 2007, the U.S. Court of Federal Claims awarded Georgia Power approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley, Hatch, and Vogtle from 1998 through 2004.

In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April 2008. In May 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay.

On March 11, 2011, the U.S. Court of Appeals for the Federal Circuit issued an order in which it affirmed the damage award to Alabama Power, but remanded the Georgia Power portion of the proceeding back to the U.S. Court of Federal Claims for reconsideration of the damages amount in light of the spent nuclear fuel acceptance rates adopted in a separate proceeding by the U.S. Court of Appeals for the Federal Circuit. The Georgia Power portion remains pending. On July 7, 2011, Alabama Power and the government entered into a stipulation for the entry of a separate judgment in favor of Alabama Power. On July 12, 2011, the court entered final judgment in favor of Alabama Power and subsequently the judgment was paid.

In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim) due to the government’s alleged continuing breach of contract. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of September 30, 2011 for the second claim.

The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be credited to cost of service for the benefit of customers.

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

Income Tax Matters

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On June 10, 2011, Georgia Power and the Georgia Department of Revenue agreed to a settlement resolving the claims. As a result, Georgia Power recorded additional tax benefits of approximately $64 million and, in accordance with the 2010 ARP, also recorded a related regulatory liability of approximately $62 million. In addition, Georgia Power recorded a reduction of approximately $23 million in related interest expense. See Notes 3 and 5 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, and Note (G) herein for additional information.

154

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

State PSC Matters

Alabama Power

Environmental Accounting Order

Proposed environmental regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions. On September 7, 2011, the Alabama PSC approved an order allowing for the establishment of a regulatory asset to record the unrecovered investment costs associated with any such decisions, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure. These costs would be amortized over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement.

Retail Rate Adjustments

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 7 of the Form 10-K for information regarding the rate structure of Alabama Power. On July 12, 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under Alabama Power’s rate structure effective with October 2011 billings. Alabama Power anticipates the elimination of this adjustment will result in additional revenues of approximately $30 million for the remainder of 2011 and is expected to have an annual effect of approximately $150 million beginning in 2012.

In accordance with the order, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues from the elimination of the tax-related adjustment to replenish the NDR, which was impacted as a result of operations and maintenance expenses incurred in connection with the April 2011 storms in Alabama. Alabama Power expects that the additional revenue in 2012 will preclude the need for a rate adjustment under Rate Stabilization and Equalization (Rate RSE). Accordingly, Alabama Power agreed to a moratorium on any increase in 2012 under Rate RSE.

Natural Disaster Reserve

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.

During the first half of 2011, multiple storms caused varying degrees of damage to Alabama Power’s transmission and distribution facilities. The most significant storm occurred on April 27, 2011, causing over 400,000 of Alabama Power’s 1.4 million customers to be without electrical service. The estimated cost of repairing the damage to facilities and restoring electrical service to customers, as a result of these storms, is approximately $45 million for operations and maintenance expenses and approximately $163 million for capital-related expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.

At September 30, 2011, the NDR had an accumulated balance of $75 million, which is included in Southern Company’s and Alabama Power’s Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.

In accordance with the order discussed above that was issued by the Alabama PSC on July 12, 2011 to eliminate a tax-related adjustment under Alabama Power’s rate structure, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues, which are expected to be approximately $30 million.

155

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Retail Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Alabama Power under “Retail Regulatory Matters — Alabama Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s under recovered fuel costs as of September 30, 2011 totaled $39 million as compared to $4 million at December 31, 2010. These under recovered fuel costs at September 30, 2011 are included in deferred under recovered regulatory clause revenues on Southern Company’s and Alabama Power’s Condensed Balance Sheets herein. This classification is based on an estimate which includes 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 recovery of the under recovered fuel costs.

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. On May 24, 2011, the Georgia PSC approved Georgia Power’s request to decrease fuel rates by 0.61%. The decrease reduced Georgia Power’s annual billings by approximately $43 million effective June 1, 2011. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s or Georgia Power’s revenues or net income, but will affect cash flow.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and “Construction — Nuclear,” respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power’s construction of Plant Vogtle Units 3 and 4, which are expected to attain commercial operation in 2016 and 2017, respectively.

In December 2010, Westinghouse submitted a revision to the supporting documents for the AP1000 Design Certification Amendment (DCA) to the NRC. On January 24, 2011, the Advisory Committee on Reactor Safeguards endorsed the issuance of the Construction and Operating Licenses (COLs) for Plant Vogtle Units 3 and 4. In addition, on March 25, 2011, the NRC submitted to the EPA the final environmental impact statement for Plant Vogtle Units 3 and 4. On September 27 and 28, 2011, the NRC held the mandatory hearing for the COLs and Georgia Power’s request for a second limited work authorization. On October 18, 2011, the Atomic Safety and Licensing Board (ASLB) denied the remaining motions seeking to re-open the Plant Vogtle Units 3 and 4 licensing proceeding; however, on October 27, 2011, the petitioners requested reconsideration of this decision and, on November 2, 2011, further appealed to the NRC to admit their contentions, should they again be denied by the ASLB. The remaining steps in the regulatory process are to address the status of these petitions and to obtain the NRC approvals of the DCA and the COLs, which Georgia Power expects in late 2011. Issuance of the COLs by the NRC staff generally would be expected to occur 10 days after the NRC’s decision. However, due to certain administrative procedural requirements, it is possible that the effective date of the DCA and issuance of the COLs could occur in early 2012. In this case, the NRC could approve Georgia Power’s request for a second limited work authorization, which would allow Georgia Power to perform additional construction activities related to the nuclear island in late 2011.

In connection with its certification of Plant Vogtle Units 3 and 4, the Georgia PSC ordered Georgia Power and the Georgia PSC Public Interest Advocacy Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize Georgia Power’s earnings if and when overruns are due to mandates from governing agencies. In May 2011, the Georgia PSC initiated a separate proceeding to address the issue. On August 2, 2011, the Georgia PSC voted to approve a settlement agreement between Georgia Power and the Georgia PSC Public Interest Advocacy Staff whereby the proposed risk

156

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

sharing mechanisms were withdrawn. On August 16, 2011, the Georgia PSC voted to approve Georgia Power’s fourth semi-annual construction monitoring report including total costs of $1.3 billion for Plant Vogtle Units 3 and 4 incurred through December 31, 2010. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

In December 2010, the Georgia PSC approved the NCCR tariff, which became effective January 1, 2011. The NCCR tariff was established to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period in accordance with the Georgia Nuclear Energy Financing Act. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. 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, 2011, approximately $78 million of these 2009 and 2010 costs were included in construction work in progress.

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 (collectively, Owners), and a consortium consisting of Westinghouse and Stone & Webster, Inc. have established both informal and formal dispute resolution procedures in order to resolve issues that commonly arise during the course of constructing a project of this magnitude. Southern Nuclear, on behalf of the Owners, has initiated both formal and informal claims through these procedures, including ongoing claims. During the course of construction activities, issues have materialized that may impact the project budget and schedule, including potential costs associated with compressing the project schedule to meet the projected commercial operation dates. The Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including petitions filed at the NRC in response to the events in Japan. Similar additional challenges at the state and federal level are expected as construction proceeds.

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

Other Construction

Georgia Power is currently constructing Plant McDonough Units 4, 5, and 6 which are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. The Georgia PSC has approved Georgia Power’s quarterly construction monitoring reports, including actual project expenditures incurred, through December 31, 2010. Georgia Power filed its second quarter 2011 construction monitoring report on August 26, 2011, including actual project expenditures incurred through June 30, 2011 as well as a request to approve a 4.6% increase in the current certified amount. The Georgia PSC is scheduled to issue its decision on February 16, 2012. Georgia Power will continue to file quarterly construction monitoring reports throughout the construction period. The ultimate outcome of this matter cannot be determined at this time.

2011 Integrated Resource Plan Update

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” and “Retail Regulatory Matters — Rate Plans,” respectively, in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility Maximum Available Control Technology (MACT) rule for coal- and oil-fired electric utility steam generating units, 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; and the 2010 ARP.

157

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

On August 4, 2011, Georgia Power filed an update to its IRP (2011 IRP Update). The filing included Georgia Power’s application to decertify Plant Branch Units 1 and 2 as of December 31, 2013 and October 1, 2013, the compliance dates for the respective units under the Georgia Multi-Pollutant Rule. However, as a result of the considerable uncertainty regarding pending state and federal environmental regulations, Georgia Power is continuing to defer decisions to add controls, switch fuel, or retire its remaining fossil generating units where environmental controls have not yet been installed, representing approximately 2,600 MWs of capacity. Georgia Power expects to update its economic analysis of these units once the Utility MACT rule is finalized. Georgia Power currently expects that certain units, representing approximately 600 MWs of capacity, are more likely than others to switch fuel or be controlled in time to comply with the Utility MACT rule. However, even if the updated economic analysis shows more positive benefits associated with adding controls or switching fuel for more units, it is unlikely that all of the required controls could be completed by 2015, the expected effective date of the Utility MACT rule. As a result, Georgia Power currently cannot rely on the availability of approximately 2,000 MWs of capacity in 2015. As such, the 2011 IRP Update also includes Georgia Power’s application requesting that the Georgia PSC certify the purchase of a total of 1,562 MWs of capacity beginning in 2015, from four PPAs selected through the 2015 request for proposal process.

Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets resulting from new or revised environmental regulations through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. In connection with the retirement decision, Georgia Power reclassified the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net. Georgia Power is continuing to depreciate these units using the current composite straight-line rates previously approved by the Georgia PSC and upon actual retirement has requested that the Georgia PSC approve the continued deferral and amortization of the units’ remaining net carrying value. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Southern Company’s or Georgia Power’s financial statements.

The Georgia PSC is expected to vote on these requests in March 2012. The ultimate outcome of these matters cannot be determined at this time.

Gulf Power

Retail Base Rate Case

On July 8, 2011, 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 $93.5 million. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail rate of return on common equity of 11.7%. The Florida PSC is expected to make a decision on this matter in the first quarter 2012. Gulf Power has calculated its revenue deficiency based on the projected period January 1, 2012 through December 31, 2012 which serves as the test year.

On August 23, 2011, the Florida PSC approved Gulf Power’s request for an interim retail rate increase of $38.5 million per year, effective beginning with billings based on meter readings on and after September 22, 2011 and continuing through the effective date of the Florida PSC’s decision on Gulf Power’s petition for the permanent increase. The interim rates are subject to refund pending the outcome of the permanent retail base rate proceeding.

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

Fuel Cost Recovery

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. If the projected fuel cost over or under recovery balance at year-end exceeds 10% of the projected fuel revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the fuel cost recovery factor is being requested.

158

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

In previous years, Gulf Power has experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and volatile price swings in natural gas. Under recovered fuel costs at September 30, 2011 totaled $7.5 million, compared to $17.4 million at December 31, 2010. This amount is included in under recovered regulatory clause revenues on Southern Company’s and Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor will have no significant effect on Southern Company’s or Gulf Power’s revenues or net income, but will affect cash flow. See Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters — Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

Purchased Power Capacity Recovery

Gulf Power has established purchased power capacity recovery cost rates as approved by the Florida PSC. If the projected purchased power capacity cost over or under recovery balance at year-end exceeds 10% of the projected purchased power capacity revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the purchased power capacity cost recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on August 19, 2011, but no adjustment to the 2011 factor was requested.

Over recovered purchased power capacity costs at September 30, 2011 totaled $3.5 million compared to $4.4 million at December 31, 2010. This amount is included in other regulatory liabilities, current on Southern Company’s and Gulf Power’s Condensed Balance Sheets herein. Purchased power capacity cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor will have no significant effect on Southern Company’s and Gulf Power’s revenues or net income, but will affect cash flow.

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

Environmental Cost Recovery

In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million and is scheduled for completion in early 2015. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011. On May 5, 2011, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in additional spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in December 2011. The ultimate outcome of this matter cannot be determined at this time.

Over recovered environmental costs at September 30, 2011 totaled $16.9 million compared to $10.4 million at December 31, 2010. This amount is included in other regulatory liabilities, current on Southern Company’s and Gulf Power’s Condensed Balance Sheets herein. See Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.

Energy Conservation Cost Recovery

Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the Energy Conservation Cost Recovery clause.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The most recent goal setting process established new DSM goals for the period 2010-2019. The new goals are significantly larger than the goals established in the previous five-year cycle due to a change in the cost-effectiveness test on which the Florida PSC relies to set the goals. Throughout 2010, Gulf Power engaged in a process at the Florida PSC to develop plans and programs to meet the new DSM goals. The DSM program standards were approved in April 2011, which allow Gulf Power to implement its DSM programs designed to meet the new goals. Higher cost recovery rates and achievement of the new DSM goals may result in reduced sales of electricity which could negatively impact results of operations, cash flows, and financial condition if base rates cannot be adjusted on a timely basis.

Mississippi Power

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Performance Evaluation Plan” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s base rates.

In November 2010, Mississippi Power filed its annual PEP filing for 2011, which indicated a rate increase of 1.936%, or $16.1 million, annually. On January 10, 2011, the Mississippi Public Utilities Staff (MPUS) contested the filing. On June 7, 2011, the Mississippi PSC issued an order approving a joint stipulation between the MPUS and Mississippi Power resulting in no change in rates.

On March 15, 2011, Mississippi Power submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. On May 2, 2011, Mississippi Power received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. The ultimate outcome of this matter cannot be determined at this time.

System Restoration Rider

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — System Restoration Rider” in Item 8 of the Form 10-K for additional information regarding the System Restoration Rider.

On January 31, 2011, Mississippi Power submitted its 2011 System Restoration Rider rate filing to the Mississippi PSC, which proposed that Mississippi Power be allowed to accrue approximately $3.6 million to the property damage reserve in 2011. On May 5, 2011, the filing was approved by the Mississippi PSC.

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Environmental Compliance Overview Plan” in Item 8 of the Form 10-K for information on Mississippi Power’s annual environmental filing with the Mississippi PSC.

On February 14, 2011, Mississippi Power submitted its ECO Plan notice which proposed an immaterial decrease in annual revenues. In addition, Mississippi Power proposed to change the ECO Plan collection period to more appropriately match ECO Plan revenues with ECO Plan expenditures. On April 7, 2011, due to changes in ECO Plan cost projections, Mississippi Power submitted a revised 2011 ECO Plan which changed the requested annual revenues to a $0.9 million decrease. On May 5, 2011, hearings on the revised ECO Plan were held and the filing was approved by the Mississippi PSC with the new rates effective in May 2011.

In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million, with Mississippi Power’s portion being $312.5 million. As of September 30, 2011, total project expenditures were $35.8 million, with Mississippi Power’s portion being $17.9 million. The project is scheduled for completion in early 2015.

160

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Mississippi Power’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through the ECO Plan. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011. On May 5, 2011, in conjunction with the ECO Plan hearings, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in additional spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in December 2011. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. Mississippi Power establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. Mississippi Power is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred in November 2010. The Mississippi PSC approved the retail fuel cost recovery factor in December 2010, with the new rates effective in January 2011. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 5.0% of total 2010 retail revenue. At September 30, 2011, the amount of over recovered retail fuel costs included in the balance sheets was $41.4 million compared to $55.2 million at December 31, 2010. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2011, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 3.5% of total 2010 MRA revenue. Effective February 1, 2011, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 7.0% of total 2010 MB revenue. At September 30, 2011, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $14.6 million and $2.3 million compared to $17.5 million and $4.4 million, respectively, at December 31, 2010. In addition, at September 30, 2011, the amount of over recovered MRA emissions allowance cost included in the balance sheets was $1.0 million. See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information. 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, this decrease to the billing factors will have no significant effect on Southern Company’s or Mississippi Power’s revenues or net income, but will decrease annual cash flow.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Mississippi Power Integrated Coal Gasification Combined Cycle” and of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding Mississippi Power’s construction of the Kemper IGCC.

In June 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 2010 decision to grant the Certificate of Public Convenience and Necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, in July 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Club’s direct appeal. On February 28, 2011, the Chancery Court issued a judgment affirming the Mississippi PSC’s order authorizing the construction of the Kemper IGCC. On March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court.

In May 2009, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $133 million of Internal Revenue Code Section 48A tax credits (Phase I) to Mississippi Power. On April 19, 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II tax credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the carbon dioxide (CO₂) produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits. Through

161

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

September 30, 2011, Mississippi Power received or accrued tax benefits totaling $73.9 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC.

In February 2008, Mississippi Power requested that the DOE transfer the remaining funds previously granted under the Clean Coal Power Initiative Round 2 (CCPI2) from a cancelled IGCC project of one of Southern Company’s subsidiaries that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. Mississippi Power will receive grant funds of $245 million during the construction of the Kemper IGCC and $25 million during its initial operation. Mississippi Power had received $158.6 million through September 30, 2011 and subsequently received an additional $20.9 million on October 19, 2011 associated with this grant.

On March 10, 2011, the Sierra Club filed a lawsuit in the U.S. District Court for the District of Columbia against the DOE regarding the National Environmental Policy Act review process asking for a preliminary and permanent injunction on the issuance of CCPI2 funds and loan guarantees and a stay to any related construction activities based upon alleged deficiencies in the DOE’s environmental impact statement. Mississippi Power intervened in this lawsuit on May 18, 2011.

In March 2010, the Mississippi Department of Environmental Quality (MDEQ) issued the Prevention of Significant Deterioration (PSD) air permit modification for the plant, which modifies the original PSD air permit issued in October 2008. The Sierra Club requested a formal evidentiary hearing regarding the issuance of the modified permit. On April 4, 2011, the MDEQ Permit Board held an evidentiary hearing wherein it unanimously affirmed the PSD air permit. On June 30, 2011, the Sierra Club appealed the final PSD air permit issued by the MDEQ to the Chancery Court of Kemper County, Mississippi. Mississippi Power has intervened as a party in this appeal.

On March 4, 2011, Mississippi Power and Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., entered into a contract pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC. On May 19, 2011, Mississippi Power and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tenrgys, LLC, entered into a contract pursuant to which Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC.

On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-A (CNP-A), a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. Annual CNP-A rate filings will be made with the first filing occurring by November 15, 2011. If approved by the Mississippi PSC, recovery through CNP-A will remain in place thereafter until the end of the calendar year that the Kemper IGCC is placed into commercial service, which is projected to be 2014. On August 9, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-B (CNP-B) to govern rates effective from the first calendar year after the Kemper IGCC is placed into commercial service through the first seven full calendar years of its operation. Under the proposed CNP-B, Mississippi Power’s allowed cost of capital would be adjusted based on certain operational performance indicators.

On June 7, 2011, consistent with the treatment of non-capital costs 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. The amortization period for the regulatory asset will be determined by the Mississippi PSC at a later date. In addition, Mississippi Power is authorized to accrue carrying costs for 2011 on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in connection with future proceedings regarding the cost recovery mechanism for the Kemper IGCC.

On September 9, 2011, Mississippi Power filed a request for confirmation of the Kemper IGCC’s Certificate of Public Convenience and Necessity with the Mississippi PSC authorizing the acquisition, construction, and operation of approximately 61 miles of CO₂ pipeline infrastructure at an estimated capital cost of $141 million.

The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. In conjunction with the plant, Mississippi Power will own a lignite mine and equipment

162

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

and will acquire mineral reserves located around the plant site in Kemper County. The estimated capital cost of the mine is approximately $245.0 million. On January 18, 2011, Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations, submitted an application to the MDEQ for a surface mining permit for the mine.

As of September 30, 2011, Mississippi Power had spent a total of $664.9 million on the Kemper IGCC, including regulatory filing costs. Of this total, $463.8 million was included in construction work in progress (net of $179.5 million of CCPI2 grant funds), $19.0 million was recorded in other regulatory assets, $1.6 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

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

Plant Daniel Combined Cycle Generating Units

See Note 7 to the financial statements of Southern Company and Mississippi Power under “Operating Leases” and “Operating Leases — Plant Daniel Combined Cycle Generating Units,” respectively, in Item 8 of the Form 10-K for information relating to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel (Facility).

Mississippi Power was required to provide notice of its intent to either renew the lease or purchase the Facility by July 22, 2011. On July 20, 2011, Mississippi Power provided notice to the lessor of its intent to purchase the Facility. Mississippi Power’s right to purchase the Facility was approved by the Mississippi PSC in its order dated January 7, 1998, as amended on February 19, 1999, which granted Mississippi Power a Certificate of Public Convenience and Necessity for the Facility.

On October 20, 2011, Mississippi Power purchased the Facility for approximately $85 million in cash and the assumption of debt obligations of the lessor related to the Facility, which mature in 2021, have a face value of $270 million and a fixed stated interest rate of 7.13%, and are secured by the Facility and certain personal property, accounts, and proceeds related thereto. Accounting rules require that the Facility be reflected on Southern Company’s and Mississippi Power’s financial statements at the time of the purchase at the fair value of the consideration rendered. Based on interest rates as of October 20, 2011, the fair value of the debt assumed was approximately $346 million. Accordingly, the Facility will be reflected in Southern Company’s and Mississippi Power’s financial statements at approximately $431 million. Mississippi Power intends to maintain its traditional capital structure by adding equity to support the additional debt.

In connection with the purchase of the Facility, Mississippi Power filed a request on July 25, 2011 for an accounting order from the Mississippi PSC. If the accounting order is approved as requested, the retail revenue requirements under the purchase option will be comparable to those otherwise required under operating lease accounting treatment for the extended lease term, with any differences deferred as a regulatory asset over the 10-year period ending October 2021. At the conclusion of the proposed deferral period in 2021, the unamortized deferral balance will be amortized into rates over the remaining life of the Facility. On November 2, 2011, Mississippi Power filed a request with the FERC seeking authorization to defer as a regulatory asset, for the 10-year period ending October 2021, the difference between the revenue requirement under the purchase of the Facility (assuming a remaining 30-year life) and the revenue requirement assuming the continuation of the operating lease regulatory treatment. At the conclusion of the proposed deferral period in 2021, the accumulated deferred balance will be amortized into wholesale rates over the remaining life of the Facility. The ultimate outcome of these matters cannot be determined at this time.

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(C)	FAIR VALUE MEASUREMENTS
	As of September 30, 2011, 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
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2011:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Interest rate derivatives		—		16		—		16
Foreign currency derivatives		—		3		—		3
Nuclear decommissioning trusts(a)		487		671		—		1,158
Cash equivalents and restricted cash		1,286		—		—		1,286
Other investments		4		53		13		70
Total	$	1,777	$	746	$	13	$	2,536
Liabilities:
Energy-related derivatives	$	—	$	154	$	—	$	154
Interest rate derivatives		—		27		—		27
Foreign currency derivatives		—		2		—		2
Total	$	—	$	183	$	—	$	183
Alabama Power
Assets:
Nuclear decommissioning trusts:(b)
Domestic equity	$	228	$	53	$	—	$	281
Foreign equity		23		23		—		46
U.S. Treasury and government agency securities		16		9		—		25
Corporate bonds		—		112		—		112
Mortgage and asset backed securities		—		29		—		29
Other		—		8		—		8
Cash equivalents and restricted cash		445		—		—		445
Total	$	712	$	234	$	—	$	946
Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	29
Interest rate derivatives		—		12		—		12
Total	$	—	$	41	$	—	$	41

164

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2011:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts:(c)
Domestic equity		125		1		—		126
Foreign equity		95		—		—		95
U.S. Treasury and government agency securities		—		68		—		68
Municipal bonds		—		57		—		57
Corporate bonds		—		153		—		153
Mortgage and asset backed securities		—		96		—		96
Other		—		62		—		62
Cash equivalents		45		—		—		45
Total	$	265	$	439	$	—	$	704
Liabilities:
Energy-related derivatives	$	—	$	68	$	—	$	68
Gulf Power
Assets:
Cash equivalents	$	14	$	—	$	—	$	14
Liabilities:
Energy-related derivatives	$	—	$	17	$	—	$	17
Mississippi Power
Assets:
Foreign currency derivatives	$	—	$	3	$	—	$	3
Cash equivalents		85		—		—		85
Total	$	85	$	3	$	—	$	88
Liabilities:
Energy-related derivatives	$	—	$	35	$	—	$	35
Interest rate derivatives		—		15		—		15
Foreign currency derivatives		—		2		—		2
Total	$	—	$	52	$	—	$	52
Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents		196		—		—		196
Total	$	196	$	1	$	—	$	197
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5

(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 receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the securities lending program. As of September 30, 2011, approximately $53 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.

165

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 used in the 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.

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

As of September 30, 2011, 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:

	Fair		Unfunded	Redemption	Redemption
As of September 30, 2011:	Value		Commitments	Frequency	Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	37	None	Daily		1 to 3 days
Other — commingled funds		62	None	Daily	Not applicable
Trust owned life insurance		82	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		1,286	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Trust owned life insurance	$	82	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		445	None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	37	None	Daily		1 to 3 days
Other — commingled funds		62	None	Daily	Not applicable
Cash equivalents:
Money market funds		45	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	14	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	85	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	196	None	Daily	Not applicable

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The NRC requires licensees of commercial 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 commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, 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, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset rate date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The corporate bonds — commingled funds 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 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, 2011, the decrease in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $64 million and $32 million, respectively, for Alabama Power, $34 million and $7 million, respectively, for Georgia Power, and $98 million and $39 million, respectively, for Southern Company.

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.

Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at September 30, 2011 were as follows:

	Level 3
	Other
	Three Months Ended			Nine Months Ended
	September 30, 2011			September 30, 2011
	(in millions)
Beginning balance	$	17		$	19
Purchases		—			1
Total gains (losses) — realized/unrealized:
Included in earnings		—			(5	)
Included in OCI		(4	)		(2	)
Ending balance at September 30, 2011	$	13		$	13

168

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 30, 2011, 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	$	20,532	$	22,215
Alabama Power	$	6,232	$	6,910
Georgia Power	$	8,620	$	9,327
Gulf Power	$	1,235	$	1,359
Mississippi Power	$	702	$	739
Southern Power	$	1,599	$	1,694

* Includes securities due within one year.

The fair values were based on closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

(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 further 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		Three Months		Nine Months		Nine Months
	Ended		Ended		Ended		Ended
	September 30, 2011		September 30, 2010		September 30, 2011		September 30, 2010
	(in millions)
As reported shares		860		836		854		829
Effect of options		8		6		7		4
Diluted shares		868		842		861		833

Stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive were 0.4 million and 6.7 million for the three months ended September 30, 2011 and 2010, respectively, and 0.4 million and 13.7 million for the nine months ended September 30, 2011 and 2010, respectively. Assuming an average stock price of $40.14 (the highest exercise price of the anti-dilutive options outstanding in 2011), there would be no effect on stock options for the three and nine months ended September 30, 2011. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding in 2010), the effect of options would have increased by 0.4 million and 0.8 million shares for the three and nine months ended September 30, 2010, respectively.

169

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:

									Preferred and
	Number of					Common			Preference		Total
	Common Shares					Stockholders’			Stock of		Stockholders’
	Issued		Treasury			Equity			Subsidiaries		Equity
	(in thousands)								(in millions)
Balance at December 31, 2010		843,814		(474	)	$	16,202		$	707	$	16,909
Net income after dividends on preferred and preference stock		—		—			1,942			—		1,942
Other comprehensive income (loss)		—		—			(11	)		—		(11	)
Stock issued		18,634		—			692			—		692
Cash dividends on common stock		—		—			(1,193	)		—		(1,193	)
Other		—		(45	)		1			—		1
Balance at September 30, 2011		862,448		(519	)	$	17,633		$	707	$	18,340
Balance at December 31, 2009		820,152		(505	)	$	14,878		$	707	$	15,585
Net income after dividends on preferred and preference stock		—		—			1,822			—		1,822
Other comprehensive income (loss)		—		—			16			—		16
Stock issued		18,994		—			650			—		650
Cash dividends on common stock		—		—			(1,114	)		—		(1,114	)
Other		—		30			3			—		3
Balance at September 30, 2010		839,146		(475	)	$	16,255		$	707	$	16,962

(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 under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information.

The following table outlines the credit arrangements by company as of September 30, 2011:

					Executable										Expires Within
					Term-Loans				Expires						One Year(a)
													2013				No
					One		Two						And		Term		Term
Company	Total		Unused		Year		Years		2011		2012		Beyond		Out		Out
	(in millions)
Southern Company	$	1,000	$	1,000	$	—	$	—	$	—	$	—	$	1,000	$	—	$	—
Alabama Power		1,296		1,296		111		—		60		121		1,115		111		71
Georgia Power		1,750		1,745		—		—		—		—		1,750		—		—
Gulf Power		240		240		55		—		20		55		165		55		20
Mississippi Power		296		296		25		41		16		115		165		66		65
Southern Power		500		500		—		—		—		—		500		—		—
Other		50		50		25		—		—		25		25		25		—
Total	$	5,132	$	5,127	$	216	$	41	$	96	$	316	$	4,720	$	257	$	156

(a)   Reflects facilities expiring on or before September 30, 2012.

170

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

In May 2011, Southern Company, Alabama Power, Georgia Power, and Southern Power each replaced their multi-year credit arrangements that were to expire in 2012 with new five-year credit arrangements that will expire in 2016. These new credit arrangements provide for borrowings by Southern Company, Alabama Power, Georgia Power, and Southern Power of up to $1.0 billion, $800 million, $1.5 billion, and $500 million, respectively.

Subsequent to September 30, 2011, Alabama Power replaced a $20 million credit arrangement expiring in 2011 with a $30 million credit arrangement which will expire in 2014.

These credit arrangements generally have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes long-term debt payable to affiliated trusts and other hybrid securities.

(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 (ERISA). No contributions to the qualified pension plan are expected for the year ending December 31, 2011. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

171

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Components of the net periodic benefit costs for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Southern			Alabama			Georgia			Gulf			Mississippi
Pension Plans	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended September 30, 2011
Service cost	$	46		$	11		$	14		$	2		$	3
Interest cost		97			24			36			4			4
Expected return on plan assets		(152	)		(44	)		(59	)		(6	)		(7	)
Net amortization		14			3			5			—			1
Net cost (income)	$	5		$	(6	)	$	(4	)	$	—		$	1
Nine Months Ended September 30, 2011
Service cost	$	138		$	32		$	43		$	6		$	7
Interest cost		292			72			108			13			13
Expected return on plan assets		(456	)		(130	)		(176	)		(20	)		(19	)
Net amortization		40			10			14			1			2
Net cost (income)	$	14		$	(16	)	$	(11	)	$	—		$	3
Three Months Ended September 30, 2010
Service cost	$	43		$	10		$	13		$	2		$	2
Interest cost		98			25			36			5			4
Expected return on plan assets		(138	)		(42	)		(54	)		(6	)		(5	)
Net amortization		11			3			4			—			1
Net cost (income)	$	14		$	(4	)	$	(1	)	$	1		$	2
Nine Months Ended September 30, 2010
Service cost	$	129		$	31		$	40		$	6		$	6
Interest cost		293			73			109			13			13
Expected return on plan assets		(413	)		(126	)		(164	)		(18	)		(16	)
Net amortization		32			8			11			1			2
Net cost (income)	$	41		$	(14	)	$	(4	)	$	2		$	5

172

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Southern			Alabama			Georgia			Gulf			Mississippi
Postretirement Benefits	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended September 30, 2011
Service cost	$	6		$	1		$	1		$	—		$	—
Interest cost		23			6			11			1			1
Expected return on plan assets		(16	)		(6	)		(8	)		—			—
Net amortization		5			2			3			—			—
Net cost (income)	$	18		$	3		$	7		$	1		$	1
Nine Months Ended September 30, 2011
Service cost	$	16		$	4		$	5		$	1		$	1
Interest cost		69			18			31			3			3
Expected return on plan assets		(48	)		(19	)		(23	)		(1	)		(1	)
Net amortization		15			5			8			—			—
Net cost (income)	$	52		$	8		$	21		$	3		$	3
Three Months Ended September 30, 2010
Service cost	$	6		$	2		$	3		$	—		$	—
Interest cost		25			7			11			1			2
Expected return on plan assets		(15	)		(7	)		(8	)		—			—
Net amortization		5			2			2			—			—
Net cost (income)	$	21		$	4		$	8		$	1		$	2
Nine Months Ended September 30, 2010
Service cost	$	19		$	5		$	7		$	1		$	1
Interest cost		75			20			33			3			4
Expected return on plan assets		(47	)		(19	)		(23	)		(1	)		(1	)
Net amortization		15			5			8			—			—
Net cost (income)	$	62		$	11		$	25		$	3		$	4

173

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 in Item 8 of the Form 10-K for information on the effective income tax rate.
	Southern Company
	Southern Company’s effective tax rate was 36.1% for the nine months ended September 30, 2011, compared to 33.1% for the corresponding period in 2010. Southern Company’s effective tax rate is lower than the statutory rate primarily due to its employee stock dividend deduction and non-taxable AFUDC equity. Southern Company’s effective tax rate increased primarily due to no production activities deduction and no Georgia state income tax credits for activity through Georgia ports available to Southern Company for the nine months ended September 30, 2011, compared to the production activities deduction and additional Georgia state income tax credits recognized as of September 30, 2010.
	Alabama Power
	Alabama Power’s effective tax rate was 39.0% for the nine months ended September 30, 2011, compared to 36.9% for the corresponding period in 2010. The increase was due to an increase in Alabama state income taxes as a result of a decrease in the state income tax deduction for federal income taxes paid.
	Georgia Power
	Georgia Power’s effective tax rate was 35.8% for the nine months ended September 30, 2011, compared to 32.3% for the corresponding period in 2010. The increase was primarily due to the inclusion of Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011, which reduced the amount of AFUDC equity capitalized, and the impact of Georgia state income tax credits discussed above under “Southern Company.”
	Gulf Power
	Gulf Power’s effective tax rate was 36.6% for the nine months ended September 30, 2011, compared to 36.4% for the corresponding period in 2010. The increase was not material.
	Mississippi Power
	Mississippi Power’s effective tax rate was 32.6% for the nine months ended September 30, 2011, compared to 36.5% for the corresponding period in 2010. The decrease was primarily due to an increase in non-taxable AFUDC equity related to the Kemper IGCC construction.
	Southern Power
	Southern Power’s effective tax rate was 35.9% for the nine months ended September 30, 2011, compared to 30.1% for the corresponding period in 2010. The increase was primarily due to the impact of a decrease in investment tax credits and no production activities deduction, combined with higher net income.

174

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Unrecognized Tax Benefits

Changes during 2011 for unrecognized tax benefits were as follows:

	Southern			Alabama			Georgia			Gulf			Mississippi			Southern
	Company			Power			Power			Power			Power			Power
							(in millions)
Unrecognized tax benefits as of December 31, 2010	$	296		$	43		$	237		$	4		$	4		$	2
Tax positions from current periods		43			2			7			1			1			1
Tax positions from prior periods		(108	)		(18	)		(87	)		(2	)		(1	)		—
Reductions due to settlements		(112	)		—			(112	)		—			—			—
Reductions due to expired statute of limitations		—			—			—			—			—			—
Balance as of September 30, 2011	$	119		$	27		$	45		$	3		$	4		$	3

The tax positions from current periods relate primarily to the MC Asset Recovery litigation settlement refund claim, the tax accounting method change for repairs – generation assets, and the production activities deduction. See Note 5 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Effective Tax Rate” for additional information. The tax positions decrease from prior periods and reductions due to settlements relate to the settlement of the Georgia state tax credit litigation on June 10, 2011. See Note (B) under “Income Tax Matters — Georgia State Income Tax Credits” herein for additional information. In addition, the tax positions decrease from prior periods also relates to the uncertain tax position for the tax accounting method change for repairs – transmission and distribution assets. See “Tax Method of Accounting for Repairs” below for additional information.

The impact on the effective tax rate, if recognized, is as follows:

							As of
							December 31,
	As of September 30, 2011						2010
	Georgia		Other		Southern		Southern
	Power		Registrants		Company		Company
			(in millions)
Tax positions impacting the effective tax rate	$	28	$	12	$	76	$	217
Tax positions not impacting the effective tax rate		17		25		43		79
Balance of unrecognized tax benefits	$	45	$	37	$	119	$	296

The tax positions impacting the effective tax rate primarily relate to the production activities deduction tax position and the MC Asset Recovery litigation settlement refund claim. See Note 5 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Effective Tax Rate” for additional information. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs - generation assets. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Accrued interest for unrecognized tax benefits was as follows:

	Georgia			Other		Southern
	Power			Registrants		Company
	(in millions)
Interest accrued as of December 31, 2010	$	27		$	2	$	29
Interest reclassified due to settlements		(24	)		—		(24	)
Interest accrued during the period		2			1		4
Balance as of September 30, 2011	$	5		$	3	$	9

All of the registrants classify interest on tax uncertainties as interest expense. The interest reclassified due to settlements is primarily associated with the Georgia state tax credit litigation settled on June 10, 2011. See Note (B) under “Income Tax Matters — Georgia State Income Tax Credits” herein for additional information.

175

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 Southern Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the tax accounting method change for repairs - generation assets, as well as the conclusion or settlement of federal and state audits, could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Tax Method of Accounting for Repairs

Southern Company submitted a tax accounting method change for repair costs associated with its subsidiaries’ generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $141 million for Alabama Power, $133 million for Georgia Power, $8 million for Gulf Power, $5 million for Mississippi Power, $6 million for Southern Power, and $297 million for Southern Company on a consolidated basis. On August 19, 2011, the IRS issued Revenue Procedure 2011-43, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. Based upon this guidance from the IRS, the uncertain tax position for the tax accounting method change for repairs – transmission and distribution assets has been removed. However, the IRS continues to work with the utility industry in an effort to resolve the repair costs for generation assets matter in a consistent manner for all utilities. Due to uncertainty regarding the ultimate resolution of the repair costs for generation assets, an unrecognized tax position has been recorded for the tax accounting method change for repairs – generation assets. The ultimate outcome of this matter cannot be determined at this time.

(H)

DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, 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.

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 electric utilities may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the electric utilities may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

176

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Energy-related derivative contracts are accounted for in 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, 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, 2011, the net volume of energy-related derivative contracts for power and natural gas positions for the registrants, 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:

	Power						Gas
			Longest		Longest		Net		Longest		Longest
	Net Sold		Hedge		Non-Hedge		Purchased		Hedge		Non-Hedge
	MWHs		Date		Date		mmBtu		Date		Date
	(in millions)						(in millions)
Southern Company		0.3		—		2011		160		2015		2015
Alabama Power		—		—		—		31		2015		—
Georgia Power		—		—		—		66		2015		—
Gulf Power		—		—		—		26		2015		—
Mississippi Power		—		—		—		31		2015		—
Southern Power		0.3		—		2011		7		2012		2015

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 was 2.95 million mmBtu for Southern Company, 2.69 million mmBtu for Georgia Power, and was immaterial for the other registrants.

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending September 30, 2012 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries 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.

177

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 30, 2011, the following interest rate derivatives were outstanding:

	Notional		Interest Rate			Interest Rate			Hedge Maturity	Fair Value Gain (Loss)
	Amount		Received			Paid			Date	September 30, 2011
	(in millions)									(in millions)
Cash flow hedges of existing debt
Southern Company	$	300	3-month LIBOR + 0.40% spread				1.24	%*	October 2011	$	—
Cash flow hedges of forecasted debt
Alabama Power		300	3-month LIBOR				2.90	%*	December 2022		(12	)
Mississippi Power		150	3-month LIBOR				2.37	%*	September 2021		(4	)
Mississippi Power		150	3-month LIBOR				1.25	%*	September 2016		—
Mississippi Power		300	3-month LIBOR				2.66	%*	April 2022		(11	)
Fair value hedges of existing debt
						3-month LIBOR +
Southern Company		350		4.15	%	1.96%* spread			May 2014		16
Total	$	1,550								$	(11	)

* Weighted Average

The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending September 30, 2012, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.

	Estimated Gain (Loss)to
	be Reclassified for the			Total Deferred
	12 Months Ending			Gains (Losses)
Registrant	September 30, 2012			Amortized Through
	(in millions)
Southern Company	$	(16	)		2037
Alabama Power		—			2035
Georgia Power		(3	)		2037
Gulf Power		(1	)		2020
Mississippi Power		(1	)		2022
Southern Power		(11	)		2016

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 recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

178

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 30, 2011, the following foreign currency derivatives were outstanding:

				Fair Value Gain
	Notional	Average	Hedge	(Loss)
	Amount	Forward Rate	Maturity Date	September 30, 2011
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR28.3	1.297 Dollars per Euro	Various through March 2014	$	1

Derivative Financial Statement Presentation and Amounts

At September 30, 2011, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

Asset Derivatives at September 30, 2011
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf Power		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	1	$	—	$	1	$	—	$	—
Other deferred charges and assets		1		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	2	$	—	$	2	$	—	$	—		N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	6	$	—	$	—	$	—	$	—	$	—
Other deferred charges and assets		10		—		—		—		—		—
Foreign currency derivatives:
Other current assets		3		—		—		—		3		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	19	$	—	$	—	$	—	$	3	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets*	$	1	$	—	$	—	$	—	$	—	$	—
Assets from risk management activities		—		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	1	$	—	$	—	$	—	$	—	$	1
Total asset derivatives	$	22	$	—	$	2	$	—	$	3	$	1

* Southern Company includes “Assets from risk management activities” in “Other current assets” where applicable.

179

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Liability Derivatives at September 30, 2011
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	114	$	24	$	53	$	10	$	27
Other deferred credits and liabilities		35		5		15		7		8
Total derivatives designated as hedging instruments for regulatory purposes	$	149	$	29	$	68	$	17	$	35		N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Liabilities from risk management activities	$	15	$	—	$	—	$	—	$	15	$	—
Other deferred credits and liabilities		12		12		—		—		—		—
Foreign currency derivatives:
Liabilities from risk management activities		2		—		—		—		2		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	29	$	12	$	—	$	—	$	17	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	5	$	—	$	—	$	—	$	—	$	5
Total liability derivatives	$	183	$	41	$	68	$	17	$	52	$	5

All derivative instruments are measured at fair value. See Note (C) herein for additional information.

At September 30, 2011, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheet was as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet	Southern			Alabama			Georgia			Gulf			Mississippi
Location	Company			Power			Power			Power			Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(114	)	$	(24	)	$	(53	)	$	(10	)	$	(27	)
Other regulatory assets, deferred		(35	)		(5	)		(15	)		(7	)		(8	)
Other regulatory liabilities, current		1			—			—			—			—
Other current liabilities*		—			—			1			—			—
Other regulatory liabilities, deferred		1			—			—			—			—
Other deferred credits and liabilities**		—			—			1			—			—
Total energy-related derivative gains (losses)	$	(147	)	$	(29	)	$	(66	)	$	(17	)	$	(35	)

*	Georgia Power includes “Other regulatory liabilities, current” in “Other current liabilities.”
**	Georgia Power includes “Other regulatory liabilities, deferred” in “Other deferred credits and liabilities.”

For the three months and nine months ended September 30, 2011, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were $5 million and $7 million, respectively. For the three months and nine months ended September 30, 2010, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were $9 million and $17 million, respectively. These amounts were offset with changes in the fair value of the hedged debt.

180

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months and nine months ended September 30, 2011, the pre-tax (losses) from foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were $(3) million and $(2) million, respectively. For each of the three months and nine months ended September 30, 2010, the pre-tax gains from foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were $5 million. These amounts were offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there is no impact on Southern Company’s or Mississippi Power’s statements of income.

For the three months ended September 30, 2011 and September 30, 2010, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI into
Derivatives in Cash Flow	on Derivative						Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2011			2010				2011			2010
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	—		$	3		Fuel	$	—		$	—
Interest rate derivatives		(27	)		(1	)	Interest expense, net of amounts capitalized		(5	)		(7	)
Total	$	(27	)	$	2			$	(5	)	$	(7	)
Alabama Power
Interest rate derivatives	$	(12	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(3	)
Gulf Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	—		$	—
Mississippi Power
Interest rate derivatives	$	(15	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	—		$	3		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense, net of amounts capitalized		(3	)		(3	)
Total	$	—		$	3			$	(3	)	$	(3	)

181

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the nine months ended September 30, 2011 and September 30, 2010, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI into
Derivatives in Cash Flow	on Derivative						Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2011			2010				2011			2010
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	1		$	4		Fuel	$	—		$	—
Interest rate derivatives		(23	)		(3	)	Interest expense, net of amounts capitalized		(10	)		(24	)
Total	$	(22	)	$	1			$	(10	)	$	(24	)
Alabama Power
Interest rate derivatives	$	(8	)	$	—		Interest expense, net of amounts capitalized	$	3		$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(13	)
Gulf Power
Interest rate derivatives	$	—		$	(1	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Mississippi Power
Interest rate derivatives	$	(15	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	1		$	4		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense, net of amounts capitalized		(8	)		(8	)
Total	$	1		$	4			$	(8	)	$	(8	)

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three months and nine months ended September 30, 2011 and September 30, 2010, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.

182

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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, 2011, the fair value of derivative liabilities with contingent features, by registrant, was as follows:

	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power
					(in millions)
Derivative liabilities	$	32	$	7	$	16	$	2	$	5	$	2

At September 30, 2011, the registrants had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $32 million for each registrant.

Currently, each of the registrants has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock. 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 has a credit rating change to below investment grade.

183

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(I)

SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity primarily in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $85 million and $239 million for the three and nine months ended September 30, 2011, respectively, and $93 million and $288 million for the three and nine months ended September 30, 2010, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2011:
Operating revenues	$	5,145	$	363	$	(97	)	$	5,411	$	38		$	(21	)	$	5,428
Segment net income (loss)*		862		56		—			918		—			(2	)		916
Nine Months Ended September 30, 2011:
Operating revenues	$	13,246	$	950	$	(288	)	$	13,908	$	114		$	(61	)	$	13,961
Segment net income (loss)*		1,805		138		—			1,943		2			(3	)		1,942
Total assets at September 30, 2011	$	52,949	$	3,757	$	(160	)	$	56,546	$	1,431		$	(634	)	$	57,343
Three Months Ended September 30, 2010:
Operating revenues	$	5,066	$	357	$	(124	)	$	5,299	$	40		$	(19	)	$	5,320
Segment net income (loss)*		756		63		—			819		(1	)		(1	)		817
Nine Months Ended September 30, 2010:
Operating revenues	$	13,127	$	862	$	(367	)	$	13,622	$	122		$	(59	)	$	13,685
Segment net income (loss)*		1,713		109		—			1,822		2			(2	)		1,822
Total assets at December 31, 2010	$	51,144	$	3,438	$	(128	)	$	54,454	$	1,178		$	(600	)	$	55,032

* After dividends on preferred and preference stock of subsidiaries

Products and Services

	Electric Utilities’ Revenues
Period	Retail		Wholesale		Other		Total
			(in millions)
Three Months Ended September 30, 2011	$	4,693	$	557	$	161	$	5,411
Three Months Ended September 30, 2010		4,573		566		160		5,299
Nine Months Ended September 30, 2011	$	11,931	$	1,513	$	464	$	13,908
Nine Months Ended September 30, 2010		11,603		1,581		438		13,622

184

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

185

Item 6. Exhibits.

(2) Plan of acquisition, reorganization, arrangement, liquidation or succession

Mississippi Power
(e)1	-	Assignment and Assumption Agreement dated as of October 20, 2011, between Mississippi Power and Juniper Capital L.P. (Designated in Form 8-K dated October 20, 2011, File No. 001-11229, as Exhibit 2.1.)
(e)2	-	Bond Assumption and Exchange Agreement, dated as of October 20, 2011, by and among Mississippi Business Finance Corporation, Mississippi Power, and the bondholders parties thereto. (Designated in Form 8-K dated October 20, 2011, File No. 001-11229, as Exhibit 2.2.)

(4) Instruments Describing Rights of Security Holders, Including Indentures

Southern Company
(a)1	-	Seventh Supplemental Indenture to Senior Notes Indenture dated as of August 23, 2011, providing for the issuance of the Series 2011A 1.95% Senior Notes due September 1, 2016. (Designated in Form 8-K dated August 16, 2011, File No. 001-03526, as Exhibit 4.2.)
Mississippi Power
(e)1	-	Eleventh Supplemental Indenture to Senior Note Indenture dated as of October 19, 2011, providing for the issuance of the Series 2011A 2.35% Senior Notes due October 15, 2016. (Designated in Form 8-K dated October 11, 2011, File No. 001-11229, as Exhibit 4.2(a).)
(e)2	-	Twelfth Supplemental Indenture to Senior Note Indenture dated as of October 19, 2011, providing for the issuance of the Series 2011B 4.75% Senior Notes due October 15, 2041. (Designated in Form 8-K dated October 11, 2011, File No. 001-11229, as Exhibit 4.2(b).)
Southern Power
(f)1	-	Fourth Supplemental Indenture to Senior Note Indenture dated as of September 22, 2011, providing for the issuance of the Series 2011A 5.150% Senior Notes due September 15, 2041. (Designated in Form 8-K dated September 14, 2011, File No. 333-98553, as Exhibit 4.4.)

(12) Computation of Ratio of Earnings to Fixed Charges

Southern Company
(a)1	Computation of ratio of earnings to fixed charges.
(a)2	Computation of ratio of earnings to fixed charges plus preferred dividend requirements (pre-income tax basis).
Alabama Power
(b)1	Computation of ratio of earnings to fixed charges.
(b)2	Computation of ratio of earnings to fixed charges plus preferred dividend requirements (pre-income tax basis).

186

Georgia Power
(c)1	Computation of ratio of earnings to fixed charges.
(c)2	Computation of ratio of earnings to fixed charges plus preferred dividend requirements (pre-income tax basis).
Gulf Power
(d)1	Computation of ratio of earnings to fixed charges.
(d)2	Computation of ratio of earnings to fixed charges plus preferred dividend requirements (pre-income tax basis).
Mississippi Power
(e)1	Computation of ratio of earnings to fixed charges.
(e)2	Computation of ratio of earnings to fixed charges plus preferred dividend requirements (pre-income tax basis).
Southern Power
(f)1	Computation of ratio of earnings to fixed charges.
(f)2	Computation of ratio of earnings to fixed charges plus preferred dividend requirements (pre-income tax basis).

(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, 2010, 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, 2010, 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, 2010, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)
Gulf Power
(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2010, File No. 001-31737 as Exhibit 24(d)1 and incorporated herein by reference.)
(d)2	-	Power of Attorney Mark A. Crosswhite. (Designated in the Form 10-K for the year ended December 31, 2010, File No. 001-31737 as Exhibit 24(d)2 and incorporated herein by reference.)

187

Mississippi Power
(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2010, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.)
Southern Power
(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2010, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)

(31) Section 302 Certifications

Southern Company
(a)1	-	Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(a)2	-	Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Alabama Power
(b)1	-	Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(b)2	-	Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Georgia Power
(c)1	-	Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(c)2	-	Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Gulf Power
(d)1	-	Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(d)2	-	Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

188

Mississippi Power
(e)1	-	Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(e)2	-	Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
Southern Power
(f)1	-	Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(f)2	-	Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(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.

189

(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

190

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.

		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 7, 2011

191

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.

	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 7, 2011

192

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.

	GEORGIA POWER COMPANY
By	W. Paul Bowers
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Ronnie R. Labrato
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 7, 2011

193

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.

	GULF POWER COMPANY
By	Mark A. Crosswhite
	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 7, 2011

194

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.

	MISSISSIPPI POWER COMPANY
By	Edward Day, VI
	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 7, 2011

195

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.

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

Date: November 7, 2011

196

EX-12

Exhibit 12(a)1

THE SOUTHERN COMPANY

Computation of ratio of earnings to fixed charges for

the five years ended December 31, 2010

and the year to date September 30, 2011

											Nine
											Months
											Ended
	Year ended December 31,										30-Sep
		2006		2007		2008		2009		2010		2011
	-----------------------------------------Millions of Dollars------------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings Before Income Taxes	$	2,446	$	2,641	$	2,711	$	2,604	$	3,066	$	3,114
Interest expense, net of amounts capitalized		868		888		869		907		898		639
Interest component of rental expense		82		80		88		94		112		94
Amortization of capitalized interest		2		2		2		3		3		2
AFUDC - Debt funds		21		48		64		82		74		41
Less: Dividends on preferred and preference stock of subsidiaries		(35)		(48)		(65)		(65)		(65)		(49)
Earnings as defined	$	3,384	$	3,611	$	3,669	$	3,625	$	4,088	$	3,841
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	629	$	743	$	813	$	876	$	885	$	648
Interest on affiliated loans		122		66		23		22		19		14
Interest on interim obligations		77		75		30		4		2		3
Amort of debt disc, premium and expense, net		58		46		40		40		42		31
Other interest charges		3		7		27		46		24		(16)
Capitalized interest		17		17		7		2		12		12
Interest component of rental expense		82		80		87		94		112		94
Fixed charges as defined		988		1,034		1,027		1,084		1,096		786
Tax deductible preferred dividends		1		1		1		1		1		1
		989		1,035		1,028		1,085		1,097		787
Non-tax deductible preferred and preference dividends		33		46		64		64		64		48
Ratio of net income before taxes to net income	x	1.485	x	1.469	x	1.507	x	1.525	x	1.503	x	1.564
Preferred and preference dividend requirements     before income taxes		49		68		96		98		96		75
Fixed charges plus preferred and preference     dividend requirements	$	1,038	$	1,103	$	1,124	$	1,183	$	1,193	$	862
RATIO OF EARNINGS TO FIXED CHARGES		3.26		3.27		3.26		3.06		3.43		4.46

EX-12

Exhibit 12(a)2

THE SOUTHERN COMPANY

Computation of ratio of earnings to fixed charges plus preferred and preference

dividend requirements for the five years ended December 31, 2010

and the year to date September 30, 2011

												Nine
												Months
												Ended
	Year ended December 31,											September 30,
		2006		2007		2008		2009		2010		2011
	----------------------------------------Millions of Dollars-----------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings Before Income Taxes	$	2,446	$	2,641	$	2,711	$	2,604	$	3,066	$	3,114
Interest expense, net of amounts capitalized		868		888		869		907		898		639
Interest component of rental expense		82		80		88		94		112		94
Amortization of capitalized interest		2		2		2		3		3		2
AFUDC - Debt funds		21		48		64		82		74		41
Less: Dividends on preferred and preference stock of subsidiaries		(35)		(48)		(65)		(65)		(65)		(49)
Earnings as defined	$	3,384	$	3,611	$	3,669	$	3,625	$	4,088	$	3,841
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	629		743		813		876		885		648
Interest on affiliated loans		122		66		23		22		19		14
Interest on interim obligations		77		75		30		4		2		3
Amort of debt disc, premium and expense, net		58		46		40		40		42		31
Other interest charges		3		7		27		46		24		(16)
Capitalized interest		17		17		7		2		12		12
Interest component of rental expense		82		80		87		94		112		94
Fixed charges as defined		988		1,034		1,027		1,084		1,096		786
Tax deductible preferred dividends		1		1		1		1		1		1
		989		1,035		1,028		1,085		1,097		787
Non-tax deductible preferred and preference dividends		33		46		64		64		64		48
Ratio of net income before taxes to net income	x	1.485	x	1.469	x	1.507	x	1.525	x	1.503	x	1.564
Preferred and preference dividend requirements     before income taxes		49		68		96		98		96		75
Fixed charges plus preferred and preference     dividend requirements	$	1,038	$	1,103	$	1,124	$	1,183	$	1,193	$	862
RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED DIVIDEND REQUIREMENTS		3.26		3.27		3.26		3.06		3.43		4.46

EX-12

Exhibit 12(b)1

ALABAMA POWER COMPANY

Computation of ratio of earnings to fixed charges for

the five years ended December 31, 2010

and the year to date September 30, 2011

											Nine
											Months
											Ended
	Year ended December 31,										September 30,
		2006		2007		2008		2009		2010		2011
	------------------------------------Millions of Dollars------------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	868	$	962	$	1,018	$	1,088	$	1,204	$	1,037
Distributed income of equity investees		4		1		4		0		2		6
Interest expense, net of amounts capitalized		252		274		279		298		303		224
Interest component of rental expense		45		46		44		40		23		16
AFUDC - Debt funds		8		18		20		33		14		7
Earnings as defined	$	1,177	$	1,301	$	1,365	$	1,459	$	1,546	$	1,290
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	229	$	249	$	263	$	287	$	287	$	211
Interest on affiliated loans		16		15		11		10		7		5
Interest on interim obligations		2		2		1		0		0		0
Amort of debt disc, premium and expense, net		13		14		12		11		10		8
Other interest charges		0		12		12		23		13		7
Interest component of rental expense		45		46		44		40		23		16
Fixed charges as defined	$	305	$	338	$	343	$	371	$	340	$	247
RATIO OF EARNINGS TO FIXED CHARGES		3.86		3.85		3.98		3.93		4.55		5.23

EX-12

Exhibit 12(b)2

ALABAMA POWER COMPANY

Computation of ratio of earnings to fixed charges plus preferred and preference

dividend requirements for the five years ended December 31, 2010

and the year to date September 30, 2011

											Nine
											Months
											Ended
	Year ended December 31,										September 30,
		2006		2007		2008		2009		2010		2011
	-----------------------------------Thousands of Dollars----------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	868	$	962	$	1,018	$	1,088	$	1,204	$	1,037
Distributed income of equity investees		4		1		4		0		2		6
Interest expense, net of amounts capitalized		252		274		279		298		303		224
Interest component of rental expense		45		46		44		40		23		16
AFUDC - Debt funds		8		18		20		33		14		7
Earnings as defined	$	1,177	$	1,301	$	1,365	$	1,459	$	1,546	$	1,290
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	229	$	249	$	263	$	287	$	287	$	211
Interest on affiliated loans		16		15		11		10		7		5
Interest on interim obligations		2		2		1		0		0		0
Amort of debt disc, premium and expense, net		13		14		12		11		10		8
Other interest charges		0		12		12		23		13		7
Interest component of rental expense		45		46		44		40		23		16
Fixed charges as defined		305		338		343		371		340		247
Tax deductible preferred dividends		1		1		1		1		1		1
		306		339		344		372		341		248
Non-tax deductible preferred and preference dividends		24		35		38		38		38		29
Ratio of net income before taxes to net income	x	1.609	x	1.570	x	1.561	x	1.542	x	1.620	x	1.640
Preferred and preference dividend requirements     before income taxes		38		55		60		59		62		47
Fixed charges plus preferred and preference     dividend requirements	$	344	$	394	$	404	$	431	$	403	$	295
RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED
AND PREFERENCE DIVIDEND REQUIREMENTS		3.42		3.30		3.38		3.38		3.83		4.38

EX-12

Exhibit 12(c)1

GEORGIA POWER COMPANY

Computation of ratio of earnings to fixed charges for

the five years ended December 31, 2010

and the year to date September 30, 2011

											Nine
											Months
											Ended
	Year ended December 31,										September 30,
		2006		2007		2008		2009		2010		2011
	----------------------------------------Millions of Dollars-----------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	1,228	$	1,254	$	1,402	$	1,236	$	1,414	$	1,626
Distributed income of equity investees		6		2		4		0		3		6
Interest expense, net of amounts capitalized		318		344		346		386		375		257
Interest component of rental expense		11		10		17		22		43		45
AFUDC - Debt funds		12		29		40		40		54		26
Earnings as defined	$	1,575	$	1,639	$	1,809	$	1,684	$	1,889	$	1,960
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	216	$	269	$	324	$	371	$	377	$	274
Interest on affiliated loans		87		66		22		13		13		9
Interest on interim obligations		0		9		3		1		0		0
Amort of debt disc, premium and expense, net		17		18		20		20		21		17
Other interest charges		10		11		16		20		19		(17)
Interest component of rental expense		11		10		18		22		42		45
Fixed charges as defined	$	341	$	383	$	403	$	447	$	472	$	328
RATIO OF EARNINGS TO FIXED CHARGES		4.61		4.28		4.49		3.76		4.00		5.98

EX-12

Exhibit 12(c)2

GEORGIA POWER COMPANY

Computation of ratio of earnings to fixed charges plus preferred and preference

dividend requirements for the five years ended December 31, 2010

and the year to date September 30, 2011

											Nine
											Months
											Ended
	Year ended December 31,										September 30,
		2006		2007		2008		2009		2010		2011
	-----------------------------------Millions of Dollars-----------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	1,228	$	1,254	$	1,402	$	1,236	$	1,414	$	1,626
Distributed income of equity investees		6		2		4		0		3		6
Interest expense, net of amounts capitalized		318		344		346		386		375		257
Interest component of rental expense		11		10		17		22		43		45
AFUDC - Debt funds		12		29		40		40		54		26
Earnings as defined	$	1,575	$	1,639	$	1,809	$	1,684	$	1,889	$	1,960
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	216	$	269	$	324	$	371	$	377	$	274
Interest on affiliated loans		87		66		22		13		13		9
Interest on interim obligations		0		9		3		1		0		0
Amort of debt disc, premium and expense, net		17		18		20		20		21		17
Other interest charges		10		11		16		20		19		(17)
Interest component of rental expense		11		10		18		22		42		45
Fixed charges as defined		341		383		403		447		472		328
Tax deductible preferred dividends		0		0		0		0		0		0
		341		383		403		447		472		328
Non-tax deductible preferred and preference dividends		5		6		17		17		17		13
Ratio of net income before taxes to net income	x	1.563	x	1.481	x	1.530	x	1.493	x	1.468	x	1.557
Preferred and preference dividend requirements     before income taxes		8		9		26		26		26		20
Fixed charges plus preferred and preference     dividend requirements	$	349	$	392	$	429	$	473	$	498	$	348
RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED
AND PREFERENCE DIVIDEND REQUIREMENTS		4.51		4.19		4.21		3.56		3.80		5.63

EX-12

Exhibit 12(d)1

GULF POWER COMPANY

Computation of ratio of earnings to fixed charges for

the five years ended December 31, 2010

and the year to date September 30, 2011

												Nine
												Months
												Ended
	Year ended December 31,										September 30,
		2006		2007		2008		2009		2010		2011
	--------------------------------------------------Thousands of Dollars--------------------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	124,582	$	135,082	$	158,651	$	170,461	$	199,228	$	143,363
Interest expense, net of amounts capitalized		44,134		44,680		43,098		38,358		51,897		43,208
Interest component of rental expense		1,727		1,574		1,670		6,778		15,984		12,727
AFUDC - Debt funds		160		1,048		3,973		9,489		2,875		2,826
Earnings as defined	$	170,603	$	182,384	$	207,392	$	225,086	$	269,984	$	202,124
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	28,863	$	36,351	$	41,174	$	42,166	$	49,298	$	41,930
Interest on affiliated loans		6,887		4,510		739		80		108		102
Interest on interim obligations		3,713		169		513		701		37		162
Amort of debt disc, premium and expense, net		2,894		2,837		2,755		2,890		2,918		2,017
Other interest charges		1,937		1,861		1,890		2,010		2,411		1,823
Interest component of rental expense		1,727		1,574		1,670		6,778		15,984		12,727
Fixed charges as defined	$	46,021	$	47,302	$	48,741	$	54,625	$	70,756	$	58,761
RATIO OF EARNINGS TO FIXED CHARGES		3.71		3.86		4.25		4.12		3.82		3.44

EX-12

Exhibit 12(d)2

GULF POWER COMPANY

Computation of ratio of earnings to fixed charges plus preferred and preference

dividend requirements for the five years ended December 31, 2010

and the year to date September 30, 2011

												Nine
												Months
												Ended
	Year ended December 31,											September 30,
		2006		2007		2008		2009		2010		2011
	----------------------------------------------Thousands of Dollars-------------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	124,582	$	135,082	$	158,651	$	170,461	$	199,228	$	143,363
Interest expense, net of amounts capitalized		44,134		44,680		43,098		38,358		51,897		43,208
Interest component of rental expense		1,727		1,574		1,670		6,778		15,984		12,727
AFUDC - Debt funds		160		1,048		3,973		9,489		2,875		2,826
Earnings as defined	$	170,603	$	182,384	$	207,392	$	225,086	$	269,984	$	202,124
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	28,863	$	36,351	$	41,174	$	42,166	$	49,298	$	41,930
Interest on affiliated loans		6,887		4,510		739		80		108		102
Interest on interim obligations		3,713		169		513		701		37		162
Amort of debt disc, premium and expense, net		2,894		2,837		2,755		2,890		2,918		2,017
Other interest charges		1,937		1,861		1,890		2,010		2,411		1,823
Interest component of rental expense		1,727		1,574		1,670		6,778		15,984		12,727
Fixed charges as defined		46,021		47,302		48,741		54,625		70,756		58,761
Tax deductible preferred dividends		0		0		0		0		0		0
		46,021		47,302		48,741		54,625		70,756		58,761
Non-tax deductible preferred and preference dividends		3,300		3,881		6,203		6,203		6,203		4,652
Ratio of net income before taxes to net income	x	1.571	x	1.535	x	1.517	x	1.452	x	1.560	x	1.577
Preferred and preference dividend requirements     before income taxes		5,184		5,957		9,410		9,007		9,677		7,336
Fixed charges plus preferred and preference     dividend requirements	$	51,205	$	53,259	$	58,151	$	63,632	$	80,433	$	66,097
RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED
AND PREFERENCE DIVIDEND REQUIREMENTS		3.33		3.42		3.57		3.54		3.36		3.06

EX-12

Exhibit 12(e)1

MISSISSIPPI POWER COMPANY

Computation of ratio of earnings to fixed charges for

the five years ended December 31, 2010

and the year to date September 30, 2011

											Nine
											Months
											Ended
	Year ended December 31,										September 30,
		2006		2007		2008		2009		2010		2011
	--------------------------------------Thousands of Dollars-------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	131,840	$	137,594	$	136,042	$	136,914	$	128,225	$	117,541
Interest expense, net of amounts capitalized		18,640		18,158		17,979		22,940		22,341		15,401
Interest component of rental expense (a)		30,306		30,386		31,139		30,279		30,089		22,172
AFUDC - Debt funds		0		12		229		117		2,903		4,832
Earnings as defined	$	180,786	$	186,150	$	185,389	$	190,250	$	183,558	$	159,946
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	11,808	$	12,440	$	15,467	$	20,620	$	21,795	$	17,376
Interest capitalized as a regulatory asset		10,567		0		0		0		0		0
Interest on affiliated loans		3,881		4,095		730		47		33		14
Interest on interim obligations		1,425		0		0		0		0		0
Amort of debt disc, premium and expense, net		1,061		1,055		1,204		1,399		1,624		1,403
Other interest charges		465		580		807		991		1,792		1,745
Interest component of rental expense (a)		30,306		30,386		31,139		30,279		30,089		22,172
Fixed charges as defined	$	59,513	$	48,556	$	49,347	$	53,336	$	55,333	$	42,710
RATIO OF EARNINGS TO FIXED CHARGES		3.04		3.83		3.76		3.57		3.32		3.74
(a)  Includes the interest component of rentals where determinable plus one-third of remaining rental expense.

EX-12

Exhibit 12(e)2

MISSISSIPPI POWER COMPANY

Computation of ratio of earnings to fixed charges plus preferred

dividend requirements for the five years ended December 31, 2010

and the year to date September 30, 2011

											Nine
											Months
											Ended
	Year ended December 31,										September 30,
		2006		2007		2008		2009		2010		2011
	--------------------------------------Thousands of Dollars--------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	131,840	$	137,594	$	136,042	$	136,914	$	128,225	$	117,541
Interest expense, net of amounts capitalized		18,640		18,158		17,979		22,940		22,341		15,401
Interest component of rental expense (a)		30,306		30,386		31,139		30,279		30,089		22,172
AFUDC - Debt funds		0		12		229		117		2,903		4,832
Earnings as defined	$	180,786	$	186,150	$	185,389	$	190,250	$	183,558	$	159,946
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	11,808	$	12,440	$	15,467	$	20,620	$	21,795	$	17,376
Interest capitalized as a regulatory asset		10,567		0		0		0		0		0
Interest on affiliated loans		3,881		4,095		730		47		33		14
Interest on interim obligations		1,425		0		0		0		0		0
Amort of debt disc, premium and expense, net		1,061		1,055		1,204		1,399		1,624		1,403
Other interest charges		465		580		807		991		1,792		1,745
Interest component of rental expense (a)		30,306		30,386		31,139		30,279		30,089		22,172
Fixed charges as defined		59,513		48,556		49,347		53,336		55,333		42,710
Tax deductible preferred dividends		192		192		192		192		192		144
		59,705		48,748		49,539		53,528		55,525		42,854
Non-tax deductible preferred dividends		1,541		1,541		1,541		1,541		1,541		1,155
Ratio of net income before taxes to net income	x	1.574	x	1.604	x	1.551	x	1.579	x	1.565	x	1.484
Preferred dividend requirements before income taxes		2,426		2,472		2,390		2,433		2,412		1,714
Fixed charges plus preferred dividend requirements	$	62,131	$	51,220	$	51,929	$	55,961	$	57,937	$	44,568
RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED DIVIDEND REQUIREMENTS		2.91		3.63		3.57		3.40		3.17		3.59
(a)  Includes the interest component of rentals where determinable plus one-third of remaining rental expense.

EX-12

Exhibit 12(f)1

SOUTHERN POWER COMPANY

Computation of ratio of earnings to fixed charges for

the five years ended December 31, 2010

and the year to date September 30, 2011

												Nine
												Months
												Ended
	Year ended December 31,										September 30,
		2006		2007		2008		2009		2010		2011
	----------------------------------------Thousands of Dollars----------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	206,280	$	215,185	$	237,251	$	241,515	$	206,665	$	215,999
Interest expense, net of amounts capitalized		80,153		79,175		83,212		84,963		76,120		56,489
Interest component of rental expense		208		155		150		159		176		188
Amortization of capitalized interest		1,540		1,573		2,239		2,885		2,905		2,471
Earnings as defined	$	288,181	$	296,088	$	322,852	$	329,522	$	285,866	$	275,147
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	75,994	$	88,037	$	86,301	$	84,279	$	85,054	$	64,587
Interest on affiliated loans		0		0		0		0		8		534
Interest on interim obligations		8,294		5,414		1,574		(122)		603		1,314
Amort of debt disc, premium and expense, net		1,513		2,169		2,098		2,098		2,098		1,524
Other interest charges		0		96		314		332		467		642
Interest component of rental expense		208		155		150		159		176		188
Fixed charges as defined	$	86,009	$	95,871	$	90,437	$	86,746	$	88,406	$	68,789
RATIO OF EARNINGS TO FIXED CHARGES		3.35		3.09		3.57		3.80		3.23		4.00

EX-12

Exhibit 12(f)2

SOUTHERN POWER COMPANY

Computation of ratio of earnings to fixed charges plus preferred and preference

dividend requirements for the five years ended December 31, 2010

and the year to date September 30, 2011

												Nine
												Months
												Ended
	Year ended December 31,											September 30,
		2006		2007		2008		2009		2010		2011
	-----------------------------------------Thousands of Dollars----------------------------------------
EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K:
Earnings before income taxes	$	206,280	$	215,185	$	237,251	$	241,515	$	206,665	$	215,999
Interest expense, net of amounts capitalized		80,153		79,175		83,212		84,963		76,120		56,489
Interest component of rental expense		208		155		150		159		176		188
Amortization of capitalized interest		1,540		1,573		2,239		2,885		2,905		2,471
Earnings as defined	$	288,181	$	296,088	$	322,852	$	329,522	$	285,866	$	275,147
FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K:
Interest on long-term debt	$	75,994	$	88,037	$	86,301	$	84,279	$	85,054	$	64,587
Interest on affiliated loans		0		0		0		0		8		534
Interest on interim obligations		8,294		5,414		1,574		(122)		603		1,314
Amort of debt disc, premium and expense, net		1,513		2,169		2,098		2,098		2,098		1,524
Other interest charges		0		96		314		332		467		642
Interest component of rental expense		208		155		150		159		176		188
Fixed charges as defined		86,009		95,871		90,437		86,746		88,406		68,789
Tax deductible preferred dividends		0		0		0		0		0		0
		86,009		95,871		90,437		86,746		88,406		68,789
Non-tax deductible preferred and preference dividends		0		0		0		0		0		0
Ratio of net income before taxes to net income	x	1.657	x	1.635	x	1.643	x	1.550	x	1.574	x	1.561
Preferred and preference dividend requirements     before income taxes		0		0		0		0		0		0
Fixed charges plus preferred and preference     dividend requirements	$	86,009	$	95,871	$	90,437	$	86,746	$	88,406	$	68,789
RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED
AND PREFERENCE DIVIDEND REQUIREMENTS		3.35		3.09		3.57		3.80		3.23		4.00

EX-31

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 7, 2011

                      /s/Thomas A. Fanning                   

Thomas A. Fanning

Chairman, President and Chief Executive Officer

EX-31

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 7, 2011

                        /s/Art P. Beattie                         

Art P. Beattie

Executive Vice President and Chief Financial Officer

EX-31

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 7, 2011

            /s/Charles D. McCrary            

Charles D. McCrary

President and Chief Executive Officer

EX-31

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 7, 2011

_____________/s/Philip C. Raymond______________

Philip C. Raymond

Executive Vice President, Chief Financial Officer and Treasurer

EX-31

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 7, 2011

               /s/W. Paul Bowers              

W. Paul Bowers

President and Chief Executive Officer

EX-31

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Ronnie R. Labrato, 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 7, 2011

                 /s/Ronnie R. Labrato                

Ronnie R. Labrato

Executive Vice President, Chief Financial Officer and Treasurer

EX-31

Exhibit 31(d)1

GULF POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, 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 7, 2011

            /s/Mark A. Crosswhite            

Mark A. Crosswhite

President and Chief Executive Officer

EX-31

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 7, 2011

               /s/Richard S. Teel              

Richard S. Teel

Vice President and Chief Financial Officer

EX-31

Exhibit 31(e)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Edward Day, VI, 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 7, 2011

             /s/Edward Day, VI             

Edward Day, VI

President and Chief Executive Officer

EX-31

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 7, 2011

              /s/Moses H. Feagin                

Moses H. Feagin

Vice President, Treasurer and Chief Financial Officer

EX-31

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 7, 2011

              /s/Oscar C. Harper IV             

Oscar C. Harper IV

President and Chief Executive Officer

EX-31

Exhibit 31(f)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Michael W. Southern, 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 7, 2011

             /s/Michael W. Southern              

Michael W. Southern

Senior Vice President, Treasurer and Chief Financial Officer

EX-32

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, 2011, 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, 2011, 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, 2011, 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 7, 2011

EX-32

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, 2011, 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, 2011, 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, 2011, 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 7, 2011

EX-32

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, 2011, 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, 2011, 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, 2011, 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/Ronnie R. Labrato                   

Ronnie R. Labrato

Executive Vice President,

Chief Financial Officer and Treasurer

November 7, 2011

EX-32

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, 2011, 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, 2011, 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, 2011, fairly presents, in all material respects, the financial condition and results of operations of Gulf Power Company.

             /s/Mark A. Crosswhite               

Mark A. Crosswhite

President and Chief Executive Officer

              /s/Richard S. Teel                   

Richard S. Teel

Vice President and Chief Financial Officer

November 7, 2011

EX-32

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, 2011, 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, 2011, 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, 2011, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

               /s/Edward Day, VI                  

Edward Day, VI

President and Chief Executive Officer

               /s/Moses H. Feagin                 

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

November 7, 2011

EX-32

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, 2011, 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, 2011, 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, 2011, 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/Michael W. Southern              

Michael W. Southern

Senior Vice President, Treasurer and

Chief Financial Officer

November 7, 2011

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Operating Activities:
Consolidated net income	$ 1,991,000,000	$ 1,871,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	1,530,000,000	1,377,000,000
Deferred income taxes	914,000,000	573,000,000
Deferred revenues	(2,000,000)	(77,000,000)
Allowance for equity funds used during construction	(113,000,000)	(140,000,000)
Pension, postretirement, and other employee benefits	(1,000,000)	52,000,000
Stock based compensation expense	35,000,000	28,000,000
Generation construction screening costs		(51,000,000)
Other, net	13,000,000	(1,000,000)
Changes in certain current assets and liabilities --
-Receivables	(118,000,000)	(319,000,000)
-Fossil fuel stock	229,000,000	220,000,000
-Other current assets	(45,000,000)	(59,000,000)
-Accounts payable	(155,000,000)	(82,000,000)
-Accrued taxes	440,000,000	118,000,000
-Accrued compensation	(96,000,000)	93,000,000
-Other current liabilities	(24,000,000)	(76,000,000)
Net cash provided from operating activities	4,598,000,000	3,527,000,000
Investing Activities:
Property additions	(3,115,000,000)	(2,894,000,000)
Distribution of restricted cash	61,000,000	25,000,000
Nuclear decommissioning trust fund purchases	(1,946,000,000)	(696,000,000)
Nuclear decommissioning trust fund sales	1,942,000,000	672,000,000
Proceeds from property sales	21,000,000	7,000,000
Cost of removal, net of salvage	(90,000,000)	(84,000,000)
Change in construction payables	137,000,000	(84,000,000)
Other investing activities	92,000,000	48,000,000
Net cash used for investing activities	(2,898,000,000)	(3,006,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(1,160,000,000)	(289,000,000)
Proceeds --
Long-term debt issuances	3,144,000,000	2,796,000,000
Common stock issuances	620,000,000	610,000,000
Redemptions --
Long-term debt	(1,987,000,000)	(1,871,000,000)
Payment of common stock dividends	(1,193,000,000)	(1,114,000,000)
Payment of dividends on preferred and preference stock of subsidiaries	(49,000,000)	(49,000,000)
Other financing activities	(6,000,000)	(35,000,000)
Net cash provided from (used for) financing activities	(631,000,000)	48,000,000
Net Change in Cash and Cash Equivalents	1,069,000,000	569,000,000
Cash and Cash Equivalents at Beginning of Period	447,000,000	690,000,000
Cash and Cash Equivalents at End of Period	1,516,000,000	1,259,000,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2011 and 2010, respectively)	369,000,000	589,000,000
Income taxes (net of refunds)	(358,000,000)	278,000,000
Noncash transactions - accrued property additions at end of period	541,000,000	361,000,000
Alabama Power [Member]
Operating Activities:
Consolidated net income	636,000,000	682,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	562,000,000	519,000,000
Deferred income taxes	350,000,000	301,000,000
Allowance for equity funds used during construction	(18,000,000)	(29,000,000)
Pension, postretirement, and other employee benefits	(17,000,000)	(9,000,000)
Stock based compensation expense	5,000,000	4,000,000
Other, net	6,000,000	29,000,000
Changes in certain current assets and liabilities --
-Receivables	(74,000,000)	(110,000,000)
-Fossil fuel stock	75,000,000	21,000,000
-Materials and supplies	(13,000,000)	(10,000,000)
-Other current assets	(19,000,000)	(34,000,000)
-Accounts payable	(120,000,000)	(66,000,000)
-Accrued taxes	215,000,000	(48,000,000)
-Accrued compensation	(35,000,000)	8,000,000
-Other current liabilities	5,000,000	(103,000,000)
Net cash provided from operating activities	1,558,000,000	1,155,000,000
Investing Activities:
Property additions	(694,000,000)	(685,000,000)
Distribution of restricted cash from pollution control revenue bonds	11,000,000	18,000,000
Nuclear decommissioning trust fund purchases	(301,000,000)	(126,000,000)
Nuclear decommissioning trust fund sales	301,000,000	126,000,000
Cost of removal, net of salvage	(52,000,000)	(26,000,000)
Change in construction payables	(13,000,000)	(34,000,000)
Other investing activities	14,000,000	(9,000,000)
Net cash used for investing activities	(734,000,000)	(736,000,000)
Proceeds --
Capital contributions from parent company	10,000,000	19,000,000
Senior note issuances	700,000,000
Redemptions --
Pollution control revenue bonds	(4,000,000)
Senior notes	(650,000,000)
Payment of preferred and preference stock dividends	(30,000,000)	(30,000,000)
Payment of common stock dividends	(415,000,000)	(407,000,000)
Other financing activities	(13,000,000)	(1,000,000)
Net cash provided from (used for) financing activities	(402,000,000)	(419,000,000)
Net Change in Cash and Cash Equivalents	422,000,000
Cash and Cash Equivalents at Beginning of Period	154,000,000	368,000,000
Cash and Cash Equivalents at End of Period	576,000,000	368,000,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2011 and 2010, respectively)	207,000,000	214,000,000
Income taxes (net of refunds)	(95,000,000)	212,000,000
Noncash transactions - accrued property additions at end of period	15,000,000	39,000,000
Georgia Power [Member]
Operating Activities:
Consolidated net income	1,048,000,000	909,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	646,000,000	551,000,000
Deferred income taxes	422,000,000	225,000,000
Deferred revenues		(77,000,000)
Deferred expenses	(30,000,000)	(54,000,000)
Allowance for equity funds used during construction	(73,000,000)	(105,000,000)
Pension, postretirement, and other employee benefits	2,000,000	20,000,000
Stock based compensation expense	7,000,000	5,000,000
Other, net	(47,000,000)	(10,000,000)
Changes in certain current assets and liabilities --
-Receivables	(68,000,000)	(126,000,000)
-Fossil fuel stock	115,000,000	153,000,000
-Prepaid income taxes	81,000,000	2,000,000
-Other current assets	(2,000,000)	4,000,000
-Accounts payable	(46,000,000)	61,000,000
-Accrued taxes	(1,000,000)	66,000,000
-Accrued compensation	(18,000,000)	45,000,000
-Other current liabilities	43,000,000	38,000,000
Net cash provided from operating activities	2,079,000,000	1,707,000,000
Investing Activities:
Property additions	(1,363,000,000)	(1,628,000,000)
Nuclear decommissioning trust fund purchases	(1,645,000,000)	(570,000,000)
Nuclear decommissioning trust fund sales	1,641,000,000	546,000,000
Cost of removal, net of salvage	(21,000,000)	(46,000,000)
Change in construction payables, net of joint owner portion	108,000,000	27,000,000
Other investing activities	(9,000,000)	5,000,000
Net cash used for investing activities	(1,289,000,000)	(1,666,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(575,000,000)	(321,000,000)
Proceeds --
Capital contributions from parent company	199,000,000	681,000,000
Pollution control revenue bonds	604,000,000
Senior note issuances	550,000,000	1,950,000,000
Other long-term debt issuances	250,000,000
Redemptions --
Pollution control revenue bonds	(286,000,000)
Senior notes	(277,000,000)	(1,112,000,000)
Other long-term debt	(509,000,000)	(3,000,000)
Payment of preferred and preference stock dividends	(13,000,000)	(13,000,000)
Payment of common stock dividends	(672,000,000)	(615,000,000)
Other financing activities	(3,000,000)	(32,000,000)
Net cash provided from (used for) financing activities	(732,000,000)	535,000,000
Net Change in Cash and Cash Equivalents	58,000,000	576,000,000
Cash and Cash Equivalents at Beginning of Period	8,000,000	14,000,000
Cash and Cash Equivalents at End of Period	66,000,000	590,000,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2011 and 2010, respectively)	240,000,000	231,000,000
Income taxes (net of refunds)	(2,000,000)	107,000,000
Noncash transactions - accrued property additions at end of period	375,000,000	261,000,000
Gulf Power [Member]
Operating Activities:
Consolidated net income	90,912,000	105,176,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	101,335,000	95,491,000
Deferred income taxes	56,869,000	55,355,000
Allowance for equity funds used during construction	(7,091,000)	(4,504,000)
Pension, postretirement, and other employee benefits	(179,000)	2,883,000
Stock based compensation expense	1,055,000	959,000
Other, net	(5,787,000)	2,570,000
Changes in certain current assets and liabilities --
-Receivables	(13,605,000)	(67,814,000)
-Prepayments	7,745,000	2,667,000
-Fossil fuel stock	36,802,000	29,483,000
-Materials and supplies	(6,382,000)	(1,363,000)
-Prepaid income taxes	36,081,000	(9,558,000)
-Property damage cost recovery		34,000
-Other current assets	(571,000)
-Accounts payable	(65,000)	12,003,000
-Accrued taxes	22,186,000	18,166,000
-Accrued compensation	(4,290,000)	2,695,000
-Other current liabilities	10,284,000	10,776,000
Net cash provided from operating activities	325,299,000	255,019,000
Investing Activities:
Property additions	(228,696,000)	(203,911,000)
Distribution of restricted cash from pollution control revenue bonds		6,347,000
Cost of removal, net of salvage	(9,137,000)	(750,000)
Change in construction payables	636,000	(17,792,000)
Payments pursuant to long-term service agreements	(6,173,000)	(4,211,000)
Other investing activities	303,000	(295,000)
Net cash used for investing activities	(243,067,000)	(220,612,000)
Financing Activities:
Increase (decrease) in notes payable, net	(56,607,000)	(88,733,000)
Proceeds --
Capital contributions from parent company	1,569,000	3,571,000
Pollution control revenue bonds		21,000,000
Common stock issuances	50,000,000	50,000,000
Senior note issuances	125,000,000	300,000,000
Redemptions --
Senior notes	(553,000)	(140,413,000)
Other long-term debt	(110,000,000)
Payment of preferred and preference stock dividends	(4,652,000)	(4,652,000)
Payment of common stock dividends	(82,500,000)	(78,225,000)
Other financing activities	(3,593,000)	(3,280,000)
Net cash provided from (used for) financing activities	(81,336,000)	59,268,000
Net Change in Cash and Cash Equivalents	896,000	93,675,000
Cash and Cash Equivalents at Beginning of Period	16,434,000	8,677,000
Cash and Cash Equivalents at End of Period	17,330,000	102,352,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2011 and 2010, respectively)	36,427,000	28,394,000
Income taxes (net of refunds)	(46,319,000)	13,862,000
Noncash transactions - accrued property additions at end of period	15,820,000	28,670,000
Mississippi Power [Member]
Operating Activities:
Consolidated net income	79,218,000	65,364,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	64,329,000	60,959,000
Deferred income taxes	35,225,000	(4,557,000)
Convertible investment tax credits received	51,761,000	14,352,000
Allowance for equity funds used during construction	(15,413,000)	(2,018,000)
Pension, postretirement, and other employee benefits	3,327,000	6,657,000
Stock based compensation expense	1,302,000	1,053,000
Generation construction screening costs		(50,554,000)
Other, net	(7,642,000)	(720,000)
Changes in certain current assets and liabilities --
-Receivables	(5,295,000)	(21,003,000)
-Fossil fuel stock	2,345,000	10,163,000
-Materials and supplies	(1,442,000)	(222,000)
-Prepaid income taxes	(18,762,000)
-Other current assets	2,295,000	(2,503,000)
-Accounts payable	21,711,000	25,819,000
-Accrued taxes	(3,751,000)	7,630,000
-Accrued compensation	(4,514,000)	427,000
-Over recovered regulatory clause revenues	(17,754,000)	14,939,000
-Other current liabilities	(296,000)	(442,000)
Net cash provided from operating activities	186,644,000	125,344,000
Investing Activities:
Property additions	(605,710,000)	(125,980,000)
Capital grant proceeds	139,921,000
Distribution of restricted cash	50,000,000
Cost of removal, net of salvage	(6,931,000)	(7,613,000)
Change in construction payables	70,909,000	6,903,000
Other investing activities	(3,399,000)	(6,693,000)
Net cash used for investing activities	(355,210,000)	(133,383,000)
Proceeds --
Capital contributions from parent company	199,782,000	3,920,000
Other long-term debt issuances	115,000,000	125,000,000
Redemptions --
Capital leases	(1,067,000)	(988,000)
Other long-term debt	(130,000,000)
Payment of preferred and preference stock dividends	(1,299,000)	(1,299,000)
Payment of common stock dividends	(56,625,000)	(51,450,000)
Other financing activities	(377,000)	(614,000)
Net cash provided from (used for) financing activities	125,414,000	74,569,000
Net Change in Cash and Cash Equivalents	(43,152,000)	66,530,000
Cash and Cash Equivalents at Beginning of Period	160,779,000	65,025,000
Cash and Cash Equivalents at End of Period	117,627,000	131,555,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2011 and 2010, respectively)	13,956,000	16,726,000
Income taxes (net of refunds)	(33,276,000)	11,345,000
Noncash transactions - accrued property additions at end of period	109,732,000	10,592,000
Southern Power [Member]
Operating Activities:
Consolidated net income	138,415,000	108,867,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	102,756,000	97,469,000
Deferred income taxes	474,000	10,001,000
Convertible investment tax credits received	62,298,000	22,150,000
Deferred revenues	8,114,000	18,846,000
Mark-to-market adjustments	1,479,000	2,435,000
Other, net	3,790,000	2,364,000
Changes in certain current assets and liabilities --
-Receivables	(24,799,000)	(35,588,000)
-Fossil fuel stock	305,000	6,097,000
-Materials and supplies	(1,826,000)	3,216,000
-Prepaid income taxes	24,436,000	1,668,000
-Other current assets	219,000	598,000
-Accounts payable	(2,634,000)	(1,988,000)
-Accrued taxes	27,417,000	31,069,000
Accrued interest	(11,601,000)	(12,194,000)
-Other current liabilities	(661,000)	21,000
Net cash provided from operating activities	328,182,000	255,031,000
Investing Activities:
Property additions	(200,157,000)	(211,519,000)
Change in construction payables	(14,667,000)	31,021,000
Payments pursuant to long-term service agreements	(46,065,000)	(30,936,000)
Other investing activities	(3,211,000)	3,752,000
Net cash used for investing activities	(264,100,000)	(207,682,000)
Financing Activities:
Increase (decrease) in notes payable, net	(220,903,000)	20,216,000
Proceeds --
Capital contributions from parent company	125,596,000	5,638,000
Senior note issuances	300,000,000
Redemptions --
Other long-term debt	(3,441,000)
Payment of common stock dividends	(68,400,000)	(80,325,000)
Other financing activities	(5,629,000)	426,000
Net cash provided from (used for) financing activities	127,223,000	(54,045,000)
Net Change in Cash and Cash Equivalents	191,305,000	(6,696,000)
Cash and Cash Equivalents at Beginning of Period	14,204,000	7,152,000
Cash and Cash Equivalents at End of Period	205,509,000	456,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2011 and 2010, respectively)	65,201,000	63,560,000
Income taxes (net of refunds)	(26,555,000)	(8,158,000)
Noncash transactions - accrued property additions at end of period	$ 36,971,000	$ 36,576,000

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Supplemental Cash Flow Information:
Net cash paid for capitalized interest	$ 54,000	$ 61,000
Alabama Power [Member]
Supplemental Cash Flow Information:
Net cash paid for capitalized interest	7,000	11,000
Georgia Power [Member]
Supplemental Cash Flow Information:
Net cash paid for capitalized interest	27,000	39,000
Gulf Power [Member]
Supplemental Cash Flow Information:
Net cash paid for capitalized interest	2,826	1,795
Mississippi Power [Member]
Supplemental Cash Flow Information:
Net cash paid for capitalized interest	5,136	1,482
Southern Power [Member]
Supplemental Cash Flow Information:
Net cash paid for capitalized interest	$ 12,112	$ 7,704

XML

Effective Tax Rate and Unrecognized Tax Benefits (Tables)

9 Months Ended

Sep. 30, 2011

Effective Tax Rate and Unrecognized Tax Benefits [Abstract]

Changes for unrecognized tax benefits

	Southern			Alabama			Georgia			Gulf			Mississippi			Southern
	Company			Power			Power			Power			Power			Power
							(in millions)
Unrecognized tax benefits as of December 31, 2010	$	296		$	43		$	237		$	4		$	4		$	2
Tax positions from current periods		43			2			7			1			1			1
Tax positions from prior periods		(108	)		(18	)		(87	)		(2	)		(1	)		—
Reductions due to settlements		(112	)		—			(112	)		—			—			—
Reductions due to expired statute of limitations		—			—			—			—			—			—
Balance as of September 30, 2011	$	119		$	27		$	45		$	3		$	4		$	3

Impact on effective tax rate

							As of
							December 31,
	As of September 30, 2011						2010
	Georgia		Other		Southern		Southern
	Power		Registrants		Company		Company
			(in millions)
Tax positions impacting the effective tax rate	$	28	$	12	$	76	$	217
Tax positions not impacting the effective tax rate		17		25		43		79
Balance of unrecognized tax benefits	$	45	$	37	$	119	$	296

Accrued interest for unrecognized tax benefits

	Georgia			Other		Southern
	Power			Registrants		Company
	(in millions)
Interest accrued as of December 31, 2010	$	27		$	2	$	29
Interest reclassified due to settlements		(24	)		—		(24	)
Interest accrued during the period		2			1		4
Balance as of September 30, 2011	$	5		$	3	$	9

XML

Document and Entity Information (USD $) In Billions, except Share data	9 Months Ended
	Sep. 30, 2011	Jun. 30, 2010
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 27.6
Entity Common Stock, Shares Outstanding	861,928,103

XML

Introduction (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Introduction [Abstract]
Total original notional amount of the guarantees	$ 120
Current guarantee obligations outstanding	12
Short term obligations outstanding	3
Long term obligations outstanding	9
Maximum Range of the term of leveraged lease agreements	45 years
Expected potential impairment loss on abandonment of the project	$ 80

XML

Stockholders Equity

9 Months Ended

Sep. 30, 2011

Stockholders' Equity [Abstract]

STOCKHOLDERS' EQUITY

(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 further 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		Three Months		Nine Months		Nine Months
	Ended		Ended		Ended		Ended
	September 30, 2011		September 30, 2010		September 30, 2011		September 30, 2010
	(in millions)
As reported shares		860		836		854		829
Effect of options		8		6		7		4
Diluted shares		868		842		861		833

Stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive were 0.4 million and 6.7 million for the three months ended September 30, 2011 and 2010, respectively, and 0.4 million and 13.7 million for the nine months ended September 30, 2011 and 2010, respectively. Assuming an average stock price of $40.14 (the highest exercise price of the anti-dilutive options outstanding in 2011), there would be no effect on stock options for the three and nine months ended September 30, 2011. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding in 2010), the effect of options would have increased by 0.4 million and 0.8 million shares for the three and nine months ended September 30, 2010, respectively.

Changes in Stockholders’ Equity

The following table presents year-to-date changes in stockholders’ equity of Southern Company:

									Preferred and
	Number of					Common			Preference		Total
	Common Shares					Stockholders’			Stock of		Stockholders’
	Issued		Treasury			Equity			Subsidiaries		Equity
	(in thousands)								(in millions)
Balance at December 31, 2010		843,814		(474	)	$	16,202		$	707	$	16,909
Net income after dividends on preferred and preference stock		—		—			1,942			—		1,942
Other comprehensive income (loss)		—		—			(11	)		—		(11	)
Stock issued		18,634		—			692			—		692
Cash dividends on common stock		—		—			(1,193	)		—		(1,193	)
Other		—		(45	)		1			—		1
Balance at September 30, 2011		862,448		(519	)	$	17,633		$	707	$	18,340
Balance at December 31, 2009		820,152		(505	)	$	14,878		$	707	$	15,585
Net income after dividends on preferred and preference stock		—		—			1,822			—		1,822
Other comprehensive income (loss)		—		—			16			—		16
Stock issued		18,994		—			650			—		650
Cash dividends on common stock		—		—			(1,114	)		—		(1,114	)
Other		—		30			3			—		3
Balance at September 30, 2010		839,146		(475	)	$	16,255		$	707	$	16,962

XML

Contingencies and Regulatory Matters (Details Textual) (USD $)	1 Months Ended		9 Months Ended	1 Months Ended		6 Months Ended	9 Months Ended	1 Months Ended	9 Months Ended					9 Months Ended		1 Months Ended		9 Months Ended	12 Months Ended									9 Months Ended		9 Months Ended
	Apr. 30, 2009 Potentially_Responsible_Party	Jul. 31, 2004 Other_Power_Companies Environmental_Groups	Sep. 30, 2011	Sep. 30, 2010 Alabama Power [Member] Claims	Jul. 31, 2007 Alabama Power [Member]	Jun. 30, 2011 Alabama Power [Member]	Sep. 30, 2011 Alabama Power [Member] Coal_Fired_Generating_Facilities	Jul. 31, 2007 Georgia Power [Member]	Sep. 30, 2011 Georgia Power [Member] Megawatt Million_British_Thermal_Unit	Aug. 26, 2011 Georgia Power [Member]	Aug. 16, 2011 Georgia Power [Member]	Jun. 10, 2011 Georgia Power [Member]	May 24, 2011 Georgia Power [Member]	Sep. 30, 2011 Gulf Power [Member]	Jul. 08, 2011 Gulf Power [Member]	Nov. 30, 2010 Mississippi Power [Member]	May 31, 2009 Mississippi Power [Member]	Sep. 30, 2011 Mississippi Power [Member]	Dec. 31, 2008 Mississippi Power [Member]	Oct. 19, 2011 Mississippi Power [Member]	Sep. 09, 2011 Mississippi Power [Member] mi	May 05, 2011 Mississippi Power [Member]	Apr. 19, 2011 Mississippi Power [Member]	Mar. 04, 2011 Mississippi Power [Member]	Jan. 31, 2011 Mississippi Power [Member]	Dec. 31, 2010 Mississippi Power [Member]	Aug. 19, 2010 Mississippi Power [Member]	Sep. 30, 2011 Mississippi Power [Member] MRA Revenue [Member]	Dec. 31, 2010 Mississippi Power [Member] MRA Revenue [Member]	Sep. 30, 2011 Mississippi Power [Member] MB Revenue [Member]	Dec. 31, 2010 Mississippi Power [Member] MB Revenue [Member]	Sep. 30, 2011 Gulf Power and Mississippi Power [Member]	Sep. 30, 2011 Southern Company and Gulf Power [Member]	Dec. 31, 2010 Southern Company and Gulf Power [Member]	Sep. 30, 2011 Southern Company and Alabama Power [Member]	Dec. 31, 2010 Southern Company and Alabama Power [Member]
Contingencies and Regulatory Matters (Textual) [Abstract]
Number of coal fired generating facilities at which new source review violations occurred							8
Number of dismissed claims against Alabama Power				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, lower range			$ 25,000
Civil penalties under Clean Air Act per day, upper range			37,500
No. of environmental group which filed complaint against the Southern Company		3
Number other electric power companies against which complaint is filed		4
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									14,000,000					62,000,000
Number of PRPs filed separate actions	2
Agreements with plaintiffs in pending actions (in percentage)																		95.00%
Civil penalties per violation rate									37,500
Claims awarded to companies related to nuclear fuel disposal litigation					17,000,000			30,000,000
Unrecognized tax benefits of additional tax benefits recorded												64,000,000
Related regulatory liability												62,000,000
Reduction in related interest expense												23,000,000
Anticipates of elimination adjustment will result in additional revenues							30,000,000
Anticipates of elimination adjustment will result in additional revenues with an annual effect							150,000,000
Capacity of units used by Georgia Power to control fuel switch or retire remaining fossil generating units where environmental controls not yet install									2,600
Capacity of units used by Georgia Power more likely than others to switch fuel or control in time to comply with utility MACT Rule									600
Currently available capacity of unit not rely by Georgia Power in 2015									2,000
Capacity of units include application request by Georgia Power that country PSC certify purchase from four PPAs selected through 2015 request for proposal process									1,562
Estimated cost of scrubber project																		312,500,000														625,000,000
Scrubber project expenditures amount																		17,900,000														35,800,000
Ownership percentage in Scrubber project														50.00%				50.00%
Condition for adjustment to the fuel cost recovery														If the projected fuel cost over or under recovery balance at year-end exceeds 10% of the projected fuel revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.
Under recovered fuel cost																																	7,500,000	17,400,000	39,000,000	4,000,000
Condition for adjustment to purchased power capacity recovery														If the projected purchased power capacity cost over or under recovery balance at year-end exceeds 10% of the projected purchased power capacity revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the purchased power capacity cost recovery factor is being requested.
Over recovered purchased power capacity costs																																	3,500,000	4,400,000
Approved amount for scrubber project																						19,500,000
Over recovered environmental cost																																	16,900,000	10,400,000
Amount approved for property damage reserve																									3,600,000
Increase (decrease) in annual revenues																		900,000
Percentage decrease in prior year annual retail revenue amount due to retail fuel cost recovery factor																		5.00%
Amount of over recovered retail fuel costs included in the balance sheets																		41,400,000								55,200,000
Amount of over recovered MRA emissions allowance cost included in the balance sheets																		1,000,000
Estimated cost associated with repairing damage facility to operation and maintenance expenses						45,000,000
Estimated cost associated with repairing damage facility to capital expenditure						163,000,000
Accumulated NDR reserve reflected as other regulatory liabilities, deferred																																			75,000,000
Establishment period														5 years
Conservation goals covering period														10 years
Percentage rate increase																1.936%
Rate increase amount																16,100,000
Percentage decrease in fuel rates requested with Georgia Public Service Commission													0.61%
Expected decrease in annual billings for fuel costs													43,000,000
Cost deferred in other regulatory assets																		19,000,000
Previously expensed																		1,000,000
Construction and capital costs included in semi-annual construction monitoring report made on Plant Vogtle Units 3 and 4											1,300,000,000
Projected financing costs to recover due to legislation									1,700,000,000
Reduction in projected in-service cost									4,400,000,000
Amortization to earnings of financing costs capitalized over the five year period									91,000,000
Costs included in CWIP									78,000,000									463,800,000
Expected Number of Days for the Issuance of Construction and Operating Licenses by the NRC staff									10 days
Approval pending in percentage to increase current certified amount										4.60%
Generate additional gross annual revenues														38,500,000
Retail rate of return on common equity															11.70%
Generate additional gross annual revenues															93,500,000
Tax credits (Phase I)																	133,000,000
Tax credits (Phase II)																							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%
Accrued tax benefits on tax credits																		73,900,000
Agreement reached to assign the remaining funds to the Kemper IGCC																			270,000,000
Grant funds assigned to receive during initial operations of plant																											25,000,000
Grant funds assigned to receive during construction of plant																			245,000,000
Grant received for plant																		158,600,000
Additional billed grant for plant																				20,900,000
Percentage of Carbon dioxide captured from project by purchase Denbury																								70.00%
Percentage of contract to purchase carbon dioxide from Kemper IGCC																								30.00%
New Co2 Pipeline Infrastructure																					61
Estimated cost of pipeline infrastructure																					141,000,000
Estimated capital cost of mine																					245,000,000
Cost incurred by Mississippi Power associated with plant including regulatory filing costs																		664,900,000
Costs associated with CCP12 grant funds																		179,500,000
Other deferred charges and assets																		1,600,000
Cash Payment to be Made in Conjunction with Purchase of Facility																		85,000,000
Fixed stated interest rate of debt obligation																		7.13%
Percentage annual decrease in revenue amount due to decrease in wholesale fuel rate																												3.50%		7.00%
Amount of over recovered fuel costs																												14,600,000	17,500,000	2,300,000	4,400,000
Fair value of debt assumed in Plant Daniel Combined Cycle Generating Units																		346,000,000
Amount of Facility reflected in Southern Company and Mississippi Power financial statements																		431,000,000
Lesser obligation related to aggregate principal amount			$ 270,000,000

XML

Segment and Related Information (Details 1) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Financial data for Products and Services
Electric Utilities Revenues	$ 5,411	$ 5,299	$ 13,908	$ 13,622
Retail [Member]
Financial data for Products and Services
Electric Utilities Revenues	4,693	4,573	11,931	11,603
Wholesale [Member]
Financial data for Products and Services
Electric Utilities Revenues	557	566	1,513	1,581
Other Electric Revenue [Member]
Financial data for Products and Services
Electric Utilities Revenues	$ 161	$ 160	$ 464	$ 438

XML

Derivatives (Details) In Millions, unless otherwise specified	9 Months Ended					9 Months Ended		9 Months Ended		9 Months Ended										9 Months Ended
	Sep. 30, 2011 USD ($)	Sep. 30, 2011 Alabama Power [Member] USD ($)	Sep. 30, 2011 Alabama Power [Member] Gas [Member] Million_British_Thermal_Unit	Sep. 30, 2011 Alabama Power [Member] Cash Flow Hedging [Member] Interest Rate Contract Two [Member] USD ($)	Sep. 30, 2011 Alabama Power [Member] Interest Rate Contract Two [Member] USD ($)	Sep. 30, 2011 Georgia Power [Member] USD ($)	Sep. 30, 2011 Georgia Power [Member] Gas [Member] Million_British_Thermal_Unit	Sep. 30, 2011 Gulf Power [Member] USD ($)	Sep. 30, 2011 Gulf Power [Member] Gas [Member] Million_British_Thermal_Unit	Sep. 30, 2011 Mississippi Power [Member] USD ($)	Sep. 30, 2011 Mississippi Power [Member] Gas [Member] Million_British_Thermal_Unit	Sep. 30, 2011 Mississippi Power [Member] Cash Flow Hedging [Member] Interest Rate Contract Three [Member] USD ($)	Sep. 30, 2011 Mississippi Power [Member] Cash Flow Hedging [Member] Interest Rate Contract Four [Member]	Sep. 30, 2011 Mississippi Power [Member] Cash Flow Hedging [Member] Interest Rate Contract Five [Member] USD ($)	Sep. 30, 2011 Mississippi Power [Member] Fair Value Hedging [Member] USD ($)	Sep. 30, 2011 Mississippi Power [Member] Fair Value Hedging [Member] EUR (€)	Sep. 30, 2011 Mississippi Power [Member] Interest Rate Contract Three [Member] USD ($)	Sep. 30, 2011 Mississippi Power [Member] Interest Rate Contract Four [Member] USD ($)	Sep. 30, 2011 Mississippi Power [Member] Interest Rate Contract Five [Member] USD ($)	Sep. 30, 2011 Southern Power [Member] USD ($)	Sep. 30, 2011 Southern Power [Member] Power [Member] Megawatt	Sep. 30, 2011 Southern Power [Member] Gas [Member] Million_British_Thermal_Unit	Sep. 30, 2011 Power [Member] Megawatt	Sep. 30, 2011 Gas [Member] Million_British_Thermal_Unit	Sep. 30, 2011 Cash Flow Hedging [Member] Interest Rate Contract One [Member] USD ($)	Sep. 30, 2011 Fair Value Hedging [Member] USD ($)	Sep. 30, 2011 Interest Rate Contract One [Member] USD ($)
Energy-related derivative contracts
Net Sold MWHs																					300,000		300,000
Net Purchased mmBtu			31,000,000				66,000,000		26,000,000		31,000,000											7,000,000		160,000,000
Longest Hedge Date			2015				2015		2015		2015											2012		2015
Longest Non-Hedge Date																					2011	2015	2011	2015
Notional amount of interest rate derivatives
Notional Amount, Fair Value	$ 350
Notional Amount					300												150	150	300								300
Notional Amount of interest rate derivatives, Total	1,550
Interest Rate Received				3-month LIBOR								3-month LIBOR	3-month LIBOR	3-month LIBOR											3-month LIBOR + 0.40% spread	0.0415
Interest Rate Paid				0.0290								0.0237	0.0125	0.0266											0.0124	3-month LIBOR + 1.96%* spread
Hedge Maturity Date				Dec. 01, 2022								Sep. 01, 2021	Sep. 01, 2016	Apr. 01, 2022											Oct. 01, 2011	May 01, 2014
Fair Value Gain (Loss) September 30, 2011	(11)			(12)								(4)		(11)											0	16
Total deferred gains and losses are expected to be amortized into earnings
Estimated Gain (Loss) to be Reclassified for the 12 Months Ending September 30, 2012	(16)	0				(3)		(1)		(1)										(11)
Total Deferred Gains (Losses) Amortized Through	2037	2035				2037		2020		2022										2016
Notional amount of foreign currency derivatives
Notional Amount																28.3
Average Forward Rate															1.297	1.297
Hedge Maturity Date															Various through March 2014	Various through March 2014
Fair Value Gain (Loss) September 30, 2011															$ 1

XML

Segment and Related Information (Tables)

9 Months Ended

Sep. 30, 2011

Segment and Related Information [Abstract]

Financial data for business segments

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2011:
Operating revenues	$	5,145	$	363	$	(97	)	$	5,411	$	38		$	(21	)	$	5,428
Segment net income (loss)*		862		56		—			918		—			(2	)		916
Nine Months Ended September 30, 2011:
Operating revenues	$	13,246	$	950	$	(288	)	$	13,908	$	114		$	(61	)	$	13,961
Segment net income (loss)*		1,805		138		—			1,943		2			(3	)		1,942
Total assets at September 30, 2011	$	52,949	$	3,757	$	(160	)	$	56,546	$	1,431		$	(634	)	$	57,343
Three Months Ended September 30, 2010:
Operating revenues	$	5,066	$	357	$	(124	)	$	5,299	$	40		$	(19	)	$	5,320
Segment net income (loss)*		756		63		—			819		(1	)		(1	)		817
Nine Months Ended September 30, 2010:
Operating revenues	$	13,127	$	862	$	(367	)	$	13,622	$	122		$	(59	)	$	13,685
Segment net income (loss)*		1,713		109		—			1,822		2			(2	)		1,822
Total assets at December 31, 2010	$	51,144	$	3,438	$	(128	)	$	54,454	$	1,178		$	(600	)	$	55,032

* After dividends on preferred and preference stock of subsidiaries

Financial data for products and services

	Electric Utilities’ Revenues
Period	Retail		Wholesale		Other		Total
			(in millions)
Three Months Ended September 30, 2011	$	4,693	$	557	$	161	$	5,411
Three Months Ended September 30, 2010		4,573		566		160		5,299
Nine Months Ended September 30, 2011	$	11,931	$	1,513	$	464	$	13,908
Nine Months Ended September 30, 2010		11,603		1,581		438		13,622

XML

Segment and Related Information

9 Months Ended

Sep. 30, 2011

Segment and Related Information [Abstract]

SEGMENT AND RELATED INFORMATION

(I)

SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity primarily in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $85 million and $239 million for the three and nine months ended September 30, 2011, respectively, and $93 million and $288 million for the three and nine months ended September 30, 2010, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2011:
Operating revenues	$	5,145	$	363	$	(97	)	$	5,411	$	38		$	(21	)	$	5,428
Segment net income (loss)*		862		56		—			918		—			(2	)		916
Nine Months Ended September 30, 2011:
Operating revenues	$	13,246	$	950	$	(288	)	$	13,908	$	114		$	(61	)	$	13,961
Segment net income (loss)*		1,805		138		—			1,943		2			(3	)		1,942
Total assets at September 30, 2011	$	52,949	$	3,757	$	(160	)	$	56,546	$	1,431		$	(634	)	$	57,343
Three Months Ended September 30, 2010:
Operating revenues	$	5,066	$	357	$	(124	)	$	5,299	$	40		$	(19	)	$	5,320
Segment net income (loss)*		756		63		—			819		(1	)		(1	)		817
Nine Months Ended September 30, 2010:
Operating revenues	$	13,127	$	862	$	(367	)	$	13,622	$	122		$	(59	)	$	13,685
Segment net income (loss)*		1,713		109		—			1,822		2			(2	)		1,822
Total assets at December 31, 2010	$	51,144	$	3,438	$	(128	)	$	54,454	$	1,178		$	(600	)	$	55,032

* After dividends on preferred and preference stock of subsidiaries

Products and Services

	Electric Utilities’ Revenues
Period	Retail		Wholesale		Other		Total
			(in millions)
Three Months Ended September 30, 2011	$	4,693	$	557	$	161	$	5,411
Three Months Ended September 30, 2010		4,573		566		160		5,299
Nine Months Ended September 30, 2011	$	11,931	$	1,513	$	464	$	13,908
Nine Months Ended September 30, 2010		11,603		1,581		438		13,622

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Qualifying hedges:
Changes in fair value of qualifying hedges, tax	$ (10,000,000)		$ (8,000,000)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	2,000,000	4,000,000	4,000,000	10,000,000
Marketable securities:
Change in fair value of marketable securities, tax	(2,000,000)		(1,000,000)
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	2,000,000	1,000,000	2,000,000	1,000,000
Alabama Power [Member]
Qualifying hedges:
Changes in fair value of qualifying hedges, tax	(4,000,000)		(3,000,000)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax			(1,000,000)
Georgia Power [Member]
Qualifying hedges:
Reclassification adjustment for amounts of qualifying hedges included in net income, tax		1,000,000	1,000,000	5,000,000
Gulf Power [Member]
Qualifying hedges:
Changes in fair value of qualifying hedges, tax				(542,000)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	90,000	90,000	270,000	286,000
Mississippi Power [Member]
Qualifying hedges:
Changes in fair value of qualifying hedges, tax	(5,630,000)	4,000	(5,624,000)	8,000
Southern Power [Member]
Qualifying hedges:
Changes in fair value of qualifying hedges, tax	(135,000)	1,125,000	265,000	1,536,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 1,106,000	$ 1,018,000	$ 3,261,000	$ 3,011,000

XML

Financing (DetailsTextual) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Line of Credit Facility [Line Items]
Credit Arrangements expiration period	2016
Financing Textual [Abstract]
Ratio of indebtedness to capitalization covenant	0.65
Southern Company [Member]
Line of Credit Facility [Line Items]
Credit Arrangements	$ 1,000
Alabama Power [Member]
Line of Credit Facility [Line Items]
Credit Arrangements	800
Alabama Power [Member] | Credit arrangements expire in 2014 [Member]
Line of Credit Facility [Line Items]
Credit Arrangements	30
Credit Arrangements expiration period	2014
Alabama Power [Member] | Existing credit arrangements expire in 2011 [Member]
Line of Credit Facility [Line Items]
Credit Arrangements	20
Credit Arrangements expiration period	2011
Georgia Power [Member]
Line of Credit Facility [Line Items]
Credit Arrangements	1,500
Southern Power [Member]
Line of Credit Facility [Line Items]
Credit Arrangements	$ 500

XML

Retirement Benefits

9 Months Ended

Sep. 30, 2011

Retirement Benefits [Abstract]

RETIREMENT BENEFITS

(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 (ERISA). No contributions to the qualified pension plan are expected for the year ending December 31, 2011. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

Components of the net periodic benefit costs for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Southern			Alabama			Georgia			Gulf			Mississippi
Pension Plans	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended September 30, 2011
Service cost	$	46		$	11		$	14		$	2		$	3
Interest cost		97			24			36			4			4
Expected return on plan assets		(152	)		(44	)		(59	)		(6	)		(7	)
Net amortization		14			3			5			—			1
Net cost (income)	$	5		$	(6	)	$	(4	)	$	—		$	1
Nine Months Ended September 30, 2011
Service cost	$	138		$	32		$	43		$	6		$	7
Interest cost		292			72			108			13			13
Expected return on plan assets		(456	)		(130	)		(176	)		(20	)		(19	)
Net amortization		40			10			14			1			2
Net cost (income)	$	14		$	(16	)	$	(11	)	$	—		$	3
Three Months Ended September 30, 2010
Service cost	$	43		$	10		$	13		$	2		$	2
Interest cost		98			25			36			5			4
Expected return on plan assets		(138	)		(42	)		(54	)		(6	)		(5	)
Net amortization		11			3			4			—			1
Net cost (income)	$	14		$	(4	)	$	(1	)	$	1		$	2
Nine Months Ended September 30, 2010
Service cost	$	129		$	31		$	40		$	6		$	6
Interest cost		293			73			109			13			13
Expected return on plan assets		(413	)		(126	)		(164	)		(18	)		(16	)
Net amortization		32			8			11			1			2
Net cost (income)	$	41		$	(14	)	$	(4	)	$	2		$	5

	Southern			Alabama			Georgia			Gulf			Mississippi
Postretirement Benefits	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended September 30, 2011
Service cost	$	6		$	1		$	1		$	—		$	—
Interest cost		23			6			11			1			1
Expected return on plan assets		(16	)		(6	)		(8	)		—			—
Net amortization		5			2			3			—			—
Net cost (income)	$	18		$	3		$	7		$	1		$	1
Nine Months Ended September 30, 2011
Service cost	$	16		$	4		$	5		$	1		$	1
Interest cost		69			18			31			3			3
Expected return on plan assets		(48	)		(19	)		(23	)		(1	)		(1	)
Net amortization		15			5			8			—			—
Net cost (income)	$	52		$	8		$	21		$	3		$	3
Three Months Ended September 30, 2010
Service cost	$	6		$	2		$	3		$	—		$	—
Interest cost		25			7			11			1			2
Expected return on plan assets		(15	)		(7	)		(8	)		—			—
Net amortization		5			2			2			—			—
Net cost (income)	$	21		$	4		$	8		$	1		$	2
Nine Months Ended September 30, 2010
Service cost	$	19		$	5		$	7		$	1		$	1
Interest cost		75			20			33			3			4
Expected return on plan assets		(47	)		(19	)		(23	)		(1	)		(1	)
Net amortization		15			5			8			—			—
Net cost (income)	$	62		$	11		$	25		$	3		$	4

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Measurements [Abstract]

Assets and liabilities measured at fair value on a recurring basis

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2011:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Interest rate derivatives		—		16		—		16
Foreign currency derivatives		—		3		—		3
Nuclear decommissioning trusts(a)		487		671		—		1,158
Cash equivalents and restricted cash		1,286		—		—		1,286
Other investments		4		53		13		70
Total	$	1,777	$	746	$	13	$	2,536
Liabilities:
Energy-related derivatives	$	—	$	154	$	—	$	154
Interest rate derivatives		—		27		—		27
Foreign currency derivatives		—		2		—		2
Total	$	—	$	183	$	—	$	183
Alabama Power
Assets:
Nuclear decommissioning trusts:(b)
Domestic equity	$	228	$	53	$	—	$	281
Foreign equity		23		23		—		46
U.S. Treasury and government agency securities		16		9		—		25
Corporate bonds		—		112		—		112
Mortgage and asset backed securities		—		29		—		29
Other		—		8		—		8
Cash equivalents and restricted cash		445		—		—		445
Total	$	712	$	234	$	—	$	946
Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	29
Interest rate derivatives		—		12		—		12
Total	$	—	$	41	$	—	$	41

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2011:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts:(c)
Domestic equity		125		1		—		126
Foreign equity		95		—		—		95
U.S. Treasury and government agency securities		—		68		—		68
Municipal bonds		—		57		—		57
Corporate bonds		—		153		—		153
Mortgage and asset backed securities		—		96		—		96
Other		—		62		—		62
Cash equivalents		45		—		—		45
Total	$	265	$	439	$	—	$	704
Liabilities:
Energy-related derivatives	$	—	$	68	$	—	$	68
Gulf Power
Assets:
Cash equivalents	$	14	$	—	$	—	$	14
Liabilities:
Energy-related derivatives	$	—	$	17	$	—	$	17
Mississippi Power
Assets:
Foreign currency derivatives	$	—	$	3	$	—	$	3
Cash equivalents		85		—		—		85
Total	$	85	$	3	$	—	$	88
Liabilities:
Energy-related derivatives	$	—	$	35	$	—	$	35
Interest rate derivatives		—		15		—		15
Foreign currency derivatives		—		2		—		2
Total	$	—	$	52	$	—	$	52
Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents		196		—		—		196
Total	$	196	$	1	$	—	$	197
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5

(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 receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the securities lending program. As of September 30, 2011, approximately $53 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

	Fair		Unfunded	Redemption	Redemption
As of September 30, 2011:	Value		Commitments	Frequency	Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	37	None	Daily		1 to 3 days
Other — commingled funds		62	None	Daily	Not applicable
Trust owned life insurance		82	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		1,286	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Trust owned life insurance	$	82	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		445	None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	37	None	Daily		1 to 3 days
Other — commingled funds		62	None	Daily	Not applicable
Cash equivalents:
Money market funds		45	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	14	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	85	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	196	None	Daily	Not applicable

Changes in the fair value measurement of the Level 3 items

	Level 3
	Other
	Three Months Ended			Nine Months Ended
	September 30, 2011			September 30, 2011
	(in millions)
Beginning balance	$	17		$	19
Purchases		—			1
Total gains (losses) — realized/unrealized:
Included in earnings		—			(5	)
Included in OCI		(4	)		(2	)
Ending balance at September 30, 2011	$	13		$	13

Financial instruments not having carrying amount equal to fair value

	Carrying Amount		Fair Value
	(in millions)
Long-term debt*:
Southern Company	$	20,532	$	22,215
Alabama Power	$	6,232	$	6,910
Georgia Power	$	8,620	$	9,327
Gulf Power	$	1,235	$	1,359
Mississippi Power	$	702	$	739
Southern Power	$	1,599	$	1,694

* Includes securities due within one year.

XML

Effective Tax Rate and Unrecognized Tax Benefits

9 Months Ended

Sep. 30, 2011

Effective Tax Rate and Unrecognized Tax Benefits [Abstract]

EFFECTIVE TAX RATE AND UNRECOGNISED TAX BENEFITS

(G)	EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS
	Effective Tax Rate
	See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for information on the effective income tax rate.
	Southern Company
	Southern Company’s effective tax rate was 36.1% for the nine months ended September 30, 2011, compared to 33.1% for the corresponding period in 2010. Southern Company’s effective tax rate is lower than the statutory rate primarily due to its employee stock dividend deduction and non-taxable AFUDC equity. Southern Company’s effective tax rate increased primarily due to no production activities deduction and no Georgia state income tax credits for activity through Georgia ports available to Southern Company for the nine months ended September 30, 2011, compared to the production activities deduction and additional Georgia state income tax credits recognized as of September 30, 2010.
	Alabama Power
	Alabama Power’s effective tax rate was 39.0% for the nine months ended September 30, 2011, compared to 36.9% for the corresponding period in 2010. The increase was due to an increase in Alabama state income taxes as a result of a decrease in the state income tax deduction for federal income taxes paid.
	Georgia Power
	Georgia Power’s effective tax rate was 35.8% for the nine months ended September 30, 2011, compared to 32.3% for the corresponding period in 2010. The increase was primarily due to the inclusion of Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011, which reduced the amount of AFUDC equity capitalized, and the impact of Georgia state income tax credits discussed above under “Southern Company.”
	Gulf Power
	Gulf Power’s effective tax rate was 36.6% for the nine months ended September 30, 2011, compared to 36.4% for the corresponding period in 2010. The increase was not material.
	Mississippi Power
	Mississippi Power’s effective tax rate was 32.6% for the nine months ended September 30, 2011, compared to 36.5% for the corresponding period in 2010. The decrease was primarily due to an increase in non-taxable AFUDC equity related to the Kemper IGCC construction.
	Southern Power
	Southern Power’s effective tax rate was 35.9% for the nine months ended September 30, 2011, compared to 30.1% for the corresponding period in 2010. The increase was primarily due to the impact of a decrease in investment tax credits and no production activities deduction, combined with higher net income.

Unrecognized Tax Benefits

Changes during 2011 for unrecognized tax benefits were as follows:

	Southern			Alabama			Georgia			Gulf			Mississippi			Southern
	Company			Power			Power			Power			Power			Power
							(in millions)
Unrecognized tax benefits as of December 31, 2010	$	296		$	43		$	237		$	4		$	4		$	2
Tax positions from current periods		43			2			7			1			1			1
Tax positions from prior periods		(108	)		(18	)		(87	)		(2	)		(1	)		—
Reductions due to settlements		(112	)		—			(112	)		—			—			—
Reductions due to expired statute of limitations		—			—			—			—			—			—
Balance as of September 30, 2011	$	119		$	27		$	45		$	3		$	4		$	3

The tax positions from current periods relate primarily to the MC Asset Recovery litigation settlement refund claim, the tax accounting method change for repairs – generation assets, and the production activities deduction. See Note 5 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Effective Tax Rate” for additional information. The tax positions decrease from prior periods and reductions due to settlements relate to the settlement of the Georgia state tax credit litigation on June 10, 2011. See Note (B) under “Income Tax Matters — Georgia State Income Tax Credits” herein for additional information. In addition, the tax positions decrease from prior periods also relates to the uncertain tax position for the tax accounting method change for repairs – transmission and distribution assets. See “Tax Method of Accounting for Repairs” below for additional information.

The impact on the effective tax rate, if recognized, is as follows:

							As of
							December 31,
	As of September 30, 2011						2010
	Georgia		Other		Southern		Southern
	Power		Registrants		Company		Company
			(in millions)
Tax positions impacting the effective tax rate	$	28	$	12	$	76	$	217
Tax positions not impacting the effective tax rate		17		25		43		79
Balance of unrecognized tax benefits	$	45	$	37	$	119	$	296

The tax positions impacting the effective tax rate primarily relate to the production activities deduction tax position and the MC Asset Recovery litigation settlement refund claim. See Note 5 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Effective Tax Rate” for additional information. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs - generation assets. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Accrued interest for unrecognized tax benefits was as follows:

	Georgia			Other		Southern
	Power			Registrants		Company
	(in millions)
Interest accrued as of December 31, 2010	$	27		$	2	$	29
Interest reclassified due to settlements		(24	)		—		(24	)
Interest accrued during the period		2			1		4
Balance as of September 30, 2011	$	5		$	3	$	9

All of the registrants classify interest on tax uncertainties as interest expense. The interest reclassified due to settlements is primarily associated with the Georgia state tax credit litigation settled on June 10, 2011. See Note (B) under “Income Tax Matters — Georgia State Income Tax Credits” herein for additional information.

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 Southern Company’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the tax accounting method change for repairs - generation assets, as well as the conclusion or settlement of federal and state audits, could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Tax Method of Accounting for Repairs

Southern Company submitted a tax accounting method change for repair costs associated with its subsidiaries’ generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $141 million for Alabama Power, $133 million for Georgia Power, $8 million for Gulf Power, $5 million for Mississippi Power, $6 million for Southern Power, and $297 million for Southern Company on a consolidated basis. On August 19, 2011, the IRS issued Revenue Procedure 2011-43, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. Based upon this guidance from the IRS, the uncertain tax position for the tax accounting method change for repairs – transmission and distribution assets has been removed. However, the IRS continues to work with the utility industry in an effort to resolve the repair costs for generation assets matter in a consistent manner for all utilities. Due to uncertainty regarding the ultimate resolution of the repair costs for generation assets, an unrecognized tax position has been recorded for the tax accounting method change for repairs – generation assets. The ultimate outcome of this matter cannot be determined at this time.

XML

Fair Value Measurements (Details Textual) (USD $) In Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011
Fair Value Measurements (Textual) [Abstract]
Decrease in fair value of funds including reinvested interest and dividends	$ 98	$ 39
Fair Value Measurement (Textual) [Abstract]
Maximum number of months related to maturities in the portfolio not to exceeded from the date of purchase		13 months
Maximum number of days related to dollar-weighted average portfolio maturities regarding commingled funds		90 days
Maximum maturity for longer term investment grade fixed income obligations (in years)		5 years
Minimum number of months related to the reset date of maturities in the portfolio with put features or floating rates		13 months
Alabama Power [Member]
Fair Value Measurements (Textual) [Abstract]
Decrease in fair value of funds including reinvested interest and dividends	64	32
Georgia Power [Member]
Fair Value Measurements (Textual) [Abstract]
Nuclear decommissioning trusts	53	53
Decrease in fair value of funds including reinvested interest and dividends	$ 34	$ 7

XML

Financing

9 Months Ended

Sep. 30, 2011

Financing [Abstract]

FINANCING

(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 under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information.

The following table outlines the credit arrangements by company as of September 30, 2011:

					Executable										Expires Within
					Term-Loans				Expires						One Year(a)
													2013				No
					One		Two						And		Term		Term
Company	Total		Unused		Year		Years		2011		2012		Beyond		Out		Out
	(in millions)
Southern Company	$	1,000	$	1,000	$	—	$	—	$	—	$	—	$	1,000	$	—	$	—
Alabama Power		1,296		1,296		111		—		60		121		1,115		111		71
Georgia Power		1,750		1,745		—		—		—		—		1,750		—		—
Gulf Power		240		240		55		—		20		55		165		55		20
Mississippi Power		296		296		25		41		16		115		165		66		65
Southern Power		500		500		—		—		—		—		500		—		—
Other		50		50		25		—		—		25		25		25		—
Total	$	5,132	$	5,127	$	216	$	41	$	96	$	316	$	4,720	$	257	$	156

(a)   Reflects facilities expiring on or before September 30, 2012.

In May 2011, Southern Company, Alabama Power, Georgia Power, and Southern Power each replaced their multi-year credit arrangements that were to expire in 2012 with new five-year credit arrangements that will expire in 2016. These new credit arrangements provide for borrowings by Southern Company, Alabama Power, Georgia Power, and Southern Power of up to $1.0 billion, $800 million, $1.5 billion, and $500 million, respectively.

Subsequent to September 30, 2011, Alabama Power replaced a $20 million credit arrangement expiring in 2011 with a $30 million credit arrangement which will expire in 2014.

These credit arrangements generally have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes long-term debt payable to affiliated trusts and other hybrid securities.

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Thousands, except Share data	Sep. 30, 2011	Dec. 31, 2010
Common Stockholders' Equity:
Common stock, par value per share	$ 5	$ 5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Common stock, shares issued	862,000,000	844,000,000
Treasury shares at cost	500,000	500,000
Alabama Power [Member]
Common Stockholders' Equity:
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 Stockholders' Equity:
Common Stock, No Par Value
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	9,261,500	9,261,500
Gulf Power [Member]
Common Stockholders' Equity:
Common Stock, No Par Value
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	4,142,717	3,642,717
Mississippi Power [Member]
Common Stockholders' Equity:
Common Stock, No Par Value
Common stock, shares authorized	1,130,000	1,130,000
Common stock, shares outstanding	1,121,000	1,121,000
Southern Power [Member]
Other Property and Investments:
Amortization expense on other intangible assets	$ 1,280	$ 693
Common Stockholders' Equity:
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

Introduction

9 Months Ended

Sep. 30, 2011

Introduction [Abstract]

INTRODUCTION

(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, 2010 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, 2011 and 2010. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
	Effective March 15, 2011, Southern Company transferred its ownership in its wholly-owned subsidiary, Southern Renewable Energy, Inc. (SRE), to Southern Power. SRE was formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. As a transfer of net assets among entities under common control, the assets and liabilities of SRE were transferred at historical cost. The consolidated financial statements of Southern Power have been revised to include the financial condition and the results of operations of SRE since its inception in January 2010.
	Southern Company made separate guarantees to two counterparties regarding performance of contractual commitments by SRE. Southern Power assumed the guarantees in connection with the transfer of SRE. The total original notional amount of the guarantees was $120 million, approximately $12 million of which was outstanding at September 30, 2011. Of this amount, approximately $3 million is expected to expire in the first quarter 2012 and approximately $9 million is expected to expire in 2037.
	Leveraged Leases
	Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements of Southern Company under “Leveraged Leases” in Item 8 of the Form 10-K for additional information.
	The recent financial and operational performance of one of Southern Company’s lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the asset. Southern Company will continue to monitor the performance of the underlying assets and to evaluate the ability of the lessee to continue to make the required lease payments. While there are strategic options that Southern Company may pursue to recover its investment in the leveraged lease, the potential impairment loss that would be incurred if there is an abandonment of the project is expected to be approximately $80 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.

Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

XML

Derivatives (Details 2) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	$ (27)	$ 2	$ (22)	$ 1
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(5)	(7)	(10)	(24)
Alabama Power [Member] | Interest rate derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(12)	0	(8)	0
Alabama Power [Member] | Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	3	(1)
Georgia Power [Member] | Interest rate derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	0	0	0
Georgia Power [Member] | Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)	(3)	(3)	(13)
Gulf Power [Member] | Interest rate derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	0	0	(1)
Gulf Power [Member] | Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	(1)	(1)
Mississippi Power [Member] | Interest rate derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(15)	0	(15)	0
Mississippi Power [Member] | Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	0	0
Southern Power [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	3	1	4
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(3)	(3)	(8)	(8)
Southern Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	3	1	4
Southern Power [Member] | Interest rate derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	0	0	0
Southern Power [Member] | Fuel [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	0	0
Southern Power [Member] | Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(3)	(3)	(8)	(8)
Energy-related derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	3	1	4
Interest rate derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(27)	(1)	(23)	(3)
Fuel [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	0	0
Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (5)	$ (7)	$ (10)	$ (24)

XML

Fair Value Measurements (Details 3) (USD $) In Millions	Sep. 30, 2011
Long-term debt:
Long-term debt, Carrying Amount	$ 20,532
Long-term debt, Fair Value	22,215
Alabama Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	6,232
Long-term debt, Fair Value	6,910
Georgia Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	8,620
Long-term debt, Fair Value	9,327
Gulf Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,235
Long-term debt, Fair Value	1,359
Mississippi Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	702
Long-term debt, Fair Value	739
Southern Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,599
Long-term debt, Fair Value	$ 1,694

XML

Contingencies and Regulatory Matters

9 Months Ended

Sep. 30, 2011

Contingencies and Regulatory Matters [Abstract]

CONTINGENCIES AND REGULATORY MATTERS

(B)	CONTINGENCIES AND REGULATORY MATTERS
	See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
	General Litigation Matters
	Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, each registrant’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 opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against each registrant and any of its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant’s financial statements.
	Environmental Matters
	New Source Review Actions
	In November 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 NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened. The separate action against Alabama Power is ongoing.
	In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In September 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to a facility co-owned by Mississippi Power. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has appealed the decision to the U.S. Court of Appeals for the Eleventh Circuit.
	Southern Company believes that the traditional operating companies complied with applicable laws and the EPA regulations and interpretations 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 at each generating unit, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted 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.
	Carbon Dioxide Litigation
	New York Case
	In July 2004, three environmental groups and attorneys general from several states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs did not seek monetary damages in connection with their claims. Southern Company believes these claims are without merit. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and in September 2009 that court reversed and remanded the case to the district court. In December 2010, Southern Company and the other defendants appealed the case to the U.S. Supreme Court. On June 20, 2011, the U.S. Supreme Court held that the plaintiffs’ federal common law claims against Southern Company and four other electric utilities were displaced by the Clean Air Act and EPA regulations addressing greenhouse gas emissions and remanded the case for consideration of whether federal law may also preempt the remaining state law claims. On October 6, 2011, the U.S. Court of Appeals for the Second Circuit granted the plaintiffs’ motion to remand the case to the district court for voluntary dismissal. It is anticipated that the district court will issue an order dismissing the case; however, the ultimate outcome cannot be determined at this time.
	Kivalina Case
	In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit 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 are the governing bodies of an Inupiat village in Alaska. The plaintiffs allege that the village is being destroyed by erosion caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish legal standing by showing that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit, challenging the district court’s order dismissing the case. On August 31, 2011, at the request of the plaintiffs as a result of the U.S. Supreme Court’s decision in the New York case discussed above, the U.S. Court of Appeals for the Ninth Circuit lifted the stay that had been issued. The ultimate outcome of this matter cannot be determined at this time.
	Other Litigation
	Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and, as illustrated by the New York and Kivalina cases, courts have been debating whether private parties and states have standing to bring such claims. In another common law nuisance case, the U.S. District Court for the Southern District of Mississippi dismissed private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. The court ruled that the parties lacked standing to bring the claims and the claims were barred by the political question doctrine. In October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court and held that the plaintiffs did have standing to assert their nuisance, trespass, and negligence claims and none of the claims were barred by the political question doctrine. In May 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds, reinstating the district court decision in favor of the defendants. On January 10, 2011, the U.S. Supreme Court denied the plaintiffs’ petition to reinstate the appeal. This case is now concluded. However, on May 27, 2011, a class action complaint alleging damages as a result of Hurricane Katrina was filed in the U.S. District Court for the Southern District of Mississippi by the same plaintiffs who brought the previous common law nuisance case involving substantially similar allegations. The current litigation was filed against numerous chemical, coal, oil, and utility companies (including Alabama Power, Georgia Power, Gulf Power, and Southern Power) and includes many of the same defendants that were involved in the earlier case. Each Southern Company entity named in the lawsuit believes these claims are without merit. The ultimate outcome of this matter cannot be determined at this time.
	Environmental Remediation
	The registrants 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 subsidiaries may also 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. Within limits approved by the state PSCs, these rates are adjusted annually or as necessary.
	Georgia Power’s environmental remediation liability as of September 30, 2011 was $14 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 CERCLA NPL are anticipated; however, they are not expected to have a material impact on Georgia Power’s or Southern Company’s financial statements.
	In September 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices regarding this site from the EPA. In addition, in April 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. Discovery is on-going in these cases.
	On September 29, 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 Ward Transformer Superfund site. Georgia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. As a result, on November 7, 2011, Georgia Power filed a response with the EPA indicating that Georgia Power is not willing to undertake the work set forth in the UAO because Georgia Power has sufficient cause to believe it is not a liable party.
	The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO.
	The ultimate outcome of these matters will depend upon further environmental assessment, the ultimate number of PRPs, and a determination regarding Georgia Power’s status as a liable party under CERCLA and cannot be determined at this time. As a result, Southern Company and Georgia Power also cannot estimate the potential financial statement impacts at this time.
	Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $62 million as of September 30, 2011. These estimated costs 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 will be 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. Amounts expensed related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter 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 now be determined. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, Southern Company, Georgia Power, Gulf Power, and Mississippi Power do not believe that additional liabilities, if any, at these sites would have a material impact on their respective financial statements.
	Right of Way Litigation
	Southern Company and certain of its subsidiaries, including Mississippi Power, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and Mississippi Power believe they have complied with applicable laws and that the plaintiffs’ claims are without merit.
	Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and the related cases have been dismissed. These agreements have not resulted in any material effects on Southern Company’s or Mississippi Power’s financial statements.
	In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network Inc. a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses certain of the defendants’ rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. Southern Company and Mississippi Power believe that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. In August 2010, the defendants filed a motion to dismiss the suit for lack of prosecution. The court denied the defendants’ motion to dismiss the claim. On March 25, 2011, the plaintiffs filed an amended complaint asserting claims for breach of contract for failing to make the defendants’ facilities fully available to the plaintiffs and for failing to indemnify the plaintiffs in defending the underlying landowner litigation. An adverse outcome in this matter is not expected to be material to Southern Company or Mississippi Power; however, the final outcome cannot now be determined.

Nuclear Fuel Disposal Cost Litigation

See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 of the Form 10-K for information regarding the litigation brought by Alabama Power and Georgia Power against the government for breach of contracts related to the disposal of spent nuclear fuel.

In July 2007, the U.S. Court of Federal Claims awarded Georgia Power approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley, Hatch, and Vogtle from 1998 through 2004.

In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April 2008. In May 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay.

On March 11, 2011, the U.S. Court of Appeals for the Federal Circuit issued an order in which it affirmed the damage award to Alabama Power, but remanded the Georgia Power portion of the proceeding back to the U.S. Court of Federal Claims for reconsideration of the damages amount in light of the spent nuclear fuel acceptance rates adopted in a separate proceeding by the U.S. Court of Appeals for the Federal Circuit. The Georgia Power portion remains pending. On July 7, 2011, Alabama Power and the government entered into a stipulation for the entry of a separate judgment in favor of Alabama Power. On July 12, 2011, the court entered final judgment in favor of Alabama Power and subsequently the judgment was paid.

In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim) due to the government’s alleged continuing breach of contract. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of September 30, 2011 for the second claim.

The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be credited to cost of service for the benefit of customers.

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

Income Tax Matters

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia included state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On June 10, 2011, Georgia Power and the Georgia Department of Revenue agreed to a settlement resolving the claims. As a result, Georgia Power recorded additional tax benefits of approximately $64 million and, in accordance with the 2010 ARP, also recorded a related regulatory liability of approximately $62 million. In addition, Georgia Power recorded a reduction of approximately $23 million in related interest expense. See Notes 3 and 5 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, and Note (G) herein for additional information.

State PSC Matters

Alabama Power

Environmental Accounting Order

Proposed environmental regulations could result in significant additional compliance costs that could affect future unit retirement and replacement decisions. On September 7, 2011, the Alabama PSC approved an order allowing for the establishment of a regulatory asset to record the unrecovered investment costs associated with any such decisions, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure. These costs would be amortized over the affected unit’s remaining useful life, as established prior to the decision regarding early retirement.

Retail Rate Adjustments

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 7 of the Form 10-K for information regarding the rate structure of Alabama Power. On July 12, 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under Alabama Power’s rate structure effective with October 2011 billings. Alabama Power anticipates the elimination of this adjustment will result in additional revenues of approximately $30 million for the remainder of 2011 and is expected to have an annual effect of approximately $150 million beginning in 2012.

In accordance with the order, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues from the elimination of the tax-related adjustment to replenish the NDR, which was impacted as a result of operations and maintenance expenses incurred in connection with the April 2011 storms in Alabama. Alabama Power expects that the additional revenue in 2012 will preclude the need for a rate adjustment under Rate Stabilization and Equalization (Rate RSE). Accordingly, Alabama Power agreed to a moratorium on any increase in 2012 under Rate RSE.

Natural Disaster Reserve

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.

During the first half of 2011, multiple storms caused varying degrees of damage to Alabama Power’s transmission and distribution facilities. The most significant storm occurred on April 27, 2011, causing over 400,000 of Alabama Power’s 1.4 million customers to be without electrical service. The estimated cost of repairing the damage to facilities and restoring electrical service to customers, as a result of these storms, is approximately $45 million for operations and maintenance expenses and approximately $163 million for capital-related expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.

At September 30, 2011, the NDR had an accumulated balance of $75 million, which is included in Southern Company’s and Alabama Power’s Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.

In accordance with the order discussed above that was issued by the Alabama PSC on July 12, 2011 to eliminate a tax-related adjustment under Alabama Power’s rate structure, Alabama Power will make additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues, which are expected to be approximately $30 million.

Retail Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Alabama Power under “Retail Regulatory Matters — Alabama Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s under recovered fuel costs as of September 30, 2011 totaled $39 million as compared to $4 million at December 31, 2010. These under recovered fuel costs at September 30, 2011 are included in deferred under recovered regulatory clause revenues on Southern Company’s and Alabama Power’s Condensed Balance Sheets herein. This classification is based on an estimate which includes 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 recovery of the under recovered fuel costs.

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. On May 24, 2011, the Georgia PSC approved Georgia Power’s request to decrease fuel rates by 0.61%. The decrease reduced Georgia Power’s annual billings by approximately $43 million effective June 1, 2011. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s or Georgia Power’s revenues or net income, but will affect cash flow.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and “Construction — Nuclear,” respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power’s construction of Plant Vogtle Units 3 and 4, which are expected to attain commercial operation in 2016 and 2017, respectively.

In December 2010, Westinghouse submitted a revision to the supporting documents for the AP1000 Design Certification Amendment (DCA) to the NRC. On January 24, 2011, the Advisory Committee on Reactor Safeguards endorsed the issuance of the Construction and Operating Licenses (COLs) for Plant Vogtle Units 3 and 4. In addition, on March 25, 2011, the NRC submitted to the EPA the final environmental impact statement for Plant Vogtle Units 3 and 4. On September 27 and 28, 2011, the NRC held the mandatory hearing for the COLs and Georgia Power’s request for a second limited work authorization. On October 18, 2011, the Atomic Safety and Licensing Board (ASLB) denied the remaining motions seeking to re-open the Plant Vogtle Units 3 and 4 licensing proceeding; however, on October 27, 2011, the petitioners requested reconsideration of this decision and, on November 2, 2011, further appealed to the NRC to admit their contentions, should they again be denied by the ASLB. The remaining steps in the regulatory process are to address the status of these petitions and to obtain the NRC approvals of the DCA and the COLs, which Georgia Power expects in late 2011. Issuance of the COLs by the NRC staff generally would be expected to occur 10 days after the NRC’s decision. However, due to certain administrative procedural requirements, it is possible that the effective date of the DCA and issuance of the COLs could occur in early 2012. In this case, the NRC could approve Georgia Power’s request for a second limited work authorization, which would allow Georgia Power to perform additional construction activities related to the nuclear island in late 2011.

In connection with its certification of Plant Vogtle Units 3 and 4, the Georgia PSC ordered Georgia Power and the Georgia PSC Public Interest Advocacy Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize Georgia Power’s earnings if and when overruns are due to mandates from governing agencies. In May 2011, the Georgia PSC initiated a separate proceeding to address the issue. On August 2, 2011, the Georgia PSC voted to approve a settlement agreement between Georgia Power and the Georgia PSC Public Interest Advocacy Staff whereby the proposed risk sharing mechanisms were withdrawn. On August 16, 2011, the Georgia PSC voted to approve Georgia Power’s fourth semi-annual construction monitoring report including total costs of $1.3 billion for Plant Vogtle Units 3 and 4 incurred through December 31, 2010. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

In December 2010, the Georgia PSC approved the NCCR tariff, which became effective January 1, 2011. The NCCR tariff was established to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period in accordance with the Georgia Nuclear Energy Financing Act. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. 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, 2011, approximately $78 million of these 2009 and 2010 costs were included in construction work in progress.

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 (collectively, Owners), and a consortium consisting of Westinghouse and Stone & Webster, Inc. have established both informal and formal dispute resolution procedures in order to resolve issues that commonly arise during the course of constructing a project of this magnitude. Southern Nuclear, on behalf of the Owners, has initiated both formal and informal claims through these procedures, including ongoing claims. During the course of construction activities, issues have materialized that may impact the project budget and schedule, including potential costs associated with compressing the project schedule to meet the projected commercial operation dates. The Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including petitions filed at the NRC in response to the events in Japan. Similar additional challenges at the state and federal level are expected as construction proceeds.

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

Other Construction

Georgia Power is currently constructing Plant McDonough Units 4, 5, and 6 which are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. The Georgia PSC has approved Georgia Power’s quarterly construction monitoring reports, including actual project expenditures incurred, through December 31, 2010. Georgia Power filed its second quarter 2011 construction monitoring report on August 26, 2011, including actual project expenditures incurred through June 30, 2011 as well as a request to approve a 4.6% increase in the current certified amount. The Georgia PSC is scheduled to issue its decision on February 16, 2012. Georgia Power will continue to file quarterly construction monitoring reports throughout the construction period. The ultimate outcome of this matter cannot be determined at this time.

2011 Integrated Resource Plan Update

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” and “Retail Regulatory Matters — Rate Plans,” respectively, in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility Maximum Available Control Technology (MACT) rule for coal- and oil-fired electric utility steam generating units, 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; and the 2010 ARP.

On August 4, 2011, Georgia Power filed an update to its IRP (2011 IRP Update). The filing included Georgia Power’s application to decertify Plant Branch Units 1 and 2 as of December 31, 2013 and October 1, 2013, the compliance dates for the respective units under the Georgia Multi-Pollutant Rule. However, as a result of the considerable uncertainty regarding pending state and federal environmental regulations, Georgia Power is continuing to defer decisions to add controls, switch fuel, or retire its remaining fossil generating units where environmental controls have not yet been installed, representing approximately 2,600 MWs of capacity. Georgia Power expects to update its economic analysis of these units once the Utility MACT rule is finalized. Georgia Power currently expects that certain units, representing approximately 600 MWs of capacity, are more likely than others to switch fuel or be controlled in time to comply with the Utility MACT rule. However, even if the updated economic analysis shows more positive benefits associated with adding controls or switching fuel for more units, it is unlikely that all of the required controls could be completed by 2015, the expected effective date of the Utility MACT rule. As a result, Georgia Power currently cannot rely on the availability of approximately 2,000 MWs of capacity in 2015. As such, the 2011 IRP Update also includes Georgia Power’s application requesting that the Georgia PSC certify the purchase of a total of 1,562 MWs of capacity beginning in 2015, from four PPAs selected through the 2015 request for proposal process.

Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets resulting from new or revised environmental regulations through 2013 that are approved by the Georgia PSC in connection with an updated IRP will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. In connection with the retirement decision, Georgia Power reclassified the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net. Georgia Power is continuing to depreciate these units using the current composite straight-line rates previously approved by the Georgia PSC and upon actual retirement has requested that the Georgia PSC approve the continued deferral and amortization of the units’ remaining net carrying value. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Southern Company’s or Georgia Power’s financial statements.

The Georgia PSC is expected to vote on these requests in March 2012. The ultimate outcome of these matters cannot be determined at this time.

Gulf Power

Retail Base Rate Case

On July 8, 2011, 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 $93.5 million. The requested increase is expected to provide a reasonable opportunity for Gulf Power to earn a retail rate of return on common equity of 11.7%. The Florida PSC is expected to make a decision on this matter in the first quarter 2012. Gulf Power has calculated its revenue deficiency based on the projected period January 1, 2012 through December 31, 2012 which serves as the test year.

On August 23, 2011, the Florida PSC approved Gulf Power’s request for an interim retail rate increase of $38.5 million per year, effective beginning with billings based on meter readings on and after September 22, 2011 and continuing through the effective date of the Florida PSC’s decision on Gulf Power’s petition for the permanent increase. The interim rates are subject to refund pending the outcome of the permanent retail base rate proceeding.

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

Fuel Cost Recovery

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. If the projected fuel cost over or under recovery balance at year-end exceeds 10% of the projected fuel revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the fuel cost recovery factor is being requested.

In previous years, Gulf Power has experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and volatile price swings in natural gas. Under recovered fuel costs at September 30, 2011 totaled $7.5 million, compared to $17.4 million at December 31, 2010. This amount is included in under recovered regulatory clause revenues on Southern Company’s and Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor will have no significant effect on Southern Company’s or Gulf Power’s revenues or net income, but will affect cash flow. See Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters — Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

Purchased Power Capacity Recovery

Gulf Power has established purchased power capacity recovery cost rates as approved by the Florida PSC. If the projected purchased power capacity cost over or under recovery balance at year-end exceeds 10% of the projected purchased power capacity revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate an adjustment to the purchased power capacity cost recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on August 19, 2011, but no adjustment to the 2011 factor was requested.

Over recovered purchased power capacity costs at September 30, 2011 totaled $3.5 million compared to $4.4 million at December 31, 2010. This amount is included in other regulatory liabilities, current on Southern Company’s and Gulf Power’s Condensed Balance Sheets herein. Purchased power capacity cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor will have no significant effect on Southern Company’s and Gulf Power’s revenues or net income, but will affect cash flow.

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

Environmental Cost Recovery

In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million and is scheduled for completion in early 2015. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011. On May 5, 2011, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in additional spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in December 2011. The ultimate outcome of this matter cannot be determined at this time.

Over recovered environmental costs at September 30, 2011 totaled $16.9 million compared to $10.4 million at December 31, 2010. This amount is included in other regulatory liabilities, current on Southern Company’s and Gulf Power’s Condensed Balance Sheets herein. See Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.

Energy Conservation Cost Recovery

Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the Energy Conservation Cost Recovery clause.

The most recent goal setting process established new DSM goals for the period 2010-2019. The new goals are significantly larger than the goals established in the previous five-year cycle due to a change in the cost-effectiveness test on which the Florida PSC relies to set the goals. Throughout 2010, Gulf Power engaged in a process at the Florida PSC to develop plans and programs to meet the new DSM goals. The DSM program standards were approved in April 2011, which allow Gulf Power to implement its DSM programs designed to meet the new goals. Higher cost recovery rates and achievement of the new DSM goals may result in reduced sales of electricity which could negatively impact results of operations, cash flows, and financial condition if base rates cannot be adjusted on a timely basis.

Mississippi Power

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Performance Evaluation Plan” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s base rates.

In November 2010, Mississippi Power filed its annual PEP filing for 2011, which indicated a rate increase of 1.936%, or $16.1 million, annually. On January 10, 2011, the Mississippi Public Utilities Staff (MPUS) contested the filing. On June 7, 2011, the Mississippi PSC issued an order approving a joint stipulation between the MPUS and Mississippi Power resulting in no change in rates.

On March 15, 2011, Mississippi Power submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. On May 2, 2011, Mississippi Power received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. The ultimate outcome of this matter cannot be determined at this time.

System Restoration Rider

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — System Restoration Rider” in Item 8 of the Form 10-K for additional information regarding the System Restoration Rider.

On January 31, 2011, Mississippi Power submitted its 2011 System Restoration Rider rate filing to the Mississippi PSC, which proposed that Mississippi Power be allowed to accrue approximately $3.6 million to the property damage reserve in 2011. On May 5, 2011, the filing was approved by the Mississippi PSC.

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Environmental Compliance Overview Plan” in Item 8 of the Form 10-K for information on Mississippi Power’s annual environmental filing with the Mississippi PSC.

On February 14, 2011, Mississippi Power submitted its ECO Plan notice which proposed an immaterial decrease in annual revenues. In addition, Mississippi Power proposed to change the ECO Plan collection period to more appropriately match ECO Plan revenues with ECO Plan expenditures. On April 7, 2011, due to changes in ECO Plan cost projections, Mississippi Power submitted a revised 2011 ECO Plan which changed the requested annual revenues to a $0.9 million decrease. On May 5, 2011, hearings on the revised ECO Plan were held and the filing was approved by the Mississippi PSC with the new rates effective in May 2011.

In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million, with Mississippi Power’s portion being $312.5 million. As of September 30, 2011, total project expenditures were $35.8 million, with Mississippi Power’s portion being $17.9 million. The project is scheduled for completion in early 2015.

Mississippi Power’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through the ECO Plan. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011. On May 5, 2011, in conjunction with the ECO Plan hearings, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in additional spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in December 2011. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. Mississippi Power establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. Mississippi Power is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred in November 2010. The Mississippi PSC approved the retail fuel cost recovery factor in December 2010, with the new rates effective in January 2011. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 5.0% of total 2010 retail revenue. At September 30, 2011, the amount of over recovered retail fuel costs included in the balance sheets was $41.4 million compared to $55.2 million at December 31, 2010. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2011, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 3.5% of total 2010 MRA revenue. Effective February 1, 2011, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 7.0% of total 2010 MB revenue. At September 30, 2011, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $14.6 million and $2.3 million compared to $17.5 million and $4.4 million, respectively, at December 31, 2010. In addition, at September 30, 2011, the amount of over recovered MRA emissions allowance cost included in the balance sheets was $1.0 million. See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information. 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, this decrease to the billing factors will have no significant effect on Southern Company’s or Mississippi Power’s revenues or net income, but will decrease annual cash flow.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Mississippi Power Integrated Coal Gasification Combined Cycle” and of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding Mississippi Power’s construction of the Kemper IGCC.

In June 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 2010 decision to grant the Certificate of Public Convenience and Necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, in July 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Club’s direct appeal. On February 28, 2011, the Chancery Court issued a judgment affirming the Mississippi PSC’s order authorizing the construction of the Kemper IGCC. On March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court.

In May 2009, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $133 million of Internal Revenue Code Section 48A tax credits (Phase I) to Mississippi Power. On April 19, 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II tax credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the carbon dioxide (CO₂) produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits. Through September 30, 2011, Mississippi Power received or accrued tax benefits totaling $73.9 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC.

In February 2008, Mississippi Power requested that the DOE transfer the remaining funds previously granted under the Clean Coal Power Initiative Round 2 (CCPI2) from a cancelled IGCC project of one of Southern Company’s subsidiaries that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. Mississippi Power will receive grant funds of $245 million during the construction of the Kemper IGCC and $25 million during its initial operation. Mississippi Power had received $158.6 million through September 30, 2011 and subsequently received an additional $20.9 million on October 19, 2011 associated with this grant.

On March 10, 2011, the Sierra Club filed a lawsuit in the U.S. District Court for the District of Columbia against the DOE regarding the National Environmental Policy Act review process asking for a preliminary and permanent injunction on the issuance of CCPI2 funds and loan guarantees and a stay to any related construction activities based upon alleged deficiencies in the DOE’s environmental impact statement. Mississippi Power intervened in this lawsuit on May 18, 2011.

In March 2010, the Mississippi Department of Environmental Quality (MDEQ) issued the Prevention of Significant Deterioration (PSD) air permit modification for the plant, which modifies the original PSD air permit issued in October 2008. The Sierra Club requested a formal evidentiary hearing regarding the issuance of the modified permit. On April 4, 2011, the MDEQ Permit Board held an evidentiary hearing wherein it unanimously affirmed the PSD air permit. On June 30, 2011, the Sierra Club appealed the final PSD air permit issued by the MDEQ to the Chancery Court of Kemper County, Mississippi. Mississippi Power has intervened as a party in this appeal.

On March 4, 2011, Mississippi Power and Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., entered into a contract pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC. On May 19, 2011, Mississippi Power and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tenrgys, LLC, entered into a contract pursuant to which Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC.

On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-A (CNP-A), a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. Annual CNP-A rate filings will be made with the first filing occurring by November 15, 2011. If approved by the Mississippi PSC, recovery through CNP-A will remain in place thereafter until the end of the calendar year that the Kemper IGCC is placed into commercial service, which is projected to be 2014. On August 9, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-B (CNP-B) to govern rates effective from the first calendar year after the Kemper IGCC is placed into commercial service through the first seven full calendar years of its operation. Under the proposed CNP-B, Mississippi Power’s allowed cost of capital would be adjusted based on certain operational performance indicators.

On June 7, 2011, consistent with the treatment of non-capital costs 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. The amortization period for the regulatory asset will be determined by the Mississippi PSC at a later date. In addition, Mississippi Power is authorized to accrue carrying costs for 2011 on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in connection with future proceedings regarding the cost recovery mechanism for the Kemper IGCC.

On September 9, 2011, Mississippi Power filed a request for confirmation of the Kemper IGCC’s Certificate of Public Convenience and Necessity with the Mississippi PSC authorizing the acquisition, construction, and operation of approximately 61 miles of CO₂ pipeline infrastructure at an estimated capital cost of $141 million.

The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. In conjunction with the plant, Mississippi Power will own a lignite mine and equipment and will acquire mineral reserves located around the plant site in Kemper County. The estimated capital cost of the mine is approximately $245.0 million. On January 18, 2011, Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations, submitted an application to the MDEQ for a surface mining permit for the mine.

As of September 30, 2011, Mississippi Power had spent a total of $664.9 million on the Kemper IGCC, including regulatory filing costs. Of this total, $463.8 million was included in construction work in progress (net of $179.5 million of CCPI2 grant funds), $19.0 million was recorded in other regulatory assets, $1.6 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

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

Plant Daniel Combined Cycle Generating Units

See Note 7 to the financial statements of Southern Company and Mississippi Power under “Operating Leases” and “Operating Leases — Plant Daniel Combined Cycle Generating Units,” respectively, in Item 8 of the Form 10-K for information relating to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel (Facility).

Mississippi Power was required to provide notice of its intent to either renew the lease or purchase the Facility by July 22, 2011. On July 20, 2011, Mississippi Power provided notice to the lessor of its intent to purchase the Facility. Mississippi Power’s right to purchase the Facility was approved by the Mississippi PSC in its order dated January 7, 1998, as amended on February 19, 1999, which granted Mississippi Power a Certificate of Public Convenience and Necessity for the Facility.

On October 20, 2011, Mississippi Power purchased the Facility for approximately $85 million in cash and the assumption of debt obligations of the lessor related to the Facility, which mature in 2021, have a face value of $270 million and a fixed stated interest rate of 7.13%, and are secured by the Facility and certain personal property, accounts, and proceeds related thereto. Accounting rules require that the Facility be reflected on Southern Company’s and Mississippi Power’s financial statements at the time of the purchase at the fair value of the consideration rendered. Based on interest rates as of October 20, 2011, the fair value of the debt assumed was approximately $346 million. Accordingly, the Facility will be reflected in Southern Company’s and Mississippi Power’s financial statements at approximately $431 million. Mississippi Power intends to maintain its traditional capital structure by adding equity to support the additional debt.

In connection with the purchase of the Facility, Mississippi Power filed a request on July 25, 2011 for an accounting order from the Mississippi PSC. If the accounting order is approved as requested, the retail revenue requirements under the purchase option will be comparable to those otherwise required under operating lease accounting treatment for the extended lease term, with any differences deferred as a regulatory asset over the 10-year period ending October 2021. At the conclusion of the proposed deferral period in 2021, the unamortized deferral balance will be amortized into rates over the remaining life of the Facility. On November 2, 2011, Mississippi Power filed a request with the FERC seeking authorization to defer as a regulatory asset, for the 10-year period ending October 2021, the difference between the revenue requirement under the purchase of the Facility (assuming a remaining 30-year life) and the revenue requirement assuming the continuation of the operating lease regulatory treatment. At the conclusion of the proposed deferral period in 2021, the accumulated deferred balance will be amortized into wholesale rates over the remaining life of the Facility. The ultimate outcome of these matters cannot be determined at this time.

XML

Segment and Related Information (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Financial data for business segments
Operating revenues	$ 5,428,000,000	$ 5,320,000,000	$ 13,961,000,000	$ 13,685,000,000
Segment net income (loss)	916,000,000	817,000,000	1,942,000,000	1,822,000,000
Total Assets	57,343,000,000		57,343,000,000		55,032,000,000
Traditional Operating Companies [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	5,145,000,000	5,066,000,000	13,246,000,000	13,127,000,000
Segment net income (loss)	862,000,000	756,000,000	1,805,000,000	1,713,000,000
Total Assets	52,949,000,000		52,949,000,000		51,144,000,000
Southern Power [Member]
Segment and Related Information (Textual) [Abstract]
Southern Power's revenues from sales to the traditional operating companies	85,000,000	93,000,000	239,000,000	288,000,000
Southern Power [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	363,000,000	357,000,000	950,000,000	862,000,000
Segment net income (loss)	56,000,000	63,000,000	138,000,000	109,000,000
Total Assets	3,757,000,000		3,757,000,000		3,438,000,000
Eliminations [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	(97,000,000)	(124,000,000)	(288,000,000)	(367,000,000)
Total Assets	(160,000,000)		(160,000,000)		(128,000,000)
All Other Segments [Member]
Financial data for business segments
Operating revenues	38,000,000	40,000,000	114,000,000	122,000,000
Segment net income (loss)		(1,000,000)	2,000,000	2,000,000
Total Assets	1,431,000,000		1,431,000,000		1,178,000,000
Eliminations [Member]
Financial data for business segments
Operating revenues	(21,000,000)	(19,000,000)	(61,000,000)	(59,000,000)
Segment net income (loss)	(2,000,000)	(1,000,000)	(3,000,000)	(2,000,000)
Total Assets	(634,000,000)		(634,000,000)		(600,000,000)
Electric Utilities [Member]
Financial data for business segments
Operating revenues	5,411,000,000	5,299,000,000	13,908,000,000	13,622,000,000
Segment net income (loss)	918,000,000	819,000,000	1,943,000,000	1,822,000,000
Total Assets	$ 56,546,000,000		$ 56,546,000,000		$ 54,454,000,000

XML

Fair Value Measurements (Details) (USD $) In Millions	Sep. 30, 2011
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents and restricted cash	$ 445
Fair value assets, total	946
Liabilities:
Energy-related derivatives	29
Interest rate derivatives	12
Fair value liabilities, total	41
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents and restricted cash	445
Fair value assets, total	712
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Fair value liabilities, total	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	228
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	23
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	16
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Cash equivalents and restricted cash	0
Fair value assets, total	234
Liabilities:
Energy-related derivatives	29
Interest rate derivatives	12
Fair value liabilities, total	41
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	53
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	23
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	9
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	112
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	29
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other [Member]
Assets:
Nuclear decommissioning trusts	8
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Cash equivalents and restricted cash	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Fair value liabilities, total	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	281
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	46
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	25
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	112
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	29
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other [Member]
Assets:
Nuclear decommissioning trusts	8
Georgia Power [Member]
Assets:
Nuclear decommissioning trusts	53
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	2
Cash equivalents and restricted cash	45
Fair value assets, total	704
Liabilities:
Energy-related derivatives	68
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Energy-related derivatives	0
Cash equivalents and restricted cash	45
Fair value assets, total	265
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	125
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	95
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Energy-related derivatives	2
Cash equivalents and restricted cash	0
Fair value assets, total	439
Liabilities:
Energy-related derivatives	68
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	1
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	68
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	57
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	153
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	96
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other [Member]
Assets:
Nuclear decommissioning trusts	62
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Energy-related derivatives	0
Cash equivalents and restricted cash	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	126
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	95
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	68
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	57
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	153
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	96
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other [Member]
Assets:
Nuclear decommissioning trusts	62
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents and restricted cash	14
Liabilities:
Energy-related derivatives	17
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents and restricted cash	14
Liabilities:
Energy-related derivatives	0
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Cash equivalents and restricted cash	0
Liabilities:
Energy-related derivatives	17
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Cash equivalents and restricted cash	0
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Foreign currency derivatives	3
Cash equivalents and restricted cash	85
Fair value assets, total	88
Liabilities:
Energy-related derivatives	35
Interest rate derivatives	15
Foreign currency derivatives	2
Fair value liabilities, total	52
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Foreign currency derivatives	0
Cash equivalents and restricted cash	85
Fair value assets, total	85
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Fair value liabilities, total	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Foreign currency derivatives	3
Cash equivalents and restricted cash	0
Fair value assets, total	3
Liabilities:
Energy-related derivatives	35
Interest rate derivatives	15
Foreign currency derivatives	2
Fair value liabilities, total	52
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Foreign currency derivatives	0
Cash equivalents and restricted cash	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Fair value liabilities, total	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	1
Cash equivalents and restricted cash	196
Fair value assets, total	197
Liabilities:
Energy-related derivatives	5
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Energy-related derivatives	0
Cash equivalents and restricted cash	196
Fair value assets, total	196
Liabilities:
Energy-related derivatives	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Energy-related derivatives	1
Cash equivalents and restricted cash	0
Fair value assets, total	1
Liabilities:
Energy-related derivatives	5
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Energy-related derivatives	0
Cash equivalents and restricted cash	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	3
Interest rate derivatives	16
Foreign currency derivatives	3
Nuclear decommissioning trusts	1,158
Cash equivalents and restricted cash	1,286
Other	70
Fair value assets, total	2,536
Liabilities:
Energy-related derivatives	154
Interest rate derivatives	27
Foreign currency derivatives	2
Fair value liabilities, total	183
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Nuclear decommissioning trusts	487
Cash equivalents and restricted cash	1,286
Other	4
Fair value assets, total	1,777
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Fair value liabilities, total	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Energy-related derivatives	3
Interest rate derivatives	16
Foreign currency derivatives	3
Nuclear decommissioning trusts	671
Cash equivalents and restricted cash	0
Other	53
Fair value assets, total	746
Liabilities:
Energy-related derivatives	154
Interest rate derivatives	27
Foreign currency derivatives	2
Fair value liabilities, total	183
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Nuclear decommissioning trusts	0
Cash equivalents and restricted cash	0
Other	13
Fair value assets, total	13
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Fair value liabilities, total	$ 0

XML

Stockholders' Equity (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Number of Common shares Issued [Member]	Sep. 30, 2010 Number of Common shares Issued [Member]	Sep. 30, 2011 Number of Common shares Treasury [Member]	Sep. 30, 2010 Number of Common shares Treasury [Member]	Sep. 30, 2011 Common Stockholders' Equity [Member]	Sep. 30, 2010 Common Stockholders' Equity [Member]	Sep. 30, 2011 Preferred and Preference Stock of Subsidiaries [Member]	Dec. 31, 2010 Preferred and Preference Stock of Subsidiaries [Member]	Sep. 30, 2010 Preferred and Preference Stock of Subsidiaries [Member]	Dec. 31, 2009 Preferred and Preference Stock of Subsidiaries [Member]
Changes in Stockholders' Equity
Beginning Balance			$ 16,909,000,000	$ 15,585,000,000					$ 16,202,000,000	$ 14,878,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000
Beginning Balance, Shares					843,814,000	820,152,000	(474,000)	(505,000)
Net Income After Dividends on Preferred and Preference Stock	916,000,000	817,000,000	1,942,000,000	1,822,000,000					1,942,000,000	1,822,000,000
Other comprehensive income (loss)	(19,000,000)	2,000,000	(11,000,000)	16,000,000					(11,000,000)	16,000,000
Stock issued, shares					18,634,000	18,994,000
Stock issued			692,000,000	650,000,000					692,000,000	650,000,000
Cash dividends on common stock			(1,193,000,000)	(1,114,000,000)					(1,193,000,000)	(1,114,000,000)
Other, shares							(45,000)	30,000
Other			1,000,000	3,000,000					1,000,000	3,000,000
Ending Balance	$ 18,340,000,000	$ 16,962,000,000	$ 18,340,000,000	$ 16,962,000,000					$ 17,633,000,000	$ 16,255,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000
Ending Balance, Shares					862,448,000	839,146,000	(519,000)	(475,000)
Earnings per Share
As reported shares	860,000,000	836,000,000	854,000,000	829,000,000
Effect of options	8,000,000	6,000,000	7,000,000	4,000,000
Diluted shares	868,000,000	842,000,000	861,000,000	833,000,000
Stockholders' Equity (Textual) [Abstract]
Anti dilutive stock options	400,000	6,700,000	400,000	13,700,000
Assumed average stock price			$ 40.14	$ 38.01
Increase in effect of options		400,000		800,000

XML

Derivatives (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Million_British_Thermal_Unit	Sep. 30, 2010
Fair value of derivative liabilities with contingent features
Derivative liabilities	$ 32		$ 32
Derivatives (Textual) [Abstract]
Maximum expected volume of natural gas subject to such a feature (million mmBtu)			2,950,000
Pre-tax gains (losses) from foreign currency derivatives designated as fair value hedging instruments	(3)	5	(2)	5
Pre-tax gains from interest rate derivatives designated as fair value hedging instruments	5	9	7	17
Maximum potential collateral requirements arising the from credit-risk-related contingent features	32		32
Alabama Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	7		7
Derivatives (Textual) [Abstract]
Maximum potential collateral requirements arising the from credit-risk-related contingent features	32		32
Georgia Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	16		16
Derivatives (Textual) [Abstract]
Maximum expected volume of natural gas subject to such a feature (million mmBtu)			2,690,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	32		32
Gulf Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	2		2
Derivatives (Textual) [Abstract]
Maximum potential collateral requirements arising the from credit-risk-related contingent features	32		32
Mississippi Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	5		5
Derivatives (Textual) [Abstract]
Pre-tax gains (losses) from foreign currency derivatives designated as fair value hedging instruments	(3)	5	(2)	5
Maximum potential collateral requirements arising the from credit-risk-related contingent features	32		32
Southern Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	2		2
Derivatives (Textual) [Abstract]
Maximum potential collateral requirements arising the from credit-risk-related contingent features	$ 32		$ 32

XML

Fair Value Measurements (Details 2) (USD $) In Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011
Changes in the fair value measurement of the Level 3 items
Beginning balance	$ 17	$ 19
Purchases		1
Total gains (losses) - realized/unrealized:
Included in earnings		(5)
Included in OCI	(4)	(2)
Ending balance	$ 13	$ 13

XML

Fair Value Measurements (Policies)

9 Months Ended

Sep. 30, 2011

Fair Value Measurements [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 used in the 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.

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 further 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:

Energy-Related Derivatives and Interest Rate Derivatives

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 electric utilities may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the electric utilities 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 in 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, 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, 2011, the net volume of energy-related derivative contracts for power and natural gas positions for the registrants, 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:

	Power						Gas
			Longest		Longest		Net		Longest		Longest
	Net Sold		Hedge		Non-Hedge		Purchased		Hedge		Non-Hedge
	MWHs		Date		Date		mmBtu		Date		Date
	(in millions)						(in millions)
Southern Company		0.3		—		2011		160		2015		2015
Alabama Power		—		—		—		31		2015		—
Georgia Power		—		—		—		66		2015		—
Gulf Power		—		—		—		26		2015		—
Mississippi Power		—		—		—		31		2015		—
Southern Power		0.3		—		2011		7		2012		2015

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 was 2.95 million mmBtu for Southern Company, 2.69 million mmBtu for Georgia Power, and was immaterial for the other registrants.

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending September 30, 2012 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries 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, 2011, the following interest rate derivatives were outstanding:

	Notional		Interest Rate			Interest Rate			Hedge Maturity	Fair Value Gain (Loss)
	Amount		Received			Paid			Date	September 30, 2011
	(in millions)									(in millions)
Cash flow hedges of existing debt
Southern Company	$	300	3-month LIBOR + 0.40% spread				1.24	%*	October 2011	$	—
Cash flow hedges of forecasted debt
Alabama Power		300	3-month LIBOR				2.90	%*	December 2022		(12	)
Mississippi Power		150	3-month LIBOR				2.37	%*	September 2021		(4	)
Mississippi Power		150	3-month LIBOR				1.25	%*	September 2016		—
Mississippi Power		300	3-month LIBOR				2.66	%*	April 2022		(11	)
Fair value hedges of existing debt
						3-month LIBOR +
Southern Company		350		4.15	%	1.96%* spread			May 2014		16
Total	$	1,550								$	(11	)

* Weighted Average

The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending September 30, 2012, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.

	Estimated Gain (Loss)to
	be Reclassified for the			Total Deferred
	12 Months Ending			Gains (Losses)
Registrant	September 30, 2012			Amortized Through
	(in millions)
Southern Company	$	(16	)		2037
Alabama Power		—			2035
Georgia Power		(3	)		2037
Gulf Power		(1	)		2020
Mississippi Power		(1	)		2022
Southern Power		(11	)		2016

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 recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

Leveraged Leases

Leveraged Leases

Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements of Southern Company under “Leveraged Leases” in Item 8 of the Form 10-K for additional information.

The recent financial and operational performance of one of Southern Company’s lessees and the associated generation assets has raised potential concerns on the part of Southern Company as to the credit quality of the lessee and the residual value of the asset. Southern Company will continue to monitor the performance of the underlying assets and to evaluate the ability of the lessee to continue to make the required lease payments. While there are strategic options that Southern Company may pursue to recover its investment in the leveraged lease, the potential impairment loss that would be incurred if there is an abandonment of the project is expected to be approximately $80 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

(C)	FAIR VALUE MEASUREMENTS
	As of September 30, 2011, 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
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2011:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Interest rate derivatives		—		16		—		16
Foreign currency derivatives		—		3		—		3
Nuclear decommissioning trusts(a)		487		671		—		1,158
Cash equivalents and restricted cash		1,286		—		—		1,286
Other investments		4		53		13		70
Total	$	1,777	$	746	$	13	$	2,536
Liabilities:
Energy-related derivatives	$	—	$	154	$	—	$	154
Interest rate derivatives		—		27		—		27
Foreign currency derivatives		—		2		—		2
Total	$	—	$	183	$	—	$	183
Alabama Power
Assets:
Nuclear decommissioning trusts:(b)
Domestic equity	$	228	$	53	$	—	$	281
Foreign equity		23		23		—		46
U.S. Treasury and government agency securities		16		9		—		25
Corporate bonds		—		112		—		112
Mortgage and asset backed securities		—		29		—		29
Other		—		8		—		8
Cash equivalents and restricted cash		445		—		—		445
Total	$	712	$	234	$	—	$	946
Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	29
Interest rate derivatives		—		12		—		12
Total	$	—	$	41	$	—	$	41

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2011:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts:(c)
Domestic equity		125		1		—		126
Foreign equity		95		—		—		95
U.S. Treasury and government agency securities		—		68		—		68
Municipal bonds		—		57		—		57
Corporate bonds		—		153		—		153
Mortgage and asset backed securities		—		96		—		96
Other		—		62		—		62
Cash equivalents		45		—		—		45
Total	$	265	$	439	$	—	$	704
Liabilities:
Energy-related derivatives	$	—	$	68	$	—	$	68
Gulf Power
Assets:
Cash equivalents	$	14	$	—	$	—	$	14
Liabilities:
Energy-related derivatives	$	—	$	17	$	—	$	17
Mississippi Power
Assets:
Foreign currency derivatives	$	—	$	3	$	—	$	3
Cash equivalents		85		—		—		85
Total	$	85	$	3	$	—	$	88
Liabilities:
Energy-related derivatives	$	—	$	35	$	—	$	35
Interest rate derivatives		—		15		—		15
Foreign currency derivatives		—		2		—		2
Total	$	—	$	52	$	—	$	52
Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents		196		—		—		196
Total	$	196	$	1	$	—	$	197
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5

(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 receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the securities lending program. As of September 30, 2011, approximately $53 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 used in the 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, 2011, 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:

	Fair		Unfunded	Redemption	Redemption
As of September 30, 2011:	Value		Commitments	Frequency	Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	37	None	Daily		1 to 3 days
Other — commingled funds		62	None	Daily	Not applicable
Trust owned life insurance		82	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		1,286	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Trust owned life insurance	$	82	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		445	None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	37	None	Daily		1 to 3 days
Other — commingled funds		62	None	Daily	Not applicable
Cash equivalents:
Money market funds		45	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	14	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	85	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	196	None	Daily	Not applicable

The NRC requires licensees of commercial 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 commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, 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, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset rate date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The corporate bonds — commingled funds 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 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, 2011, the decrease in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $64 million and $32 million, respectively, for Alabama Power, $34 million and $7 million, respectively, for Georgia Power, and $98 million and $39 million, respectively, for Southern Company.

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.

Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at September 30, 2011 were as follows:

	Level 3
	Other
	Three Months Ended			Nine Months Ended
	September 30, 2011			September 30, 2011
	(in millions)
Beginning balance	$	17		$	19
Purchases		—			1
Total gains (losses) — realized/unrealized:
Included in earnings		—			(5	)
Included in OCI		(4	)		(2	)
Ending balance at September 30, 2011	$	13		$	13

At September 30, 2011, 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	$	20,532	$	22,215
Alabama Power	$	6,232	$	6,910
Georgia Power	$	8,620	$	9,327
Gulf Power	$	1,235	$	1,359
Mississippi Power	$	702	$	739
Southern Power	$	1,599	$	1,694

* Includes securities due within one year.

The fair values were based on closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

XML

Financing (Tables)

9 Months Ended

Sep. 30, 2011

Financing [Abstract]

Credit arrangements by company

					Executable										Expires Within
					Term-Loans				Expires						One Year(a)
													2013				No
					One		Two						And		Term		Term
Company	Total		Unused		Year		Years		2011		2012		Beyond		Out		Out
	(in millions)
Southern Company	$	1,000	$	1,000	$	—	$	—	$	—	$	—	$	1,000	$	—	$	—
Alabama Power		1,296		1,296		111		—		60		121		1,115		111		71
Georgia Power		1,750		1,745		—		—		—		—		1,750		—		—
Gulf Power		240		240		55		—		20		55		165		55		20
Mississippi Power		296		296		25		41		16		115		165		66		65
Southern Power		500		500		—		—		—		—		500		—		—
Other		50		50		25		—		—		25		25		25		—
Total	$	5,132	$	5,127	$	216	$	41	$	96	$	316	$	4,720	$	257	$	156

(a)   Reflects facilities expiring on or before September 30, 2012.

XML

Derivatives (Details 1) (USD $) In Millions	Sep. 30, 2011
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	$ 183
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	12
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	12
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	3
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	15
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	17
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	3
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	2
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Cash Flow and Fair Value Hedging [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	19
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	6
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	10
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	15
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	12
Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	29
Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	3
Cash Flow and Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	2
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Liability Derivatives	29
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	24
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	5
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	2
Liability Derivatives	68
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	53
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	15
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Liability Derivatives	17
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	10
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	7
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Liability Derivatives	35
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	27
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	8
Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	2
Liability Derivatives	149
Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	114
Hedging Instruments for Regulatory Purposes [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	35
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Assets from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Assets from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Assets from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	0
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Assets from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	5
Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Assets from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	5
Alabama Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	41
Alabama Power [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(29)
Alabama Power [Member] | Energy-related derivatives [Member] | Other Current Liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Alabama Power [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Alabama Power [Member] | Energy-related derivatives [Member] | Other regulatory assets, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(24)
Alabama Power [Member] | Energy-related derivatives [Member] | Other regulatory assets, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(5)
Alabama Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Alabama Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Georgia Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	68
Georgia Power [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	2
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(66)
Georgia Power [Member] | Energy-related derivatives [Member] | Other Current Liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	1
Georgia Power [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	1
Georgia Power [Member] | Energy-related derivatives [Member] | Other regulatory assets, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(53)
Georgia Power [Member] | Energy-related derivatives [Member] | Other regulatory assets, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(15)
Georgia Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Georgia Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Gulf Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	17
Gulf Power [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	0
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(17)
Gulf Power [Member] | Energy-related derivatives [Member] | Other Current Liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Gulf Power [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Gulf Power [Member] | Energy-related derivatives [Member] | Other regulatory assets, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(10)
Gulf Power [Member] | Energy-related derivatives [Member] | Other regulatory assets, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(7)
Gulf Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Gulf Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Mississippi Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	52
Mississippi Power [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	3
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(35)
Mississippi Power [Member] | Energy-related derivatives [Member] | Other Current Liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Mississippi Power [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Mississippi Power [Member] | Energy-related derivatives [Member] | Other regulatory assets, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(27)
Mississippi Power [Member] | Energy-related derivatives [Member] | Other regulatory assets, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(8)
Mississippi Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Mississippi Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Southern Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	5
Southern Power [Member] | Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Energy-related derivatives [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	22
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(147)
Energy-related derivatives [Member] | Other Current Liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	0
Energy-related derivatives [Member] | Other regulatory assets, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(114)
Energy-related derivatives [Member] | Other regulatory assets, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(35)
Energy-related derivatives [Member] | Other regulatory liabilities, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	1
Energy-related derivatives [Member] | Other regulatory liabilities, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	$ 1

XML

Fair Value Measurements (Details 1) (USD $) In Millions	Sep. 30, 2011
Alabama Power [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
Fair Value	$ 82
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	15 days
Alabama Power [Member] | 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	445
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Georgia Power [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
Fair Value	37
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	1 to 3 days
Georgia Power [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
Fair Value	62
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Georgia Power [Member] | 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	45
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Gulf Power [Member] | 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	14
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Mississippi Power [Member] | 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	85
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Southern Power [Member] | 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	196
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
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	37
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	1 to 3 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	62
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	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	82
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	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	1,286
Unfunded Commitments	$ 0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable

XML

Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 1,516,000,000	$ 447,000,000
Restricted cash and cash equivalents	9,000,000	68,000,000
Receivables --
Customer accounts receivable	1,401,000,000	1,140,000,000
Unbilled revenues	449,000,000	420,000,000
Under recovered regulatory clause revenues	210,000,000	209,000,000
Other accounts and notes receivable	250,000,000	285,000,000
Accumulated provision for uncollectible accounts	(30,000,000)	(25,000,000)
Fossil fuel stock, at average cost	1,076,000,000	1,308,000,000
Materials and supplies, at average cost	854,000,000	827,000,000
Vacation pay	150,000,000	151,000,000
Prepaid expenses	319,000,000	784,000,000
Other regulatory assets, current	191,000,000	210,000,000
Other current assets	100,000,000	59,000,000
Total current assets	6,495,000,000	5,883,000,000
Property, Plant, and Equipment:
In service	58,079,000,000	56,731,000,000
Less accumulated depreciation	20,891,000,000	20,174,000,000
Plant in service, net of depreciation	37,188,000,000	36,557,000,000
Other utility plant, net	57,000,000	0
Nuclear fuel, at amortized cost	743,000,000	670,000,000
Construction work in progress	5,809,000,000	4,775,000,000
Total property, plant, and equipment	43,797,000,000	42,002,000,000
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,159,000,000	1,370,000,000
Leveraged leases	641,000,000	624,000,000
Miscellaneous property and investments	256,000,000	277,000,000
Total other property and investments	2,056,000,000	2,271,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,361,000,000	1,280,000,000
Prepaid pension costs	137,000,000	88,000,000
Unamortized debt issuance expense	163,000,000	178,000,000
Unamortized loss on reacquired debt	283,000,000	274,000,000
Deferred under recovered regulatory clause revenues	64,000,000	218,000,000
Other regulatory assets, deferred	2,496,000,000	2,402,000,000
Other deferred charges and assets	491,000,000	436,000,000
Total deferred charges and other assets	4,995,000,000	4,876,000,000
Total Assets	57,343,000,000	55,032,000,000
Current Liabilities:
Securities due within one year	1,891,000,000	1,301,000,000
Notes payable	137,000,000	1,297,000,000
Accounts payable	1,355,000,000	1,275,000,000
Customer deposits	340,000,000	332,000,000
Accrued taxes --
Accrued income taxes	46,000,000	8,000,000
Unrecognized tax benefits	22,000,000	187,000,000
Other accrued taxes	458,000,000	440,000,000
Accrued interest	245,000,000	225,000,000
Accrued vacation pay	191,000,000	194,000,000
Accrued compensation	349,000,000	438,000,000
Liabilities from risk management activities	136,000,000	152,000,000
Other regulatory liabilities, current	107,000,000	88,000,000
Other current liabilities	380,000,000	535,000,000
Total current liabilities	5,657,000,000	6,472,000,000
Long-term Debt	18,733,000,000	18,154,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	8,613,000,000	7,554,000,000
Deferred credits related to income taxes	223,000,000	235,000,000
Accumulated deferred investment tax credits	579,000,000	509,000,000
Employee benefit obligations	1,608,000,000	1,580,000,000
Asset retirement obligations	1,307,000,000	1,257,000,000
Other cost of removal obligations	1,170,000,000	1,158,000,000
Other regulatory liabilities, deferred	255,000,000	312,000,000
Other deferred credits and liabilities	483,000,000	517,000,000
Total deferred credits and other liabilities	14,238,000,000	13,122,000,000
Total Liabilities	38,628,000,000	37,748,000,000
Redeemable Preferred Stock of Subsidiaries	375,000,000	375,000,000
Common Stockholders' Equity:
Common stock	4,312,000,000	4,219,000,000
Paid-in capital	4,302,000,000	3,702,000,000
Treasury, at cost	(16,000,000)	(15,000,000)
Retained earnings	9,116,000,000	8,366,000,000
Accumulated other comprehensive loss	(81,000,000)	(70,000,000)
Total Common Stockholders' Equity	17,633,000,000	16,202,000,000
Preferred and Preference Stock of Subsidiaries	707,000,000	707,000,000
Total Stockholders' Equity	18,340,000,000	16,909,000,000
Total Liabilities and Stockholders' Equity	57,343,000,000	55,032,000,000
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	576,000,000	154,000,000
Restricted cash and cash equivalents	3,000,000	18,000,000
Receivables --
Customer accounts receivable	419,000,000	362,000,000
Unbilled revenues	126,000,000	153,000,000
Under recovered regulatory clause revenues	11,000,000	5,000,000
Other accounts and notes receivable	48,000,000	35,000,000
Affiliated companies	47,000,000	57,000,000
Accumulated provision for uncollectible accounts	(10,000,000)	(10,000,000)
Fossil fuel stock, at average cost	316,000,000	391,000,000
Materials and supplies, at average cost	355,000,000	346,000,000
Vacation pay	55,000,000	55,000,000
Prepaid expenses	77,000,000	208,000,000
Other regulatory assets, current	33,000,000	38,000,000
Other current assets	11,000,000	10,000,000
Total current assets	2,067,000,000	1,822,000,000
Property, Plant, and Equipment:
In service	20,530,000,000	19,966,000,000
Less accumulated depreciation	7,247,000,000	6,931,000,000
Plant in service, net of depreciation	13,283,000,000	13,035,000,000
Nuclear fuel, at amortized cost	316,000,000	283,000,000
Construction work in progress	485,000,000	547,000,000
Total property, plant, and equipment	14,084,000,000	13,865,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	62,000,000	64,000,000
Nuclear decommissioning trusts, at fair value	502,000,000	552,000,000
Miscellaneous property and investments	73,000,000	71,000,000
Total other property and investments	637,000,000	687,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	528,000,000	488,000,000
Prepaid pension costs	287,000,000	257,000,000
Deferred under recovered regulatory clause revenues	39,000,000	4,000,000
Other regulatory assets, deferred	680,000,000	675,000,000
Other deferred charges and assets	193,000,000	196,000,000
Total deferred charges and other assets	1,727,000,000	1,620,000,000
Total Assets	18,515,000,000	17,994,000,000
Current Liabilities:
Securities due within one year	0	200,000,000
Affiliated	195,000,000	210,000,000
Accounts payable	198,000,000	273,000,000
Customer deposits	85,000,000	86,000,000
Accrued taxes --
Accrued income taxes	13,000,000	2,000,000
Other accrued taxes	103,000,000	32,000,000
Accrued interest	71,000,000	63,000,000
Accrued vacation pay	45,000,000	45,000,000
Accrued compensation	73,000,000	99,000,000
Liabilities from risk management activities	24,000,000	31,000,000
Over recovered regulatory clause revenues	25,000,000	22,000,000
Other current liabilities	35,000,000	41,000,000
Total current liabilities	867,000,000	1,104,000,000
Long-term Debt	6,232,000,000	5,987,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,148,000,000	2,747,000,000
Deferred credits related to income taxes	81,000,000	85,000,000
Accumulated deferred investment tax credits	151,000,000	157,000,000
Employee benefit obligations	323,000,000	311,000,000
Asset retirement obligations	544,000,000	520,000,000
Other cost of removal obligations	702,000,000	701,000,000
Other regulatory liabilities, deferred	92,000,000	217,000,000
Other deferred credits and liabilities	92,000,000	87,000,000
Total deferred credits and other liabilities	5,133,000,000	4,825,000,000
Total Liabilities	12,232,000,000	11,916,000,000
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	2,177,000,000	2,156,000,000
Retained earnings	2,213,000,000	2,022,000,000
Accumulated other comprehensive loss	(14,000,000)	(7,000,000)
Total Common Stockholders' Equity	5,598,000,000	5,393,000,000
Total Liabilities and Stockholders' Equity	18,515,000,000	17,994,000,000
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	66,000,000	8,000,000
Receivables --
Customer accounts receivable	764,000,000	580,000,000
Unbilled revenues	235,000,000	172,000,000
Under recovered regulatory clause revenues	189,000,000	184,000,000
Joint owner accounts receivable	52,000,000	60,000,000
Other accounts and notes receivable	58,000,000	67,000,000
Affiliated companies	28,000,000	21,000,000
Accumulated provision for uncollectible accounts	(17,000,000)	(11,000,000)
Fossil fuel stock, at average cost	509,000,000	624,000,000
Materials and supplies, at average cost	379,000,000	371,000,000
Vacation pay	77,000,000	78,000,000
Prepaid income taxes	1,000,000	99,000,000
Other regulatory assets, current	94,000,000	105,000,000
Other current assets	144,000,000	80,000,000
Total current assets	2,579,000,000	2,438,000,000
Property, Plant, and Equipment:
In service	26,918,000,000	26,397,000,000
Less accumulated depreciation	10,198,000,000	9,966,000,000
Plant in service, net of depreciation	16,720,000,000	16,431,000,000
Other utility plant, net	57,000,000	0
Nuclear fuel, at amortized cost	427,000,000	386,000,000
Construction work in progress	3,774,000,000	3,287,000,000
Total property, plant, and equipment	20,978,000,000	20,104,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	63,000,000	70,000,000
Nuclear decommissioning trusts, at fair value	657,000,000	818,000,000
Miscellaneous property and investments	39,000,000	42,000,000
Total other property and investments	759,000,000	930,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	747,000,000	723,000,000
Prepaid pension costs	122,000,000	91,000,000
Deferred under recovered regulatory clause revenues	25,000,000	214,000,000
Other regulatory assets, deferred	1,282,000,000	1,207,000,000
Other deferred charges and assets	213,000,000	207,000,000
Total deferred charges and other assets	2,389,000,000	2,442,000,000
Total Assets	26,705,000,000	25,914,000,000
Current Liabilities:
Securities due within one year	254,000,000	415,000,000
Notes payable	1,000,000	576,000,000
Affiliated	328,000,000	243,000,000
Accounts payable	580,000,000	574,000,000
Customer deposits	206,000,000	198,000,000
Accrued taxes --
Accrued income taxes	105,000,000	1,000,000
Unrecognized tax benefits	9,000,000	187,000,000
Other accrued taxes	252,000,000	328,000,000
Accrued interest	117,000,000	94,000,000
Accrued vacation pay	56,000,000	58,000,000
Accrued compensation	100,000,000	109,000,000
Liabilities from risk management activities	53,000,000	77,000,000
Other cost of removal obligations, current	31,000,000	31,000,000
Nuclear decommissioning trust securities lending collateral	37,000,000	144,000,000
Other current liabilities	162,000,000	134,000,000
Total current liabilities	2,291,000,000	3,169,000,000
Long-term Debt	8,422,000,000	7,931,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,256,000,000	3,718,000,000
Deferred credits related to income taxes	124,000,000	129,000,000
Accumulated deferred investment tax credits	222,000,000	229,000,000
Employee benefit obligations	716,000,000	684,000,000
Asset retirement obligations	729,000,000	705,000,000
Other cost of removal obligations	123,000,000	131,000,000
Other deferred credits and liabilities	237,000,000	211,000,000
Total deferred credits and other liabilities	6,407,000,000	5,807,000,000
Total Liabilities	17,120,000,000	16,907,000,000
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	5,504,000,000	5,291,000,000
Retained earnings	3,426,000,000	3,063,000,000
Accumulated other comprehensive loss	(9,000,000)	(11,000,000)
Total Common Stockholders' Equity	9,319,000,000	8,741,000,000
Total Liabilities and Stockholders' Equity	26,705,000,000	25,914,000,000
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	17,330,000	16,434,000
Receivables --
Customer accounts receivable	91,252,000	74,377,000
Unbilled revenues	58,813,000	64,697,000
Under recovered regulatory clause revenues	9,840,000	19,690,000
Other accounts and notes receivable	14,829,000	9,867,000
Affiliated companies	15,429,000	7,859,000
Accumulated provision for uncollectible accounts	(1,863,000)	(2,014,000)
Fossil fuel stock, at average cost	128,283,000	167,155,000
Materials and supplies, at average cost	51,111,000	44,729,000
Prepaid expenses	22,342,000	58,412,000
Other regulatory assets, current	22,491,000	20,278,000
Other current assets	1,838,000	3,585,000
Total current assets	431,695,000	485,069,000
Property, Plant, and Equipment:
In service	3,813,901,000	3,634,255,000
Less accumulated depreciation	1,108,710,000	1,069,006,000
Plant in service, net of depreciation	2,705,191,000	2,565,249,000
Construction work in progress	231,156,000	209,808,000
Total property, plant, and equipment	2,936,347,000	2,775,057,000
Other Property and Investments:
Total other property and investments	16,343,000	16,352,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	52,219,000	46,357,000
Prepaid pension costs	9,414,000	7,291,000
Other regulatory assets, deferred	259,136,000	219,877,000
Other deferred charges and assets	35,318,000	34,936,000
Total deferred charges and other assets	356,087,000	308,461,000
Total Assets	3,740,472,000	3,584,939,000
Current Liabilities:
Securities due within one year	0	110,000,000
Notes payable	36,577,000	93,183,000
Affiliated	62,464,000	46,342,000
Accounts payable	53,842,000	68,840,000
Customer deposits	35,859,000	35,600,000
Accrued taxes --
Accrued income taxes	8,587,000	3,835,000
Other accrued taxes	25,014,000	7,944,000
Accrued interest	18,175,000	13,393,000
Accrued compensation	10,169,000	14,459,000
Liabilities from risk management activities	10,205,000	9,415,000
Other regulatory liabilities, current	33,080,000	27,060,000
Other current liabilities	21,015,000	19,766,000
Total current liabilities	314,987,000	449,837,000
Long-term Debt	1,235,344,000	1,114,398,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	454,530,000	382,876,000
Accumulated deferred investment tax credits	7,097,000	8,109,000
Employee benefit obligations	76,695,000	76,654,000
Other cost of removal obligations	213,113,000	204,408,000
Other regulatory liabilities, deferred	43,399,000	42,915,000
Other deferred credits and liabilities	164,752,000	132,708,000
Total deferred credits and other liabilities	959,586,000	847,670,000
Total Liabilities	2,509,917,000	2,411,905,000
Preference Stock	97,998,000	97,998,000
Common Stockholders' Equity:
Common stock	353,060,000	303,060,000
Paid-in capital	541,706,000	538,375,000
Retained earnings	240,088,000	236,328,000
Accumulated other comprehensive loss	(2,297,000)	(2,727,000)
Total Common Stockholders' Equity	1,132,557,000	1,075,036,000
Total Liabilities and Stockholders' Equity	3,740,472,000	3,584,939,000
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	117,627,000	160,779,000
Restricted cash and cash equivalents	0	50,000,000
Receivables --
Customer accounts receivable	45,269,000	37,532,000
Unbilled revenues	28,753,000	31,010,000
Other accounts and notes receivable	7,765,000	11,220,000
Affiliated companies	22,282,000	17,837,000
Accumulated provision for uncollectible accounts	(709,000)	(638,000)
Fossil fuel stock, at average cost	109,895,000	112,240,000
Materials and supplies, at average cost	30,114,000	28,671,000
Prepaid income taxes	71,749,000	59,596,000
Other regulatory assets, current	59,143,000	63,896,000
Other current assets	28,602,000	19,057,000
Total current assets	520,490,000	591,200,000
Property, Plant, and Equipment:
In service	2,445,523,000	2,392,477,000
Less accumulated depreciation	988,073,000	971,559,000
Plant in service, net of depreciation	1,457,450,000	1,420,918,000
Construction work in progress	676,762,000	274,585,000
Total property, plant, and equipment	2,134,212,000	1,695,503,000
Other Property and Investments:
Total other property and investments	6,231,000	5,900,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	28,988,000	18,065,000
Other regulatory assets, deferred	128,049,000	132,420,000
Other deferred charges and assets	22,086,000	33,233,000
Total deferred charges and other assets	179,123,000	183,718,000
Total Assets	2,840,056,000	2,476,321,000
Current Liabilities:
Securities due within one year	241,002,000	256,437,000
Affiliated	54,353,000	51,887,000
Accounts payable	148,391,000	59,295,000
Customer deposits	13,445,000	12,543,000
Accrued taxes --
Accrued income taxes	9,636,000	4,356,000
Other accrued taxes	42,964,000	51,709,000
Accrued interest	5,502,000	5,933,000
Accrued compensation	11,563,000	16,076,000
Liabilities from risk management activities	43,179,000	27,525,000
Other regulatory liabilities, current	5,523,000	6,177,000
Over recovered regulatory clause liabilities	59,292,000	77,046,000
Other current liabilities	18,651,000	20,115,000
Total current liabilities	653,501,000	589,099,000
Long-term Debt	461,531,000	462,032,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	316,675,000	281,967,000
Deferred credits related to income taxes	11,660,000	11,792,000
Accumulated deferred investment tax credits	84,449,000	33,678,000
Employee benefit obligations	115,282,000	113,964,000
Other cost of removal obligations	121,972,000	111,614,000
Other regulatory liabilities, deferred	60,574,000	58,814,000
Other deferred credits and liabilities	30,162,000	43,213,000
Total deferred credits and other liabilities	740,774,000	655,042,000
Total Liabilities	1,855,806,000	1,706,173,000
Redeemable Preferred Stock	32,780,000	32,780,000
Common Stockholders' Equity:
Common stock	37,691,000	37,691,000
Paid-in capital	594,677,000	392,790,000
Retained earnings	328,179,000	306,885,000
Accumulated other comprehensive loss	(9,077,000)	2,000
Total Common Stockholders' Equity	951,470,000	737,368,000
Total Liabilities and Stockholders' Equity	2,840,056,000	2,476,321,000
Southern Power [Member]
Current Assets:
Cash and cash equivalents	205,509,000	14,204,000
Receivables --
Customer accounts receivable	73,979,000	77,033,000
Other accounts and notes receivable	2,062,000	1,979,000
Affiliated companies	50,371,000	19,673,000
Fossil fuel stock, at average cost	13,529,000	13,663,000
Materials and supplies, at average cost	35,332,000	33,934,000
Prepaid service agreements - current	34,087,000	41,627,000
Prepaid income taxes	320,000	53,860,000
Prepaid expenses	3,941,000	4,161,000
Assets from risk management activities	663,000	2,160,000
Other current assets	0	19,000
Total current assets	419,793,000	262,313,000
Property, Plant, and Equipment:
In service	3,162,965,000	3,143,919,000
Less accumulated depreciation	628,547,000	536,107,000
Plant in service, net of depreciation	2,534,418,000	2,607,812,000
Construction work in progress	619,655,000	427,788,000
Total property, plant, and equipment	3,154,073,000	3,035,600,000
Other Property and Investments:
Goodwill	1,839,000	1,839,000
Other intangible assets, net of amortization of $1,280 and $693 at September 30, 2011 and September 30, 2010, respectively	47,839,000	48,426,000
Total other property and investments	49,678,000	50,265,000
Deferred Charges and Other Assets:
Prepaid long-term service agreements	105,953,000	69,740,000
Other deferred charges and assets -- affiliated	3,091,000	3,275,000
Other deferred charges and assets	24,611,000	16,541,000
Total deferred charges and other assets	133,655,000	89,556,000
Total Assets	3,757,199,000	3,437,734,000
Current Liabilities:
Securities due within one year	575,510,000	0
Notes payable -- affiliated	0	65,883,000
Notes payable	48,884,000	203,904,000
Affiliated	64,739,000	69,783,000
Accounts payable	46,078,000	45,985,000
Accrued taxes --
Accrued income taxes	17,472,000	812,000
Other accrued taxes	12,619,000	2,775,000
Accrued interest	18,375,000	29,977,000
Liabilities from risk management activities	5,035,000	5,773,000
Other current liabilities	5,516,000	3,923,000
Total current liabilities	794,228,000	428,815,000
Long-term Debt	1,023,967,000	1,302,619,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	312,861,000	307,989,000
Deferred convertible investment tax credits	113,280,000	80,401,000
Deferred capacity revenues -- affiliated	38,114,000	30,533,000
Other deferred credits and liabilities -- affiliated	3,859,000	4,635,000
Other deferred credits and liabilities	3,081,000	16,203,000
Total deferred credits and other liabilities	471,195,000	439,761,000
Total Liabilities	2,289,390,000	2,171,195,000
Redeemable Noncontrolling Interest	3,630,000	3,319,000
Common Stockholders' Equity:
Common stock
Paid-in capital	1,026,565,000	900,969,000
Retained earnings	446,285,000	376,270,000
Accumulated other comprehensive loss	(8,671,000)	(14,019,000)
Total Common Stockholders' Equity	1,464,179,000	1,263,220,000
Total Liabilities and Stockholders' Equity	$ 3,757,199,000	$ 3,437,734,000

XML

Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2011

Retirement Benefits [Abstract]

Pension Plans and Postretirement Plans

	Southern			Alabama			Georgia			Gulf			Mississippi
Pension Plans	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended September 30, 2011
Service cost	$	46		$	11		$	14		$	2		$	3
Interest cost		97			24			36			4			4
Expected return on plan assets		(152	)		(44	)		(59	)		(6	)		(7	)
Net amortization		14			3			5			—			1
Net cost (income)	$	5		$	(6	)	$	(4	)	$	—		$	1
Nine Months Ended September 30, 2011
Service cost	$	138		$	32		$	43		$	6		$	7
Interest cost		292			72			108			13			13
Expected return on plan assets		(456	)		(130	)		(176	)		(20	)		(19	)
Net amortization		40			10			14			1			2
Net cost (income)	$	14		$	(16	)	$	(11	)	$	—		$	3
Three Months Ended September 30, 2010
Service cost	$	43		$	10		$	13		$	2		$	2
Interest cost		98			25			36			5			4
Expected return on plan assets		(138	)		(42	)		(54	)		(6	)		(5	)
Net amortization		11			3			4			—			1
Net cost (income)	$	14		$	(4	)	$	(1	)	$	1		$	2
Nine Months Ended September 30, 2010
Service cost	$	129		$	31		$	40		$	6		$	6
Interest cost		293			73			109			13			13
Expected return on plan assets		(413	)		(126	)		(164	)		(18	)		(16	)
Net amortization		32			8			11			1			2
Net cost (income)	$	41		$	(14	)	$	(4	)	$	2		$	5

	Southern			Alabama			Georgia			Gulf			Mississippi
Postretirement Benefits	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended September 30, 2011
Service cost	$	6		$	1		$	1		$	—		$	—
Interest cost		23			6			11			1			1
Expected return on plan assets		(16	)		(6	)		(8	)		—			—
Net amortization		5			2			3			—			—
Net cost (income)	$	18		$	3		$	7		$	1		$	1
Nine Months Ended September 30, 2011
Service cost	$	16		$	4		$	5		$	1		$	1
Interest cost		69			18			31			3			3
Expected return on plan assets		(48	)		(19	)		(23	)		(1	)		(1	)
Net amortization		15			5			8			—			—
Net cost (income)	$	52		$	8		$	21		$	3		$	3
Three Months Ended September 30, 2010
Service cost	$	6		$	2		$	3		$	—		$	—
Interest cost		25			7			11			1			2
Expected return on plan assets		(15	)		(7	)		(8	)		—			—
Net amortization		5			2			2			—			—
Net cost (income)	$	21		$	4		$	8		$	1		$	2
Nine Months Ended September 30, 2010
Service cost	$	19		$	5		$	7		$	1		$	1
Interest cost		75			20			33			3			4
Expected return on plan assets		(47	)		(19	)		(23	)		(1	)		(1	)
Net amortization		15			5			8			—			—
Net cost (income)	$	62		$	11		$	25		$	3		$	4

XML

Derivatives (Tables)

9 Months Ended

Sep. 30, 2011

Derivatives [Abstract]

Energy-related derivative contracts

	Power						Gas
			Longest		Longest		Net		Longest		Longest
	Net Sold		Hedge		Non-Hedge		Purchased		Hedge		Non-Hedge
	MWHs		Date		Date		mmBtu		Date		Date
	(in millions)						(in millions)
Southern Company		0.3		—		2011		160		2015		2015
Alabama Power		—		—		—		31		2015		—
Georgia Power		—		—		—		66		2015		—
Gulf Power		—		—		—		26		2015		—
Mississippi Power		—		—		—		31		2015		—
Southern Power		0.3		—		2011		7		2012		2015

Notional amount of interest rate derivatives

	Notional		Interest Rate			Interest Rate			Hedge Maturity	Fair Value Gain (Loss)
	Amount		Received			Paid			Date	September 30, 2011
	(in millions)									(in millions)
Cash flow hedges of existing debt
Southern Company	$	300	3-month LIBOR + 0.40% spread				1.24	%*	October 2011	$	—
Cash flow hedges of forecasted debt
Alabama Power		300	3-month LIBOR				2.90	%*	December 2022		(12	)
Mississippi Power		150	3-month LIBOR				2.37	%*	September 2021		(4	)
Mississippi Power		150	3-month LIBOR				1.25	%*	September 2016		—
Mississippi Power		300	3-month LIBOR				2.66	%*	April 2022		(11	)
Fair value hedges of existing debt
						3-month LIBOR +
Southern Company		350		4.15	%	1.96%* spread			May 2014		16
Total	$	1,550								$	(11	)

* Weighted Average

Total deferred gains and losses are expected to be amortized into earnings

	Estimated Gain (Loss)to
	be Reclassified for the			Total Deferred
	12 Months Ending			Gains (Losses)
Registrant	September 30, 2012			Amortized Through
	(in millions)
Southern Company	$	(16	)		2037
Alabama Power		—			2035
Georgia Power		(3	)		2037
Gulf Power		(1	)		2020
Mississippi Power		(1	)		2022
Southern Power		(11	)		2016

Notional amount of foreign currency derivatives

				Fair Value Gain
	Notional	Average	Hedge	(Loss)
	Amount	Forward Rate	Maturity Date	September 30, 2011
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR28.3	1.297 Dollars per Euro	Various through March 2014	$	1

Fair value of energy-related derivatives and interest rate derivatives

Asset Derivatives at September 30, 2011
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf Power		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	1	$	—	$	1	$	—	$	—
Other deferred charges and assets		1		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	2	$	—	$	2	$	—	$	—		N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	6	$	—	$	—	$	—	$	—	$	—
Other deferred charges and assets		10		—		—		—		—		—
Foreign currency derivatives:
Other current assets		3		—		—		—		3		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	19	$	—	$	—	$	—	$	3	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets*	$	1	$	—	$	—	$	—	$	—	$	—
Assets from risk management activities		—		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	1	$	—	$	—	$	—	$	—	$	1
Total asset derivatives	$	22	$	—	$	2	$	—	$	3	$	1

* Southern Company includes “Assets from risk management activities” in “Other current assets” where applicable.

Liability Derivatives at September 30, 2011
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	114	$	24	$	53	$	10	$	27
Other deferred credits and liabilities		35		5		15		7		8
Total derivatives designated as hedging instruments for regulatory purposes	$	149	$	29	$	68	$	17	$	35		N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Liabilities from risk management activities	$	15	$	—	$	—	$	—	$	15	$	—
Other deferred credits and liabilities		12		12		—		—		—		—
Foreign currency derivatives:
Liabilities from risk management activities		2		—		—		—		2		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	29	$	12	$	—	$	—	$	17	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	5	$	—	$	—	$	—	$	—	$	5
Total liability derivatives	$	183	$	41	$	68	$	17	$	52	$	5

Pre-tax effect of unrealized derivative gains (losses)

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet	Southern			Alabama			Georgia			Gulf			Mississippi
Location	Company			Power			Power			Power			Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(114	)	$	(24	)	$	(53	)	$	(10	)	$	(27	)
Other regulatory assets, deferred		(35	)		(5	)		(15	)		(7	)		(8	)
Other regulatory liabilities, current		1			—			—			—			—
Other current liabilities*		—			—			1			—			—
Other regulatory liabilities, deferred		1			—			—			—			—
Other deferred credits and liabilities**		—			—			1			—			—
Total energy-related derivative gains (losses)	$	(147	)	$	(29	)	$	(66	)	$	(17	)	$	(35	)

*	Georgia Power includes “Other regulatory liabilities, current” in “Other current liabilities.”
**	Georgia Power includes “Other regulatory liabilities, deferred” in “Other deferred credits and liabilities.”

Pre-tax effect of derivatives designated as cash flow hedging instruments

	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI into
Derivatives in Cash Flow	on Derivative						Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2011			2010				2011			2010
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	—		$	3		Fuel	$	—		$	—
Interest rate derivatives		(27	)		(1	)	Interest expense, net of amounts capitalized		(5	)		(7	)
Total	$	(27	)	$	2			$	(5	)	$	(7	)
Alabama Power
Interest rate derivatives	$	(12	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(3	)
Gulf Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	—		$	—
Mississippi Power
Interest rate derivatives	$	(15	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	—		$	3		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense, net of amounts capitalized		(3	)		(3	)
Total	$	—		$	3			$	(3	)	$	(3	)

For the nine months ended September 30, 2011 and September 30, 2010, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI into
Derivatives in Cash Flow	on Derivative						Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2011			2010				2011			2010
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	1		$	4		Fuel	$	—		$	—
Interest rate derivatives		(23	)		(3	)	Interest expense, net of amounts capitalized		(10	)		(24	)
Total	$	(22	)	$	1			$	(10	)	$	(24	)
Alabama Power
Interest rate derivatives	$	(8	)	$	—		Interest expense, net of amounts capitalized	$	3		$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(13	)
Gulf Power
Interest rate derivatives	$	—		$	(1	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Mississippi Power
Interest rate derivatives	$	(15	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	1		$	4		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense, net of amounts capitalized		(8	)		(8	)
Total	$	1		$	4			$	(8	)	$	(8	)

Fair value of derivative liabilities with contingent features

	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power
					(in millions)
Derivative liabilities	$	32	$	7	$	16	$	2	$	5	$	2

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Consolidated Net Income	$ 933,000,000	$ 834,000,000	$ 1,991,000,000	$ 1,871,000,000
Net Income After Dividends on Preferred and Preference Stock	916,000,000	817,000,000	1,942,000,000	1,822,000,000
Qualifying hedges:
Changes in fair value, net of tax	(17,000,000)	2,000,000	(14,000,000)	1,000,000
Reclassification adjustment for amounts included in net income, net of tax	3,000,000	3,000,000	6,000,000	14,000,000
Marketable securities:
Change in fair value, net of tax	(5,000,000)	(3,000,000)	(3,000,000)
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax				1,000,000
Total other comprehensive income (loss)	(19,000,000)	2,000,000	(11,000,000)	16,000,000
Dividends on preferred and preference stock of subsidiaries	(17,000,000)	(17,000,000)	(49,000,000)	(49,000,000)
Comprehensive Income	897,000,000	819,000,000	1,931,000,000	1,838,000,000
Alabama Power [Member]
Consolidated Net Income	274,000,000	269,000,000	636,000,000	682,000,000
Net Income After Dividends on Preferred and Preference Stock	264,000,000	259,000,000	606,000,000	652,000,000
Qualifying hedges:
Changes in fair value, net of tax	(8,000,000)		(5,000,000)
Reclassification adjustment for amounts included in net income, net of tax			(2,000,000)
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	(8,000,000)		(7,000,000)
Dividends on preferred and preference stock of subsidiaries	(10,000,000)	(10,000,000)	(30,000,000)	(30,000,000)
Comprehensive Income	256,000,000	259,000,000	599,000,000	652,000,000
Georgia Power [Member]
Consolidated Net Income	524,000,000	424,000,000	1,048,000,000	909,000,000
Net Income After Dividends on Preferred and Preference Stock	520,000,000	420,000,000	1,035,000,000	896,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	2,000,000	2,000,000	8,000,000
Pension and other post retirement benefit plans:
Dividends on preferred and preference stock of subsidiaries	(4,000,000)	(4,000,000)	(13,000,000)	(13,000,000)
Comprehensive Income	521,000,000	422,000,000	1,037,000,000	904,000,000
Gulf Power [Member]
Consolidated Net Income	42,768,000	44,458,000	90,912,000	105,176,000
Net Income After Dividends on Preferred and Preference Stock	41,217,000	42,907,000	86,260,000	100,524,000
Qualifying hedges:
Changes in fair value, net of tax				(863,000)
Reclassification adjustment for amounts included in net income, net of tax	143,000	143,000	430,000	455,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	143,000	143,000	430,000	(408,000)
Dividends on preferred and preference stock of subsidiaries	(1,551,000)	(1,551,000)	(4,652,000)	(4,652,000)
Comprehensive Income	41,360,000	43,050,000	86,690,000	100,116,000
Mississippi Power [Member]
Consolidated Net Income	38,452,000	34,026,000	79,218,000	65,364,000
Net Income After Dividends on Preferred and Preference Stock	38,019,000	33,593,000	77,919,000	64,065,000
Qualifying hedges:
Changes in fair value, net of tax	(9,090,000)	7,000	(9,079,000)	13,000
Pension and other post retirement benefit plans:
Dividends on preferred and preference stock of subsidiaries	(433,000)	(433,000)	(1,299,000)	(1,299,000)
Comprehensive Income	28,929,000	33,600,000	68,840,000	64,078,000
Southern Power [Member]
Consolidated Net Income	56,071,000	62,576,000	138,415,000	108,867,000
Qualifying hedges:
Changes in fair value, net of tax	(206,000)	1,759,000	402,000	2,400,000
Reclassification adjustment for amounts included in net income, net of tax	1,685,000	1,590,000	4,946,000	4,703,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	1,479,000	3,349,000	5,348,000	7,103,000
Comprehensive Income	$ 57,550,000	$ 65,925,000	$ 143,763,000	$ 115,970,000

XML

Derivatives

9 Months Ended

Sep. 30, 2011

Derivatives [Abstract]

DERIVATIVES

(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.

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 electric utilities may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the electric utilities 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 in 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, 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, 2011, the net volume of energy-related derivative contracts for power and natural gas positions for the registrants, 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:

	Power						Gas
			Longest		Longest		Net		Longest		Longest
	Net Sold		Hedge		Non-Hedge		Purchased		Hedge		Non-Hedge
	MWHs		Date		Date		mmBtu		Date		Date
	(in millions)						(in millions)
Southern Company		0.3		—		2011		160		2015		2015
Alabama Power		—		—		—		31		2015		—
Georgia Power		—		—		—		66		2015		—
Gulf Power		—		—		—		26		2015		—
Mississippi Power		—		—		—		31		2015		—
Southern Power		0.3		—		2011		7		2012		2015

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 was 2.95 million mmBtu for Southern Company, 2.69 million mmBtu for Georgia Power, and was immaterial for the other registrants.

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending September 30, 2012 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries 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, 2011, the following interest rate derivatives were outstanding:

	Notional		Interest Rate			Interest Rate			Hedge Maturity	Fair Value Gain (Loss)
	Amount		Received			Paid			Date	September 30, 2011
	(in millions)									(in millions)
Cash flow hedges of existing debt
Southern Company	$	300	3-month LIBOR + 0.40% spread				1.24	%*	October 2011	$	—
Cash flow hedges of forecasted debt
Alabama Power		300	3-month LIBOR				2.90	%*	December 2022		(12	)
Mississippi Power		150	3-month LIBOR				2.37	%*	September 2021		(4	)
Mississippi Power		150	3-month LIBOR				1.25	%*	September 2016		—
Mississippi Power		300	3-month LIBOR				2.66	%*	April 2022		(11	)
Fair value hedges of existing debt
						3-month LIBOR +
Southern Company		350		4.15	%	1.96%* spread			May 2014		16
Total	$	1,550								$	(11	)

* Weighted Average

The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending September 30, 2012, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.

	Estimated Gain (Loss)to
	be Reclassified for the			Total Deferred
	12 Months Ending			Gains (Losses)
Registrant	September 30, 2012			Amortized Through
	(in millions)
Southern Company	$	(16	)		2037
Alabama Power		—			2035
Georgia Power		(3	)		2037
Gulf Power		(1	)		2020
Mississippi Power		(1	)		2022
Southern Power		(11	)		2016

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 recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At September 30, 2011, the following foreign currency derivatives were outstanding:

				Fair Value Gain
	Notional	Average	Hedge	(Loss)
	Amount	Forward Rate	Maturity Date	September 30, 2011
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR28.3	1.297 Dollars per Euro	Various through March 2014	$	1

Derivative Financial Statement Presentation and Amounts

At September 30, 2011, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

Asset Derivatives at September 30, 2011
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf Power		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	1	$	—	$	1	$	—	$	—
Other deferred charges and assets		1		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	2	$	—	$	2	$	—	$	—		N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	6	$	—	$	—	$	—	$	—	$	—
Other deferred charges and assets		10		—		—		—		—		—
Foreign currency derivatives:
Other current assets		3		—		—		—		3		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	19	$	—	$	—	$	—	$	3	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets*	$	1	$	—	$	—	$	—	$	—	$	—
Assets from risk management activities		—		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	1	$	—	$	—	$	—	$	—	$	1
Total asset derivatives	$	22	$	—	$	2	$	—	$	3	$	1

* Southern Company includes “Assets from risk management activities” in “Other current assets” where applicable.

Liability Derivatives at September 30, 2011
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	114	$	24	$	53	$	10	$	27
Other deferred credits and liabilities		35		5		15		7		8
Total derivatives designated as hedging instruments for regulatory purposes	$	149	$	29	$	68	$	17	$	35		N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Liabilities from risk management activities	$	15	$	—	$	—	$	—	$	15	$	—
Other deferred credits and liabilities		12		12		—		—		—		—
Foreign currency derivatives:
Liabilities from risk management activities		2		—		—		—		2		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	29	$	12	$	—	$	—	$	17	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	5	$	—	$	—	$	—	$	—	$	5
Total liability derivatives	$	183	$	41	$	68	$	17	$	52	$	5

All derivative instruments are measured at fair value. See Note (C) herein for additional information.

At September 30, 2011, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheet was as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet	Southern			Alabama			Georgia			Gulf			Mississippi
Location	Company			Power			Power			Power			Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(114	)	$	(24	)	$	(53	)	$	(10	)	$	(27	)
Other regulatory assets, deferred		(35	)		(5	)		(15	)		(7	)		(8	)
Other regulatory liabilities, current		1			—			—			—			—
Other current liabilities*		—			—			1			—			—
Other regulatory liabilities, deferred		1			—			—			—			—
Other deferred credits and liabilities**		—			—			1			—			—
Total energy-related derivative gains (losses)	$	(147	)	$	(29	)	$	(66	)	$	(17	)	$	(35	)

*	Georgia Power includes “Other regulatory liabilities, current” in “Other current liabilities.”
**	Georgia Power includes “Other regulatory liabilities, deferred” in “Other deferred credits and liabilities.”

For the three months and nine months ended September 30, 2011, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were $5 million and $7 million, respectively. For the three months and nine months ended September 30, 2010, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were $9 million and $17 million, respectively. These amounts were offset with changes in the fair value of the hedged debt.

For the three months and nine months ended September 30, 2011, the pre-tax (losses) from foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were $(3) million and $(2) million, respectively. For each of the three months and nine months ended September 30, 2010, the pre-tax gains from foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were $5 million. These amounts were offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there is no impact on Southern Company’s or Mississippi Power’s statements of income.

For the three months ended September 30, 2011 and September 30, 2010, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI into
Derivatives in Cash Flow	on Derivative						Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2011			2010				2011			2010
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	—		$	3		Fuel	$	—		$	—
Interest rate derivatives		(27	)		(1	)	Interest expense, net of amounts capitalized		(5	)		(7	)
Total	$	(27	)	$	2			$	(5	)	$	(7	)
Alabama Power
Interest rate derivatives	$	(12	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(3	)
Gulf Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	—		$	—
Mississippi Power
Interest rate derivatives	$	(15	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	—		$	3		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense, net of amounts capitalized		(3	)		(3	)
Total	$	—		$	3			$	(3	)	$	(3	)

For the nine months ended September 30, 2011 and September 30, 2010, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI into
Derivatives in Cash Flow	on Derivative						Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2011			2010				2011			2010
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	1		$	4		Fuel	$	—		$	—
Interest rate derivatives		(23	)		(3	)	Interest expense, net of amounts capitalized		(10	)		(24	)
Total	$	(22	)	$	1			$	(10	)	$	(24	)
Alabama Power
Interest rate derivatives	$	(8	)	$	—		Interest expense, net of amounts capitalized	$	3		$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(13	)
Gulf Power
Interest rate derivatives	$	—		$	(1	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Mississippi Power
Interest rate derivatives	$	(15	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	1		$	4		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense, net of amounts capitalized		(8	)		(8	)
Total	$	1		$	4			$	(8	)	$	(8	)

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three months and nine months ended September 30, 2011 and September 30, 2010, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2011, the fair value of derivative liabilities with contingent features, by registrant, was as follows:

	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power
					(in millions)
Derivative liabilities	$	32	$	7	$	16	$	2	$	5	$	2

At September 30, 2011, the registrants had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $32 million for each registrant.

Currently, each of the registrants has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock. 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 has a credit rating change to below investment grade.

XML

Financing (Details) (USD $) In Millions	Sep. 30, 2011
Credit arrangements by company
Total	$ 5,132
Unused	5,127
Executable Term-Loans, One Year	216
Executable Term-Loans, Two Years	41
Expires, 2011	96
Expires, 2012	316
Expires, 2013 and Beyond	4,720
Expires Within One Year, Term Out	257
Expires Within One Year, No Term Out	156
Southern Company [Member]
Credit arrangements by company
Total	1,000
Unused	1,000
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Expires, 2011	0
Expires, 2012	0
Expires, 2013 and Beyond	1,000
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
Alabama Power [Member]
Credit arrangements by company
Total	1,296
Unused	1,296
Executable Term-Loans, One Year	111
Executable Term-Loans, Two Years	0
Expires, 2011	60
Expires, 2012	121
Expires, 2013 and Beyond	1,115
Expires Within One Year, Term Out	111
Expires Within One Year, No Term Out	71
Georgia Power [Member]
Credit arrangements by company
Total	1,750
Unused	1,745
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Expires, 2011	0
Expires, 2012	0
Expires, 2013 and Beyond	1,750
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
Gulf Power [Member]
Credit arrangements by company
Total	240
Unused	240
Executable Term-Loans, One Year	55
Executable Term-Loans, Two Years	0
Expires, 2011	20
Expires, 2012	55
Expires, 2013 and Beyond	165
Expires Within One Year, Term Out	55
Expires Within One Year, No Term Out	20
Mississippi Power [Member]
Credit arrangements by company
Total	296
Unused	296
Executable Term-Loans, One Year	25
Executable Term-Loans, Two Years	41
Expires, 2011	16
Expires, 2012	115
Expires, 2013 and Beyond	165
Expires Within One Year, Term Out	66
Expires Within One Year, No Term Out	65
Southern Power [Member]
Credit arrangements by company
Total	500
Unused	500
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Expires, 2011	0
Expires, 2012	0
Expires, 2013 and Beyond	500
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
Other Subsidiaries [Member]
Credit arrangements by company
Total	50
Unused	50
Executable Term-Loans, One Year	25
Executable Term-Loans, Two Years	0
Expires, 2011	0
Expires, 2012	25
Expires, 2013 and Beyond	25
Expires Within One Year, Term Out	25
Expires Within One Year, No Term Out	$ 0

XML

Stockholders Equity (Tables)

9 Months Ended

Sep. 30, 2011

Stockholders' Equity [Abstract]

Earnings per Share

	Three Months		Three Months		Nine Months		Nine Months
	Ended		Ended		Ended		Ended
	September 30, 2011		September 30, 2010		September 30, 2011		September 30, 2010
	(in millions)
As reported shares		860		836		854		829
Effect of options		8		6		7		4
Diluted shares		868		842		861		833

Changes in Stockholders' Equity

									Preferred and
	Number of					Common			Preference		Total
	Common Shares					Stockholders’			Stock of		Stockholders’
	Issued		Treasury			Equity			Subsidiaries		Equity
	(in thousands)								(in millions)
Balance at December 31, 2010		843,814		(474	)	$	16,202		$	707	$	16,909
Net income after dividends on preferred and preference stock		—		—			1,942			—		1,942
Other comprehensive income (loss)		—		—			(11	)		—		(11	)
Stock issued		18,634		—			692			—		692
Cash dividends on common stock		—		—			(1,193	)		—		(1,193	)
Other		—		(45	)		1			—		1
Balance at September 30, 2011		862,448		(519	)	$	17,633		$	707	$	18,340
Balance at December 31, 2009		820,152		(505	)	$	14,878		$	707	$	15,585
Net income after dividends on preferred and preference stock		—		—			1,822			—		1,822
Other comprehensive income (loss)		—		—			16			—		16
Stock issued		18,994		—			650			—		650
Cash dividends on common stock		—		—			(1,114	)		—		(1,114	)
Other		—		30			3			—		3
Balance at September 30, 2010		839,146		(475	)	$	16,255		$	707	$	16,962

XML

Condensed Consolidated Statements of Income (Unaudited) (USD $) Share data in Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Operating Revenues:
Retail revenues	$ 4,693,000,000	$ 4,573,000,000	$ 11,931,000,000	$ 11,603,000,000
Wholesale revenues	557,000,000	566,000,000	1,513,000,000	1,581,000,000
Other electric revenues	161,000,000	160,000,000	464,000,000	438,000,000
Other revenues	17,000,000	21,000,000	53,000,000	63,000,000
Total operating revenues	5,428,000,000	5,320,000,000	13,961,000,000	13,685,000,000
Operating Expenses:
Fuel	1,908,000,000	1,970,000,000	5,057,000,000	5,244,000,000
Purchased power	215,000,000	209,000,000	460,000,000	464,000,000
Other operations and maintenance	983,000,000	1,019,000,000	2,837,000,000	2,846,000,000
Depreciation and amortization	431,000,000	427,000,000	1,279,000,000	1,137,000,000
Taxes other than income taxes	239,000,000	236,000,000	686,000,000	662,000,000
Total operating expenses	3,776,000,000	3,861,000,000	10,319,000,000	10,353,000,000
Operating Income	1,652,000,000	1,459,000,000	3,642,000,000	3,332,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	42,000,000	45,000,000	113,000,000	140,000,000
Interest expense, net of amounts capitalized	(217,000,000)	(225,000,000)	(638,000,000)	(666,000,000)
Other income (expense), net	(1,000,000)	(3,000,000)	(3,000,000)	(10,000,000)
Total other income and (expense)	(176,000,000)	(183,000,000)	(528,000,000)	(536,000,000)
Earnings Before Income Taxes	1,476,000,000	1,276,000,000	3,114,000,000	2,796,000,000
Income taxes	543,000,000	442,000,000	1,123,000,000	925,000,000
Consolidated Net Income	933,000,000	834,000,000	1,991,000,000	1,871,000,000
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	916,000,000	817,000,000	1,942,000,000	1,822,000,000
Earnings per share (EPS) -
Basic EPS	$ 1.07	$ 0.98	$ 2.27	$ 2.20
Diluted EPS	$ 1.06	$ 0.97	$ 2.26	$ 2.19
Average number of shares of common stock outstanding (in millions)
Basic	860	836	854	829
Diluted	868	842	861	833
Cash dividends paid per share of common stock	$ 0.4725	$ 0.4550	$ 1.4000	$ 1.3475
Alabama Power [Member]
Operating Revenues:
Retail revenues	1,489,000,000	1,527,000,000	3,859,000,000	3,925,000,000
Wholesale revenues, non-affiliates	80,000,000	86,000,000	218,000,000	395,000,000
Wholesale revenues, affiliates	52,000,000	43,000,000	202,000,000	194,000,000
Other revenues	50,000,000	50,000,000	152,000,000	149,000,000
Total operating revenues	1,671,000,000	1,706,000,000	4,431,000,000	4,663,000,000
Operating Expenses:
Fuel	512,000,000	500,000,000	1,335,000,000	1,455,000,000
Purchased power, non-affiliates	34,000,000	35,000,000	62,000,000	66,000,000
Purchased power, affiliates	49,000,000	57,000,000	152,000,000	161,000,000
Other operations and maintenance	309,000,000	379,000,000	896,000,000	997,000,000
Depreciation and amortization	160,000,000	153,000,000	476,000,000	451,000,000
Taxes other than income taxes	84,000,000	85,000,000	254,000,000	248,000,000
Total operating expenses	1,148,000,000	1,209,000,000	3,175,000,000	3,378,000,000
Operating Income	523,000,000	497,000,000	1,256,000,000	1,285,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	7,000,000	9,000,000	18,000,000	29,000,000
Interest income	4,000,000	4,000,000	13,000,000	12,000,000
Interest expense, net of amounts capitalized	(73,000,000)	(76,000,000)	(224,000,000)	(227,000,000)
Other income (expense), net	(7,000,000)	(7,000,000)	(20,000,000)	(18,000,000)
Total other income and (expense)	(69,000,000)	(70,000,000)	(213,000,000)	(204,000,000)
Earnings Before Income Taxes	454,000,000	427,000,000	1,043,000,000	1,081,000,000
Income taxes	180,000,000	158,000,000	407,000,000	399,000,000
Consolidated Net Income	274,000,000	269,000,000	636,000,000	682,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	10,000,000	10,000,000	30,000,000	30,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	264,000,000	259,000,000	606,000,000	652,000,000
Georgia Power [Member]
Operating Revenues:
Retail revenues	2,609,000,000	2,418,000,000	6,494,000,000	6,036,000,000
Wholesale revenues, non-affiliates	90,000,000	109,000,000	270,000,000	307,000,000
Wholesale revenues, affiliates	4,000,000	17,000,000	31,000,000	43,000,000
Other revenues	85,000,000	84,000,000	247,000,000	226,000,000
Total operating revenues	2,788,000,000	2,628,000,000	7,042,000,000	6,612,000,000
Operating Expenses:
Fuel	838,000,000	928,000,000	2,299,000,000	2,443,000,000
Purchased power, non-affiliates	127,000,000	128,000,000	297,000,000	294,000,000
Purchased power, affiliates	193,000,000	143,000,000	513,000,000	437,000,000
Other operations and maintenance	453,000,000	435,000,000	1,294,000,000	1,224,000,000
Depreciation and amortization	180,000,000	182,000,000	531,000,000	426,000,000
Taxes other than income taxes	102,000,000	98,000,000	283,000,000	264,000,000
Total operating expenses	1,893,000,000	1,914,000,000	5,217,000,000	5,088,000,000
Operating Income	895,000,000	714,000,000	1,825,000,000	1,524,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	26,000,000	34,000,000	73,000,000	105,000,000
Interest expense, net of amounts capitalized	(90,000,000)	(95,000,000)	(257,000,000)	(275,000,000)
Other income (expense), net	(4,000,000)	(5,000,000)	(10,000,000)	(12,000,000)
Total other income and (expense)	(68,000,000)	(66,000,000)	(194,000,000)	(182,000,000)
Earnings Before Income Taxes	827,000,000	648,000,000	1,631,000,000	1,342,000,000
Income taxes	303,000,000	224,000,000	583,000,000	433,000,000
Consolidated Net Income	524,000,000	424,000,000	1,048,000,000	909,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	4,000,000	4,000,000	13,000,000	13,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	520,000,000	420,000,000	1,035,000,000	896,000,000
Gulf Power [Member]
Operating Revenues:
Retail revenues	362,109,000	396,671,000	957,409,000	1,021,530,000
Wholesale revenues, non-affiliates	33,921,000	31,211,000	103,814,000	86,041,000
Wholesale revenues, affiliates	52,833,000	37,995,000	79,825,000	88,386,000
Other revenues	19,167,000	17,578,000	50,855,000	47,381,000
Total operating revenues	468,030,000	483,455,000	1,191,903,000	1,243,338,000
Operating Expenses:
Fuel	220,305,000	237,003,000	530,773,000	585,167,000
Purchased power, non-affiliates	20,046,000	12,771,000	37,938,000	34,615,000
Purchased power, affiliates	9,941,000	20,282,000	39,108,000	51,725,000
Other operations and maintenance	74,144,000	67,178,000	227,236,000	202,202,000
Depreciation and amortization	32,673,000	34,032,000	96,733,000	90,651,000
Taxes other than income taxes	29,467,000	29,293,000	79,230,000	78,586,000
Total operating expenses	386,576,000	400,559,000	1,011,018,000	1,042,946,000
Operating Income	81,454,000	82,896,000	180,885,000	200,392,000
Other Income and (Expense):
Allowance for equity funds used during construction	2,434,000	1,424,000	7,091,000	4,504,000
Interest income	22,000	31,000	56,000	87,000
Interest expense, net of amounts capitalized	(15,156,000)	(13,764,000)	(43,208,000)	(38,286,000)
Other income (expense), net	(451,000)	(471,000)	(1,461,000)	(1,355,000)
Total other income and (expense)	(13,151,000)	(12,780,000)	(37,522,000)	(35,050,000)
Earnings Before Income Taxes	68,303,000	70,116,000	143,363,000	165,342,000
Income taxes	25,535,000	25,658,000	52,451,000	60,166,000
Consolidated Net Income	42,768,000	44,458,000	90,912,000	105,176,000
Dividends on Preferred and Preference Stock of Subsidiaries	1,551,000	1,551,000	4,652,000	4,652,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	41,217,000	42,907,000	86,260,000	100,524,000
Mississippi Power [Member]
Operating Revenues:
Retail revenues	233,298,000	230,977,000	620,777,000	620,658,000
Wholesale revenues, non-affiliates	78,147,000	78,409,000	215,811,000	223,499,000
Wholesale revenues, affiliates	9,804,000	13,025,000	25,407,000	31,636,000
Other revenues	4,517,000	4,672,000	13,088,000	11,749,000
Total operating revenues	325,766,000	327,083,000	875,083,000	887,542,000
Operating Expenses:
Fuel	157,961,000	154,607,000	402,689,000	388,979,000
Purchased power, non-affiliates	2,314,000	2,547,000	4,660,000	7,666,000
Purchased power, affiliates	8,504,000	10,902,000	36,721,000	60,113,000
Other operations and maintenance	65,851,000	65,953,000	200,730,000	205,055,000
Depreciation and amortization	19,668,000	20,106,000	59,876,000	57,567,000
Taxes other than income taxes	18,297,000	17,935,000	53,029,000	53,568,000
Total operating expenses	272,595,000	272,050,000	757,705,000	772,948,000
Operating Income	53,171,000	55,033,000	117,378,000	114,594,000
Other Income and (Expense):
Allowance for equity funds used during construction	7,291,000	1,490,000	15,413,000	2,018,000
Interest income	167,000	49,000	910,000	122,000
Interest expense, net of amounts capitalized	(3,856,000)	(4,886,000)	(15,401,000)	(17,011,000)
Other income (expense), net	257,000	1,099,000	(759,000)	3,272,000
Total other income and (expense)	3,859,000	(2,248,000)	163,000	(11,599,000)
Earnings Before Income Taxes	57,030,000	52,785,000	117,541,000	102,995,000
Income taxes	18,578,000	18,759,000	38,323,000	37,631,000
Consolidated Net Income	38,452,000	34,026,000	79,218,000	65,364,000
Dividends on Preferred and Preference Stock of Subsidiaries	433,000	433,000	1,299,000	1,299,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	38,019,000	33,593,000	77,919,000	64,065,000
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	274,980,000	261,551,000	705,106,000	568,877,000
Wholesale revenues, affiliates	85,177,000	93,062,000	239,020,000	287,603,000
Other revenues	2,408,000	2,217,000	5,435,000	5,314,000
Total operating revenues	362,565,000	356,830,000	949,561,000	861,794,000
Operating Expenses:
Fuel	141,968,000	120,466,000	345,841,000	294,658,000
Purchased power, non-affiliates	25,159,000	24,939,000	53,765,000	59,103,000
Purchased power, affiliates	11,423,000	31,454,000	48,700,000	79,874,000
Other operations and maintenance	39,571,000	34,886,000	122,372,000	112,132,000
Depreciation and amortization	31,558,000	29,361,000	92,530,000	87,362,000
Taxes other than income taxes	4,178,000	4,071,000	13,506,000	14,314,000
Total operating expenses	253,857,000	245,177,000	676,714,000	647,443,000
Operating Income	108,708,000	111,653,000	272,847,000	214,351,000
Other Income and (Expense):
Interest expense, net of amounts capitalized	(19,886,000)	(18,801,000)	(56,489,000)	(58,408,000)
Other income (expense), net	(158,000)	(209,000)	(359,000)	(104,000)
Total other income and (expense)	(20,044,000)	(19,010,000)	(56,848,000)	(58,512,000)
Earnings Before Income Taxes	88,664,000	92,643,000	215,999,000	155,839,000
Income taxes	32,593,000	30,067,000	77,584,000	46,972,000
Consolidated Net Income	$ 56,071,000	$ 62,576,000	$ 138,415,000	$ 108,867,000

XML

Retirement Benefits (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Alabama Power [Member] | Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	$ 11	$ 10	$ 32	$ 31
Interest cost	24	25	72	73
Expected return on plan assets	(44)	(42)	(130)	(126)
Net amortization	3	3	10	8
Net cost (income)	(6)	(4)	(16)	(14)
Alabama Power [Member] | Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost	1	2	4	5
Interest cost	6	7	18	20
Expected return on plan assets	(6)	(7)	(19)	(19)
Net amortization	2	2	5	5
Net cost (income)	3	4	8	11
Georgia Power [Member] | Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	14	13	43	40
Interest cost	36	36	108	109
Expected return on plan assets	(59)	(54)	(176)	(164)
Net amortization	5	4	14	11
Net cost (income)	(4)	(1)	(11)	(4)
Georgia Power [Member] | Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost	1	3	5	7
Interest cost	11	11	31	33
Expected return on plan assets	(8)	(8)	(23)	(23)
Net amortization	3	2	8	8
Net cost (income)	7	8	21	25
Gulf Power [Member] | Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	2	2	6	6
Interest cost	4	5	13	13
Expected return on plan assets	(6)	(6)	(20)	(18)
Net amortization			1	1
Net cost (income)		1		2
Gulf Power [Member] | Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost			1	1
Interest cost	1	1	3	3
Expected return on plan assets			(1)	(1)
Net cost (income)	1	1	3	3
Mississippi Power [Member] | Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	3	2	7	6
Interest cost	4	4	13	13
Expected return on plan assets	(7)	(5)	(19)	(16)
Net amortization	1	1	2	2
Net cost (income)	1	2	3	5
Mississippi Power [Member] | Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost			1	1
Interest cost	1	2	3	4
Expected return on plan assets			(1)	(1)
Net cost (income)	1	2	3	4
Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	46	43	138	129
Interest cost	97	98	292	293
Expected return on plan assets	(152)	(138)	(456)	(413)
Net amortization	14	11	40	32
Net cost (income)	5	14	14	41
Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost	6	6	16	19
Interest cost	23	25	69	75
Expected return on plan assets	(16)	(15)	(48)	(47)
Net amortization	5	5	15	15
Net cost (income)	$ 18	$ 21	$ 52	$ 62

XML

Effective Tax Rate and Unrecognized Tax Benefits (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended		12 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2010	$ 296
Tax positions from current periods	43
Tax positions from prior periods	(108)
Reductions due to settlements	(112)
Reductions due to expired statute of limitations
Balance as of September 30, 2011	119		296
Impact on effective tax rate
Tax positions impacting the effective tax rate	76		217
Tax positions not impacting the effective tax rate	43		79
Balance of unrecognized tax benefits	119		296
Accrued interest for unrecognized tax benefits
Interest accrued as of December 31, 2010	29
Interest reclassified due to settlements	(24)
Interest accrued during the period	4
Balance as of September 30, 2011	9		29
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	36.10%	33.10%
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern	Next 12 Months
Positive cash flow due to tax accounting method for repair costs			297
Alabama Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2010	43
Tax positions from current periods	2
Tax positions from prior periods	(18)
Reductions due to expired statute of limitations
Balance as of September 30, 2011	27		43
Impact on effective tax rate
Balance of unrecognized tax benefits	27		43
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	39.00%	36.90%
Positive cash flow due to tax accounting method for repair costs			141
Georgia Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2010	237
Tax positions from current periods	7
Tax positions from prior periods	(87)
Reductions due to settlements	(112)
Reductions due to expired statute of limitations
Balance as of September 30, 2011	45		237
Impact on effective tax rate
Tax positions impacting the effective tax rate	28
Tax positions not impacting the effective tax rate	17
Balance of unrecognized tax benefits	45		237
Accrued interest for unrecognized tax benefits
Interest accrued as of December 31, 2010	27
Interest reclassified due to settlements	(24)
Interest accrued during the period	2
Balance as of September 30, 2011	5		27
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	35.80%	32.30%
Positive cash flow due to tax accounting method for repair costs			133
Gulf Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2010	4
Tax positions from current periods	1
Tax positions from prior periods	(2)
Reductions due to expired statute of limitations
Balance as of September 30, 2011	3		4
Impact on effective tax rate
Balance of unrecognized tax benefits	3		4
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	36.60%	36.40%
Positive cash flow due to tax accounting method for repair costs			8
Mississippi Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2010	4
Tax positions from current periods	1
Tax positions from prior periods	(1)
Reductions due to expired statute of limitations
Balance as of September 30, 2011	4		4
Impact on effective tax rate
Balance of unrecognized tax benefits	4		4
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	32.60%	36.50%
Positive cash flow due to tax accounting method for repair costs			5
Other Registrants [Member]
Changes for unrecognized tax benefits
Balance as of September 30, 2011	37
Impact on effective tax rate
Tax positions impacting the effective tax rate	12
Tax positions not impacting the effective tax rate	25
Balance of unrecognized tax benefits	37
Accrued interest for unrecognized tax benefits
Interest accrued as of December 31, 2010	2
Interest accrued during the period	1
Balance as of September 30, 2011	3
Southern Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2010	2
Tax positions from current periods	1
Reductions due to expired statute of limitations
Balance as of September 30, 2011	3		2
Impact on effective tax rate
Balance of unrecognized tax benefits	3		2
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	35.90%	30.10%
Positive cash flow due to tax accounting method for repair costs			$ 6