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 March 31, 2012

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

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

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

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

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

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

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

Registrant	Description of Common Stock	Shares Outstanding         at March  31, 2012
The Southern Company	Par Value $5 Per Share	868,690,126
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	4,542,717
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

March 31, 2012

		Page     Number
DEFINITIONS			5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			7
	PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	The Southern Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		10
	Condensed Consolidated Statements of Comprehensive Income		11
	Condensed Consolidated Statements of Cash Flows		12
	Condensed Consolidated Balance Sheets		13
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
	Alabama Power Company
	Condensed Statements of Income		33
	Condensed Statements of Comprehensive Income		33
	Condensed Statements of Cash Flows		34
	Condensed Balance Sheets		35
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
	Georgia Power Company
	Condensed Statements of Income		51
	Condensed Statements of Comprehensive Income		51
	Condensed Statements of Cash Flows		52
	Condensed Balance Sheets		53
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		55
	Gulf Power Company
	Condensed Statements of Income		72
	Condensed Statements of Comprehensive Income		72
	Condensed Statements of Cash Flows		73
	Condensed Balance Sheets		74
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		76
	Mississippi Power Company
	Condensed Statements of Income		92
	Condensed Statements of Comprehensive Income		92
	Condensed Statements of Cash Flows		93
	Condensed Balance Sheets		94
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		96
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		115
	Condensed Consolidated Statements of Comprehensive Income		115
	Condensed Consolidated Statements of Cash Flows		116
	Condensed Consolidated Balance Sheets		117
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		119
	Notes to the Condensed Financial Statements		130
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		31
Item 4.	Controls and Procedures		31

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

March 31, 2012

		Page                      Number
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		160
Item 1A.	Risk Factors		160
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		Inapplicable
Item 3.	Defaults Upon Senior Securities		Inapplicable
Item 4.	Mine Safety Disclosures		Inapplicable
Item 5.	Other Information		Inapplicable
Item 6.	Exhibits		161
	Signatures		165

4

DEFINITIONS

Term	Meaning
2010 ARP	Alternate Rate Plan approved by the Georgia PSC for Georgia Power, which became effective January 1, 2011 and will continue through December 31, 2013
2011 IRP Update	Georgia Power’s 2011 Integrated Resource Plan update filed with the Georgia PSC on August 4, 2011
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
Clean Air Act	Clean Air Act Amendments of 1990
CPCN	Certificate of public convenience and necessity
CWIP	Construction work in progress
DOE	U.S. Department of Energy
ECO Plan	Mississippi Power’s Environmental Compliance Overview Plan
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
Form 10-K	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2011
GAAP	Generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany Interchange Contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
Kemper IGCC	Integrated coal gasification combined cycle facility under construction in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
MW	Megawatt
MWH	Megawatt-hour
NCCR	Georgia Power’s Nuclear Construction Cost Recovery
NDR	Alabama Power’s natural disaster reserve
NRC	Nuclear Regulatory Commission
NSR	New Source Review
OCI	Other Comprehensive Income
PEP	Mississippi Power’s Performance Evaluation Plan
Plant Vogtle Units 3 and 4	Two new nuclear generating units under construction at Plant Vogtle
Power Pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power Purchase Agreement
PSC	Public Service Commission
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
ROE	Return on equity
SEC	Securities and Exchange Commission

5

SMEPA	South Mississippi Electric Power Association
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, and other subsidiaries
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 retail sales, retail rates, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related estimated expenditures, future earnings, access to sources of capital, projections for the qualified pension plan and other postretirement benefit plan contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, estimated sales and purchases under new power sale and purchase agreements, 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, 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, FERC matters, and IRS and state tax audits;

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

• variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), 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 Plant Vogtle Units 3 and 4, including Georgia PSC approvals, NRC actions, and potential DOE loan guarantees;

• regulatory approvals and actions related to the Kemper IGCC, including Mississippi PSC approvals, potential DOE loan guarantees, the SMEPA purchase decision, utilization of investment tax credits, and the outcome of any further proceedings regarding the Mississippi PSC’s issuance of the CPCN;

• 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;

7

• 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.

8

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in millions)
Operating Revenues:
Retail revenues	$	3,092		$	3,396
Wholesale revenues		349			449
Other electric revenues		148			150
Other revenues		15			17
Total operating revenues		3,604			4,012
Operating Expenses:
Fuel		1,064			1,476
Purchased power		141			100
Other operations and maintenance		967			944
Depreciation and amortization		441			418
Taxes other than income taxes		225			220
Total operating expenses		2,838			3,158
Operating Income		766			854
Other Income and (Expense):
Allowance for equity funds used during construction		31			35
Interest expense, net of amounts capitalized		(211	)		(222	)
Other income (expense), net		(2	)		2
Total other income and (expense)		(182	)		(185	)
Earnings Before Income Taxes		584			669
Income taxes		200			231
Consolidated Net Income		384			438
Dividends on Preferred and Preference Stock of Subsidiaries		16			16
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	368		$	422
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.42		$	0.50
Diluted EPS	$	0.42		$	0.49
Average number of shares of common stock outstanding (in millions)
Basic		868			848
Diluted		877			854
Cash dividends paid per share of common stock	$	0.4725		$	0.4550

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

10

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in millions)
Consolidated Net Income	$	384		$	438
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $2 and $2, respectively		3			3
Reclassification adjustment for amounts included in net income, net of tax of $1 and $2, respectively		2			3
Marketable securities:
Change in fair value, net of tax of $- and $-, respectively		—			(1	)
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1 and $1, respectively		1			(1	)
Total other comprehensive income (loss)		6			4
Dividends on preferred and preference stock of subsidiaries		(16	)		(16	)
Comprehensive Income	$	374		$	426

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

11

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in millions)
Operating Activities:
Consolidated net income	$	384		$	438
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		529			501
Deferred income taxes		104			174
Allowance for equity funds used during construction		(31	)		(35	)
Pension, postretirement, and other employee benefits		16			(11	)
Stock based compensation expense		25			21
Other, net		2			(16	)
Changes in certain current assets and liabilities —
-Receivables		372			276
-Fossil fuel stock		(218	)		(42	)
-Other current assets		(60	)		(77	)
-Accounts payable		(136	)		(108	)
-Accrued taxes		(167	)		131
-Accrued compensation		(305	)		(277	)
-Other current liabilities		53			23
Net cash provided from operating activities		568			998
Investing Activities:
Property additions		(1,231	)		(1,086	)
Distribution of restricted cash		—			61
Nuclear decommissioning trust fund purchases		(336	)		(928	)
Nuclear decommissioning trust fund sales		334			924
Proceeds from property sales		2			14
Cost of removal, net of salvage		(32	)		(15	)
Change in construction payables		(156	)		136
Other investing activities		(8	)		10
Net cash used for investing activities		(1,427	)		(884	)
Financing Activities:
Increase (decrease) in notes payable, net		174			(54	)
Proceeds —
Long-term debt issuances		1,400			937
Interest-bearing refundable deposit related to asset sale		150			—
Common stock issuances		116			193
Redemptions —
Long-term debt		(827	)		(824	)
Payment of common stock dividends		(410	)		(385	)
Payment of dividends on preferred and preference stock of subsidiaries		(16	)		(16	)
Other financing activities		1			(2	)
Net cash provided from (used for) financing activities		588			(151	)
Net Change in Cash and Cash Equivalents		(271	)		(37	)
Cash and Cash Equivalents at Beginning of Period		1,315			447
Cash and Cash Equivalents at End of Period	$	1,044		$	410
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $21 and $17 capitalized for 2012 and 2011, respectively)	$	178		$	197
Income taxes (net of refunds)		2			(357	)
Noncash transactions — accrued property additions at end of period		420			531

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

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2012			At December 31, 2011
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,044		$	1,315
Restricted cash and cash equivalents		7			8
Receivables —
Customer accounts receivable		936			1,074
Unbilled revenues		358			376
Under recovered regulatory clause revenues		5			143
Other accounts and notes receivable		226			282
Accumulated provision for uncollectible accounts		(24	)		(26	)
Fossil fuel stock, at average cost		1,585			1,367
Materials and supplies, at average cost		898			903
Vacation pay		161			160
Prepaid expenses		519			385
Other regulatory assets, current		267			239
Other current assets		59			46
Total current assets		6,041			6,272
Property, Plant, and Equipment:
In service		60,073			59,744
Less accumulated depreciation		21,327			21,154
Plant in service, net of depreciation		38,746			38,590
Other utility plant, net		54			55
Nuclear fuel, at amortized cost		830			774
Construction work in progress		6,225			5,591
Total property, plant, and equipment		45,855			45,010
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,280			1,207
Leveraged leases		654			649
Miscellaneous property and investments		260			262
Total other property and investments		2,194			2,118
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,381			1,365
Unamortized debt issuance expense		163			156
Unamortized loss on reacquired debt		279			285
Deferred under recovered regulatory clause revenues		24			48
Other regulatory assets, deferred		3,486			3,532
Other deferred charges and assets		451			481
Total deferred charges and other assets		5,784			5,867
Total Assets	$	59,874		$	59,267

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

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders’ Equity	At March 31, 2012			At December 31, 2011
	(in millions)
Current Liabilities:
Securities due within one year	$	1,881		$	1,717
Interest-bearing refundable deposit related to asset sale		150			—
Notes payable		1,029			859
Accounts payable		1,262			1,553
Customer deposits		358			347
Accrued taxes —
Accrued income taxes		51			13
Unrecognized tax benefits		12			22
Other accrued taxes		198			425
Accrued interest		249			226
Accrued vacation pay		204			205
Accrued compensation		158			450
Liabilities from risk management activities		219			209
Other regulatory liabilities, current		153			125
Other current liabilities		393			426
Total current liabilities		6,317			6,577
Long-term Debt		19,051			18,647
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		9,001			8,809
Deferred credits related to income taxes		220			224
Accumulated deferred investment tax credits		651			611
Employee benefit obligations		2,432			2,442
Asset retirement obligations		1,341			1,321
Other cost of removal obligations		1,178			1,165
Other regulatory liabilities, deferred		324			297
Other deferred credits and liabilities		578			514
Total deferred credits and other liabilities		15,725			15,383
Total Liabilities		41,093			40,607
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 — March 31, 2012: 869 million shares
— December 31, 2011: 866 million shares
Treasury — March 31, 2012: 0.5 million shares
— December 31, 2011: 0.5 million shares
Par value		4,346			4,328
Paid-in capital		4,550			4,410
Treasury, at cost		(18	)		(17	)
Retained earnings		8,926			8,968
Accumulated other comprehensive loss		(105	)		(111	)
Total Common Stockholders’ Equity		17,699			17,578
Preferred and Preference Stock of Subsidiaries		707			707
Total Stockholders’ Equity		18,406			18,285
Total Liabilities and Stockholders’ Equity	$	59,874		$	59,267

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

14

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2012 vs. FIRST QUARTER 2011

OVERVIEW

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

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

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(54)	(12.8)

Southern Company’s first quarter 2012 net income after dividends on preferred and preference stock of subsidiaries was $368 million ($0.42 per share) compared to $422 million ($0.50 per share) for the first quarter 2011. The decrease for the first quarter 2012 when compared to the corresponding period in 2011 was primarily the result of a decrease in revenues due to milder weather, an increase in depreciation on additional plant in service related to new generation, transmission, distribution, and environmental projects, an increase in operations and maintenance expenses, and lower energy revenues at Southern Power. The net income decrease for the first quarter 2012 was partially offset by increases in revenues associated with the elimination of a tax-related adjustment under Alabama Power’s rate structure, an increase related to retail revenue rate effects at Georgia Power, an increase related to interim retail rate revenues at Gulf Power, and an increase in industrial KWH sales.

Retail Revenues

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(304)	(9.0)

In the first quarter 2012, retail revenues were $3.1 billion compared to $3.4 billion for the corresponding period in 2011.

15

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues were as follows:

	First Quarter 2012
	(in millions)	(% change)
Retail — prior year	$3,396
Estimated change in —
Rates and pricing	59	1.7
Sales growth (decline)	17	0.5
Weather	(113)	(3.3)
Fuel and other cost recovery	(267)	(7.9)
Retail – current year	$3,092	(9.0)%

Revenues associated with changes in rates and pricing increased in the first quarter 2012 when compared to the corresponding period in 2011 primarily due to the elimination of a tax-related adjustment under Alabama Power’s rate structure and an increase related to interim retail rate revenues at Gulf Power. Also contributing to the increase were increases in retail revenues at Georgia Power associated with rate pricing effects due to decreased customer usage and the NCCR and demand-side management tariff increases, partially offset by lower contributions from market-driven rates from commercial and industrial customers.

Revenues attributable to changes in sales increased in the first quarter 2012 when compared to the corresponding period in 2011. The increase was due to a 1.9% increase in industrial KWH sales and a 0.6% increase in weather-adjusted residential KWH sales, partially offset by a 1.3% decrease in weather-adjusted commercial KWH sales. Increased demand in the pipelines, transportation, and primary metals sectors was the main contributor to the increase in industrial KWH sales.

Revenues resulting from changes in weather decreased $113 million in the first quarter 2012 as a result of milder weather when compared to the corresponding period in 2011.

Fuel and other cost recovery revenues decreased $267 million in the first quarter 2012 when compared to the corresponding period in 2011. 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.

Wholesale Revenues

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(100)	(22.3)

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’s generation, demand for energy within the Southern Company system’s service territory, and the availability of the Southern Company system’s generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system’s variable cost to produce the energy.

16

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the first quarter 2012, wholesale revenues were $349 million compared to $449 million for the corresponding period in 2011, reflecting a $107 million decrease in energy revenues and a $7 million increase in capacity revenues. The decrease in the first quarter 2012 was primarily related to lower energy sales mainly due to lower customer demand and a reduction in the average price of energy.

Fuel and Purchased Power Expenses

First Quarter 2012 vs. First Quarter 2011
	(change in millions)	(% change)
Fuel	$                (412)	(27.9)
Purchased power	41	41.0
Total fuel and purchased power expenses	$                (371)

In the first quarter 2012, total fuel and purchased power expenses were $1.2 billion compared to $1.6 billion for the corresponding period in 2011. The decrease in the first quarter 2012 when compared to the corresponding period in 2011 was primarily the result of a $395 million decrease in the average cost of fuel and purchased power, partially offset by a $24 million net increase related to total KWHs generated and purchased.

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 — “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 generation and purchased power were as follows:

	First Quarter 2012	First Quarter 2011
Total generation (billions of KWHs)	39	46
Total purchased power (billions of KWHs)	4	1
Sources of generation (percent) —
Coal	35	53
Nuclear	19	16
Gas	42	28
Hydro	4	3
Cost of fuel, generated (cents per net KWH) —
Coal	4.09	3.96
Nuclear	0.80	0.67
Gas	2.77	3.93
Average cost of fuel, generated (cents per net KWH)	2.85	3.39
Average cost of purchased power (cents per net KWH)*	3.88	9.25

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

In the first quarter 2012, fuel expense was $1.1 billion compared to $1.5 billion for the corresponding period in 2011. The decrease in the first quarter 2012 when compared to the corresponding period in 2011 was primarily due to a 29.5% decrease in the average cost of gas per KWH generated, a higher percentage of generation from lower cost natural gas-fired resources, and lower customer demand mainly due to milder weather.

In the first quarter 2012, purchased power expense was $141 million compared to $100 million for the corresponding period in 2011. The increase in the first quarter 2012 when compared to the corresponding period in 2011 was primarily due to a 298.2% increase in the volume of KWHs purchased as the market cost of available energy was lower than the marginal cost of generation available, partially offset by a 58.1% decrease in the average cost per KWH purchased.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Other Operations and Maintenance Expenses

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$23	2.4

In the first quarter 2012, other operations and maintenance expenses were $967 million compared to $944 million for the corresponding period in 2011. The increase in the first quarter 2012 when compared to the corresponding period in 2011 was primarily the result of a $43 million increase in administrative and general costs primarily due to increases in pension costs, property insurance, and other employee benefits. Also contributing to the increase was a $6 million increase in customer service and sales related costs. The increase in the first quarter 2012 was partially offset by a $13 million decrease primarily related to scheduled outage and maintenance costs and commodity and labor costs, as well as an $11 million decrease at Mississippi Power related to the expiration of an operating lease for Plant Daniel Units 3 and 4. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Purchase of the Plant Daniel Combined Cycle Generating Units” of Southern Company in Item 7 of the Form 10-K for additional information.

Depreciation and Amortization

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$23	5.5

In the first quarter 2012, depreciation and amortization was $441 million compared to $418 million for the corresponding period in 2011. The increase for the first quarter 2012 when compared to the corresponding period in 2011 was primarily the result of an increase in depreciation due to additional plant in service related to new generation at Georgia Power’s Plant McDonough Unit 4 that went into service in December 2011, as well as transmission, distribution, and environmental projects.

Allowance for Equity Funds Used During Construction

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(4)	(11.4)

In the first quarter 2012, AFUDC equity was $31 million compared to $35 million for the corresponding period in 2011. The decrease for the first quarter 2012 when compared to the corresponding period in 2011 was primarily due to the completion of Georgia Power’s Plant McDonough Unit 4 in December 2011, partially offset by CWIP related to Mississippi Power’s Kemper IGCC.

Interest Expense, Net of Amounts Capitalized

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(11)	(5.0)

In the first quarter 2012, interest expense, net of amounts capitalized was $211 million compared to $222 million for the corresponding period in 2011. The decrease for the first quarter 2012 when compared to the corresponding period in 2011 was primarily due to lower interest rates on outstanding debt and a refinancing of long-term debt during 2011 at

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Southern Power. Also contributing to the decrease was an increase in capitalized interest associated with construction projects at Southern Power.

Income Taxes

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(31)	(13.4)

In the first quarter 2012, income taxes were $200 million compared to $231 million for the corresponding period in 2011. The decrease for the first quarter 2012 when compared to the corresponding period in 2011 was primarily the result of lower pre-tax earnings.

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. Another major factor is the profitability of the competitive wholesale supply business. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in 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 federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — New Source Review Actions” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — New Source Review Actions” in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to a unit co-owned by Mississippi Power). At the same time, the EPA asked the U.S. Court of Appeals for

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the Eleventh Circuit to stay its appeal of the judgment in favor of Alabama Power. Alabama Power filed oppositions to the EPA’s motion and its request for a stay. On March 29, 2012, the U.S. Court of Appeals for the Eleventh Circuit denied the EPA’s request to stay its appeal. The U.S. District Court for the Northern District of Alabama has not ruled on the EPA’s motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.

Climate Change Litigation

Hurricane Katrina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Climate Change Litigation — Hurricane Katrina Case” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — Climate Change Litigation — Hurricane Katrina Case” in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed on May 27, 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

General

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 information regarding the Southern Company system’s estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as the Southern Company system’s preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA’s final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA’s proposed water and coal combustion byproducts rules. The Southern Company system is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA’s proposed water and coal combustion byproducts rules.

The Southern Company system’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated, including any proposed environmental regulations; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the fuel mix of the electric utilities. These costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, the addition of new generating resources, and changing fuel sources for certain existing units. The Southern Company system’s preliminary analysis further indicates that the short timeframe for compliance with the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.

As part of Southern Electric Generating Company’s (SEGCO) environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Alabama Power and Georgia Power. The capacity of SEGCO’s units is sold to Alabama Power and Georgia Power through a PPA. The impact of SEGCO’s ultimate compliance strategy on such PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Southern Company’s financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

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Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Southern Company in Item 7 of the Form 10-K for additional information on the eight-hour ozone air quality standards and the MATS rule.

On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. The only area within the traditional operating companies’ service territory designated as a nonattainment area was a 15-county area within metropolitan Atlanta.

Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court of Appeals for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts” of Southern Company in Item 7 of the Form 10-K for additional information. On April 5, 2012, 10 environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts as soon as possible. Other parties are expected to file similar challenges. The ultimate outcome of this matter cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Global Climate Issues” of Southern Company in Item 7 of the Form 10-K for additional information. On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.

PSC Matters

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. The traditional operating companies have experienced lower pricing for natural gas resulting in an increase in natural gas generation and a decrease in coal generation, which is currently more costly. The lower cost of natural gas has resulted in total over recovered fuel costs at Georgia Power, Gulf Power, and Mississippi Power included in Southern Company’s Condensed Balance Sheets herein of approximately $102 million at March 31, 2012. At March 31, 2012, Alabama Power had under recovered fuel costs included in Southern Company’s Condensed Balance Sheet herein of approximately $6 million. At December 31, 2011, total under recovered fuel costs at Alabama Power and Georgia Power included in Southern Company’s Condensed Balance Sheet herein were approximately $169 million, and Gulf Power and Mississippi Power had a total over recovered fuel balance included in Southern Company’s Condensed Balance Sheet herein of approximately $52 million. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company’s revenues or net income, but will affect annual cash flow. The traditional operating companies continuously monitor their under or over recovered fuel cost balances.

On March 30, 2012, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 19%, which is expected to reduce annual billings by $567 million. The decrease in fuel costs is driven primarily by lower natural gas prices as a result of increased natural gas supplies. The Georgia PSC is scheduled to vote on this matter on June 21, 2012. As proposed, the rate decrease would become effective July 1, 2012; however, Georgia Power is currently working

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

with the Georgia PSC to potentially implement the proposed decrease effective June 1, 2012. The ultimate outcome of this matter cannot be determined at this time.

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.

Georgia Power

2011 Integrated Resource Plan Update

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

On March 20, 2012, the Georgia PSC approved Georgia Power’s request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Power’s 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.

Income Tax Matters

Bonus Depreciation

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. Due to the significant amount of estimated bonus depreciation for 2012, a portion of Southern Company’s tax credit utilization will be deferred. Consequently, Southern Company’s positive cash flow benefit is estimated to be between $530 million and $720 million in 2012.

Construction Program

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new generating facilities, including natural gas, biomass, and solar units at Southern Power, natural gas units and Plant Vogtle Units 3 and 4 at Georgia Power, and the Kemper IGCC at Mississippi Power, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the financial statements of Southern Company under “Construction

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and “Integrated Coal Gasification Combined Cycle” herein for additional information.

Investments in Leveraged Leases

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

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 assets. Southern Company is currently engaged in discussions with the lessee and the holders of the project’s nonrecourse debt to restructure the debt payments and the related rental payments to allow additional capital investment in the project to be made to improve the operation of the generation assets and the financial viability of the lease transaction. Southern Company continues to monitor the performance of the underlying assets and to evaluate the ability of the lessee to continue to make the required lease payments. If the attempts at restructuring the project are unsuccessful and the project is ultimately abandoned, the potential impairment loss that would be incurred is approximately $90 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally 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 a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Other Matters” of Southern Company in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, including the one in use at Plant Hatch, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. The staff of the NRC expects to issue additional implementation guidance by August 2012. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the

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NRC and cannot be determined at this time. 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.

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

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Overview” of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company’s financial condition remained stable at March 31, 2012. 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,” “Financing Activities,” and “Capital Requirements and Contractual Obligations” herein for additional information.

Net cash provided from operating activities totaled $568 million for the first quarter 2012, a decrease of $430 million from the corresponding period in 2011. Significant changes in operating cash flow for the first quarter 2012 compared to the corresponding period in 2011 include an increase in fossil fuel stock levels due to reduced consumption as a result of milder weather in the first quarter 2012 and a decrease in accrued taxes primarily due to the timing of tax payments. Net cash used for investing activities totaled $1.4 billion for the first quarter 2012, an increase of $543 million from the corresponding period in 2011. This increase was primarily due to property additions to utility plant. Net cash provided from financing activities totaled $588 million for the first quarter 2012 compared to $151 million net cash used for financing activities in the corresponding period in 2011. This change was primarily due to an increase in short-term debt outstanding, an increase in long-term debt issuances, and the receipt of an interest-bearing refundable deposit related to a pending asset sale at Mississippi Power.

Significant balance sheet changes for the first quarter 2012 include an increase of $845 million in total property, plant, and equipment for the construction of generation, transmission, and distribution facilities. Other significant changes include an increase in long-term debt of $404 million due to senior note issuances.

The market price of Southern Company’s common stock at the end of the first quarter 2012 was $44.93 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $20.37 per share, representing a market-to-book ratio of 221%, compared to $46.29, $20.32, and 228%, respectively, at the end of 2011. The dividend for the first quarter 2012 was $0.4725 per share compared to $0.4550 per share in the first quarter 2011. In April 2012, the quarterly dividend payable in June 2012 was increased to $0.49 per share.

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THE SOUTHERN 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 Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for the construction programs of the Southern Company system 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 $1.9 billion will be required through March 31, 2013 to fund maturities and announced redemptions of long-term debt.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet 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 2012, 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.

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 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. Mississippi Power also received DOE grant funds of $245 million that were used for the construction of the Kemper IGCC. An additional $25 million is expected to be received for the initial operation of the Kemper IGCC.

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Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business of the Southern Company system. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs which are backed by bank credit facilities.

At March 31, 2012, Southern Company and its subsidiaries had approximately $1.0 billion of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2012 were as follows:

	Expires																Executable Term Loans						Due Within One Year(a)
Company	2012			2013			2014 and Beyond			Total			Unused			One Year			Two Year			Term Out			No Term Out
	(in millions)									(in millions)						(in millions)						(in millions)
Southern Company		$	—		$	—		$	1,000		$	1,000		$	1,000		$	—		$	—		$	—		$	—
Alabama Power			121			35			1,150			1,306			1,306			51			—			51			71
Georgia Power			—			—			1,750			1,750			1,745			—			—			—			—
Gulf Power			75			35			165			275			275			75			—			75			35
Mississippi Power			106			25			165			296			296			25			41			66			65
Southern Power			—			—			500			500			500			—			—			—			—
Other			25			25			—			50			50			25			—			25			—
Total		$	327		$	120		$	4,730		$	5,177		$	5,172		$	176		$	41		$	217		$	171

(a) Reflects facilities expiring on or before March 31, 2013.

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.

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

A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2012 was approximately $1.8 billion.

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.

26

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings, excluding $2 million in notes payable related to other energy service contracts, were as follows:

	Short-term Debt at  the End of the Period		Short-term Debt During the Period (a)
	Amount   Outstanding	Weighted     Average Interest Rate	Average     Outstanding	Weighted   Average Interest Rate	Maximum Amount     Outstanding
	(in millions)		(in millions)		(in millions)
March 31, 2012:
Commercial paper	$   728	0.3%	$583	0.3%	$938
Short-term bank debt	300	1.1%	290	1.2%	300
Total	$1,028	0.6%	$873	0.6%

(a) Average and maximum amounts are based upon daily balances during the period.

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

Credit Rating Risk

Southern Company 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. The maximum potential collateral requirements under these contracts at March 31, 2012 were as follows:

Credit Ratings	Maximum Potential   Collateral Requirements
	(in millions)
At BBB and Baa2	$       9
At BBB- and/or Baa3	624
Below BBB- and/or Baa3	2,833

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.

27

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts or heat-rate contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. Southern Company had no material change in market risk exposure for the first quarter 2012 when compared with the December 31, 2011 reporting period.

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three months ended March 31, 2012 were as follows:

	First Quarter   2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$(231)
Contracts realized or settled	50
Current period changes(a)	(84)
Contracts outstanding at the end of the period, assets (liabilities), net	$(265)

(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 months ended March 31, 2012 was a decrease of $34 million, of which $18 million related to natural gas swaps, $15 million related to natural gas options, and $1 million related to other energy-related derivatives. The change is attributable to both the volume of mmBtu and the price of natural gas. At March 31, 2012, Southern Company had a net hedge volume of 221 million mmBtu, which consisted of 123 million mmBtu of swaps and 98 million mmBtu of options. The weighted average swap contract cost was approximately $1.71 per mmBtu above market prices. At December 31, 2011, Southern Company had a net hedge volume of 189 million mmBtu, which consisted of 123 million mmBtu of swaps and 66 million mmBtu of options. The weighted average swap contract cost was approximately $1.51 per mmBtu above market prices. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the natural gas hedge gains and losses are recovered through the traditional operating companies’ fuel cost recovery clauses.

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

Asset (Liability) Derivatives	March 31, 2012	December 31, 2011
	(in millions)
Regulatory hedges	$(249)	$(221)
Cash flow hedges	(1)	(1)
Not designated	(15)	(9)
Total fair value	$(265)	$(231)

Energy-related derivative contracts which are designated as regulatory hedges relate to the traditional operating companies’ fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to

28

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 for the three months ended March 31, 2012 and 2011 were not material.

Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2012 were as follows:

	March 31, 2012 Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3	Years 4&5
	(in millions)
Level 1	$   —	$   —	$ —	$—
Level 2	(265)	(197)	(66)	(2)
Level 3	—	—	—	—
Fair value of contracts outstanding at end of period	$(265)	$(197)	$(66)	$ (2)

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 all relevant 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 quarter 2012, Southern Company issued approximately 3.6 million shares of common stock for $115 million through 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.

29

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 the quarter ended March 31, 2012:

Company*	Senior Note Issuances	Senior Note Redemptions and Maturities	Other Long- Term Debt Redemptions   and Maturities
	(in millions)
Southern Company	$    —	$500	$  —
Alabama Power	250	—	1
Georgia Power	750	—	250
Mississippi Power	400	—	75
Total	$1,400	$500	$326

* Gulf Power and Southern Power did not issue or redeem any long-term debt during the first quarter 2012.

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.

On January 17, 2012, Southern Company’s $500 million aggregate principal amount of Series 2007A 5.30% Senior Notes matured.

On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of a 17.5% undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power’s AFUDC rate and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power’s senior unsecured credit rating falls below a BBB+ and/or Baa1.

Subsequent to March 31, 2012, Alabama Power redeemed $250 million aggregate principal amount of its Series 2007B 5.875% Senior Notes due April 1, 2047.

Subsequent to March 31, 2012, Mississippi Power announced the redemption of $90 million aggregate principal amount of its Series E 5-5/8% Senior Notes due May 1, 2033 that will occur on May 15, 2012.

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.

30

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 and Alabama 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 first quarter 2012 that have materially affected or are reasonably likely to materially affect Southern Company’s or Alabama Power’s internal control over financial reporting, other than as described in the next sentence. During the first quarter 2012, Alabama Power implemented new accounts payable, supply chain, and work management systems. The implementation of these systems provides additional operational and internal control benefits including system security and automation of previously manual controls. These process improvement initiatives were not in response to an identified internal control deficiency.

There have been no changes in 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 first quarter 2012 that have materially affected or are reasonably likely to materially affect Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

31

ALABAMA POWER COMPANY

32

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in millions)
Operating Revenues:
Retail revenues	$	1,092		$	1,126
Wholesale revenues, non-affiliates		61			68
Wholesale revenues, affiliates		14			75
Other revenues		49			51
Total operating revenues		1,216			1,320
Operating Expenses:
Fuel		306			395
Purchased power, non-affiliates		15			11
Purchased power, affiliates		40			46
Other operations and maintenance		321			297
Depreciation and amortization		157			157
Taxes other than income taxes		86			85
Total operating expenses		925			991
Operating Income		291			329
Other Income and (Expense):
Allowance for equity funds used during construction		5			5
Interest income		4			4
Interest expense, net of amounts capitalized		(73	)		(74	)
Other income (expense), net		(7	)		(6	)
Total other income and (expense)		(71	)		(71	)
Earnings Before Income Taxes		220			258
Income taxes		84			96
Net Income		136			162
Dividends on Preferred and Preference Stock		10			10
Net Income After Dividends on Preferred and Preference Stock	$	126		$	152

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012		2011
	(in millions)
Net Income After Dividends on Preferred and Preference Stock	$	126	$	152
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $3 and $2, respectively		4		2
Total other comprehensive income (loss)		4		2
Comprehensive Income	$	130	$	154

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

33

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in millions)
Operating Activities:
Net income	$	136		$	162
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		189			185
Deferred income taxes		31			59
Allowance for equity funds used during construction		(5	)		(5	)
Pension, postretirement, and other employee benefits		(1	)		(11	)
Stock based compensation expense		4			3
Other, net		(10	)		1
Changes in certain current assets and liabilities —
-Receivables		89			51
-Fossil fuel stock		(81	)		3
-Materials and supplies		2			10
-Other current assets		(51	)		(69	)
-Accounts payable		(149	)		(153	)
-Accrued taxes		43			160
-Accrued compensation		(63	)		(67	)
-Other current liabilities		6			(2	)
Net cash provided from operating activities		140			327
Investing Activities:
Property additions		(244	)		(213	)
Distribution of restricted cash from pollution control revenue bonds		—			11
Nuclear decommissioning trust fund purchases		(49	)		(97	)
Nuclear decommissioning trust fund sales		49			97
Cost of removal, net of salvage		(6	)		(8	)
Change in construction payables		14			(2	)
Other investing activities		1			(12	)
Net cash used for investing activities		(235	)		(224	)
Financing Activities:
Proceeds —
Capital contributions from parent company		5			5
Senior notes issuances		250			250
Redemptions —
Pollution control revenue bonds		(1	)		—
Senior notes		—			(200	)
Payment of preferred and preference stock dividends		(10	)		(10	)
Payment of common stock dividends		(135	)		(138	)
Other financing activities		(3	)		(5	)
Net cash provided from (used for) financing activities		106			(98	)
Net Change in Cash and Cash Equivalents		11			5
Cash and Cash Equivalents at Beginning of Period		344			154
Cash and Cash Equivalents at End of Period	$	355		$	159
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $2 and $2 capitalized for 2012 and 2011, respectively)	$	66		$	72
Income taxes (net of refunds)		22			(110	)
Noncash transactions — accrued property additions at end of period		32			26

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

34

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2012			At December 31, 2011
	(in millions)
Current Assets:
Cash and cash equivalents	$	355		$	344
Restricted cash and cash equivalents		—			1
Receivables —
Customer accounts receivable		300			332
Unbilled revenues		116			126
Other accounts and notes receivable		35			35
Affiliated companies		50			79
Accumulated provision for uncollectible accounts		(10	)		(10	)
Fossil fuel stock, at average cost		425			344
Materials and supplies, at average cost		372			375
Vacation pay		59			59
Prepaid expenses		146			74
Other regulatory assets, current		48			44
Other current assets		12			11
Total current assets		1,908			1,814
Property, Plant, and Equipment:
In service		20,999			20,809
Less accumulated provision for depreciation		7,446			7,344
Plant in service, net of depreciation		13,553			13,465
Nuclear fuel, at amortized cost		363			330
Construction work in progress		339			374
Total property, plant, and equipment		14,255			14,169
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		62			62
Nuclear decommissioning trusts, at fair value		588			540
Miscellaneous property and investments		74			73
Total other property and investments		724			675
Deferred Charges and Other Assets:
Deferred charges related to income taxes		530			532
Prepaid pension costs		67			59
Deferred under recovered regulatory clause revenues		24			48
Other regulatory assets, deferred		995			994
Other deferred charges and assets		161			186
Total deferred charges and other assets		1,777			1,819
Total Assets	$	18,664		$	18,477

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

35

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At March 31, 2012			At December 31, 2011
	(in millions)
Current Liabilities:
Securities due within one year	$	750		$	500
Accounts payable —
Affiliated		163			203
Other		225			322
Customer deposits		86			85
Accrued taxes —
Accrued income taxes		44			32
Other accrued taxes		54			34
Accrued interest		67			63
Accrued vacation pay		48			48
Accrued compensation		33			95
Liabilities from risk management activities		51			54
Other regulatory liabilities, current		19			18
Other current liabilities		40			38
Total current liabilities		1,580			1,492
Long-term Debt		5,630			5,632
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,287			3,257
Deferred credits related to income taxes		82			83
Accumulated deferred investment tax credits		147			149
Employee benefit obligations		343			343
Asset retirement obligations		561			553
Other cost of removal obligations		719			703
Other regulatory liabilities, deferred		193			156
Other deferred credits and liabilities		87			82
Total deferred credits and other liabilities		5,419			5,326
Total Liabilities		12,629			12,450
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		2,194			2,182
Retained earnings		1,948			1,956
Accumulated other comprehensive loss		(14	)		(18	)
Total common stockholder’s equity		5,350			5,342
Total Liabilities and Stockholder’s Equity	$	18,664		$	18,477

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

36

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2012 vs. FIRST QUARTER 2011

OVERVIEW

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

Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS — OVERVIEW — “Key Performance Indicators” of Alabama Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(26)	(17.1)

Alabama Power’s net income after dividends on preferred and preference stock for the first quarter 2012 was $126 million compared to $152 million for the corresponding period in 2011. The decrease in net income was related to a decrease in weather-related revenues due to milder weather in the first quarter 2012 and an increase in operations and maintenance expenses. The reductions in net income were partially offset by increases in revenues associated with the elimination of a tax-related adjustment under Alabama Power’s rate structure and an increase in energy sales due to an increase in customer demand. 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” of Alabama Power in Item 7 of the Form 10-K for information regarding the rate structure of Alabama Power.

Retail Revenues

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(34)	(3.0)

In the first quarter 2012, retail revenues were $1.09 billion compared to $1.13 billion for the corresponding period in 2011.

37

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues were as follows:

	First Quarter 2012
	(in millions)	(% change)
Retail – prior year	$1,126
Estimated change in –
Rates and pricing	25	2.2
Sales growth (decline)	19	1.8
Weather	(50)	(4.5)
Fuel and other cost recovery	(28)	(2.5)
Retail – current year	$1,092	(3.0)%

Revenues associated with changes in rates and pricing increased in the first quarter 2012 when compared to the corresponding period in 2011 primarily due to the elimination of a tax-related adjustment under Alabama Power’s rate structure that was effective with October 2011 billings, slightly offset by decreased revenues associated with Rate Certificated New Plant Environmental.

Revenues attributable to changes in sales increased in the first quarter 2012 when compared to the corresponding period in 2011. Industrial KWH energy sales increased 3.2% due to an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and forest products sectors, partially offset by a decrease in the stone, clay, and glass sector. Weather-adjusted residential KWH energy sales increased 1.5% due to an increase in customer demand. The decrease in weather-adjusted commercial KWH energy sales was not material.

Revenues resulting from changes in weather decreased in the first quarter 2012 when compared to the corresponding period in 2011. Alabama Power’s service territory experienced milder weather conditions in first quarter 2012 resulting in decreases of 9.0% and 1.6% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues decreased in the first quarter 2012 when compared to the corresponding period in 2011 primarily due to lower fuel costs associated with decreased KWH generation and lower average cost per KWH generated due to lower natural gas prices. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income.

See BUSINESS – “Rate Matters – Rate Structure and Cost Recovery Plans” of Alabama Power in Item 1, 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.

38

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(7)	(10.3)

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

In the first quarter 2012, wholesale revenues from non-affiliates were $61 million compared to $68 million for the corresponding period in 2011, reflecting an $8 million decrease in revenue from energy sales and a $1 million increase in capacity revenue. The decrease was primarily due to an 8.1% decrease in KWH sales and a 1.3% decrease in the price of energy.

Wholesale Revenues – Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(61)	(81.3)

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

In the first quarter 2012, wholesale revenues from affiliates were $14 million compared to $75 million for the corresponding period in 2011. The decrease was due to a 24.3% decrease in the price of energy and a 75.1% decrease in KWH sales.

Fuel and Purchased Power Expenses

First Quarter 2012 vs. First Quarter 2011
	(change in millions)	(% change)
Fuel	$(89)	(22.5)
Purchased power – non-affiliates	4	36.4
Purchased power – affiliates	(6)	(13.0)
Total fuel and purchased power expenses	$(91)

In the first quarter 2012, total fuel and purchased power expenses were $361 million compared to $452 million for the corresponding period in 2011. The decrease was primarily due to an $84 million decrease related to a reduction in total KWHs generated as a result of milder weather in the first quarter 2012, a $4 million decrease in the cost of fuel, and an $8 million decrease in the average cost of purchased power.

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

39

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2012	First Quarter 2011
Total generation (billions of KWHs)	14	16
Total purchased power (billions of KWHs)	1	1
Sources of generation (percent) –
Coal	42	55
Nuclear	27	23
Gas	20	15
Hydro	11	7
Cost of fuel, generated (cents per net KWH) –
Coal	3.43	2.99
Nuclear	0.74	0.67
Gas	3.00	4.16
Average cost of fuel, generated (cents per net KWH)*	2.51	2.62
Average cost of purchased power (cents per net KWH)**	4.60	5.26

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

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

Fuel

In the first quarter 2012, fuel expense was $306 million compared to $395 million for the corresponding period in 2011. The $89 million decrease was due to a 35.7% decrease in KWHs generated by coal and a 27.9% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements, slightly offset by a 10% increase in KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the first quarter 2012, purchased power expense from non-affiliates was $15 million compared to $11 million for the corresponding period in 2011. The increase was related to a 296.5% increase in the amount of energy purchased, partially offset by a 68.0% decrease in the average cost per KWH.

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

Purchased Power – Affiliates

In the first quarter 2012, purchased power expense from affiliates was $40 million compared to $46 million for the corresponding period in 2011. The decrease was related to a 13.9% decrease in the amount of energy purchased, slightly offset by a 2.1% increase in the average cost per KWH.

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

40

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$24	8.1

In the first quarter 2012, other operations and maintenance expenses were $321 million compared to $297 million for the corresponding period in 2011. Administrative and general expenses increased $18 million due to benefit-related expenses, affiliated service company expenses, labor expenses, and property insurance expenses. Nuclear production expenses increased $6 million primarily due to the amortization of nuclear outage expenses. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Nuclear Outage Accounting Order” of Alabama Power in Item 7 of the Form 10-K for additional information.

Income Taxes

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(12)	(12.5)

For the first quarter 2012, income taxes were $84 million compared to $96 million for the corresponding period in 2011. The decrease was primarily due to lower pre-tax earnings as a result of lower revenues due to milder weather.

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

Environmental Matters

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

41

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power. At the same time, the EPA asked the U.S. Court of Appeals for the Eleventh Circuit to stay its appeal of the judgment in favor of Alabama Power. Alabama Power filed oppositions to the EPA’s motion and its request for a stay. On March 29, 2012, the U.S. Court of Appeals for the Eleventh Circuit denied the EPA’s request to stay its appeal. The U.S. District Court for the Northern District of Alabama has not ruled on the EPA’s motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.

Climate Change Litigation

Hurricane Katrina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Climate Change Litigation – Hurricane Katrina Case” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Climate Change Litigation – Hurricane Katrina Case” in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed on May 27, 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

General

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 information regarding Alabama Power’s estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Alabama Power’s preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA’s final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA’s proposed water and coal combustion byproducts rules.

Alabama Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA’s proposed water and coal combustion byproducts rules. As part of its compliance strategy, Alabama Power has entered into agreements for the construction of two baghouses to control the emissions of mercury and particulates from generating units with an aggregate capacity of 1,901 MWs. The cost of the two baghouses is included in the estimated costs associated with compliance with the MATS rule detailed in the Form 10-K, as referenced above.

Alabama Power’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated, including any proposed environmental regulations; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Alabama Power’s fuel mix. These costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, the addition of new

42

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

generating resources, and changing fuel sources for certain existing units. Alabama Power’s preliminary analysis further indicates that the short timeframe for compliance with the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.

As part of Southern Electric Generating Company’s (SEGCO) environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Alabama Power and Georgia Power. The capacity of SEGCO’s units is sold to Alabama Power and Georgia Power through a PPA. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information. The impact of SEGCO’s ultimate compliance strategy on such PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Alabama Power’s financial statements.

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 on the eight-hour ozone air quality standards and the MATS rule.

On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Alabama Power’s service territory were designated as nonattainment areas.

Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Alabama Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court of Appeals for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Alabama Power in Item 7 of the Form 10-K for additional information. On April 5, 2012, 10 environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts as soon as possible. Other parties are expected to file similar challenges. The ultimate outcome of this matter cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Alabama Power in Item 7 of the Form 10-K for additional information. On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.

PSC Matters

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 March 31, 2012 totaled $6 million as compared to $31

43

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

million at December 31, 2011. These under recovered fuel costs at March 31, 2012 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

Bonus Depreciation

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. Consequently, Alabama Power’s positive cash flow benefit is estimated to be between $85 million and $110 million in 2012.

Other Matters

Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury 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 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.

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

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Other Matters” of Alabama Power in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. The staff of the NRC expects to issue additional implementation guidance by August 2012. The final form and the resulting impact of any changes to safety requirements for 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. The ultimate outcome of these events cannot be determined at this time.

44

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Overview” of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power’s financial condition remained stable at March 31, 2012. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital,” “Financing Activities,” and “Capital Requirements and Contractual Obligations” herein for additional information.

Net cash provided from operating activities totaled $140 million for the first three months of 2012, a decrease of $187 million as compared to the first three months of 2011. The decrease in cash provided from operating activities was primarily due to the timing of income tax payments and refunds, an increase in fossil fuel stock, and a decrease in deferred income taxes. The decrease was partially offset by an increase in receivables. Net cash used for investing activities totaled $235 million for the first three months of 2012 primarily due to gross property additions related to nuclear fuel and transmission, distribution, other production, and steam generation equipment. Net cash provided by financing activities totaled $106 million for the first three months of 2012. This was primarily due to the issuances of senior notes, partially offset by the payment of common stock dividends. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2012 include increases of $250 million of securities due within one year, $86 million in property, plant, and equipment associated with routine property additions and nuclear fuel, and $81 million in fossil fuel stock, at average cost, and a decrease of $97 million in other accounts payable.

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. Approximately $750 million will be required through March 31, 2013 to fund maturities and announced redemptions of long-term debt.

45

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet 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, short-term debt, security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Alabama Power in Item 7 of the Form 10-K for additional information.

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

At March 31, 2012, Alabama Power had approximately $355 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2012 were as follows:

Expires					Executable Term Loans		Due Within One Year(a)
2012	2013	2014 and     Beyond	Total	Unused	One     Year	Two   Year	Term     Out	No Term Out
(in millions)			(in millions)		(in millions)		(in millions)
$121	$35	$1,150	$1,306	$1,306	$51	$—	$51	$71

(a) Reflects facilities expiring on or before March 31, 2013.

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

Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Alabama Power. Alabama Power is currently in compliance with all such covenants. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Alabama Power’s commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2012 was approximately $793 million.

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

Alabama Power had no commercial paper or short-term debt outstanding during the three-months ended March 31, 2012.

46

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 March 31, 2012, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $310 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Alabama Power’s market risk exposure relative to interest rate changes for the first quarter 2012 has not changed materially compared to the December 31, 2011 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. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts or heat-rate contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power had no material change in market risk exposure for the first quarter 2012 when compared with the December 31, 2011 reporting period.

47

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three months ended March 31, 2012 were as follows:

	First Quarter 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net		$(48)
Contracts realized or settled		13
Current period changes(a)		(18)
Contracts outstanding at the end of the period, assets (liabilities), net		$(53)

(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 months ended March 31, 2012 was a decrease of $5 million, of which $3 million related to natural gas swaps and $2 million related to natural gas options. The change is attributable to both the volume of mmBtu and the price of natural gas. At March 31, 2012, Alabama Power had a net hedge volume of 37 million mmBtu, which consisted of 27 million mmBtu of swaps and 10 million mmBtu of options. The weighted average swap contract cost was approximately $1.72 per mmBtu above market prices. At December 31, 2011, Alabama Power had a net hedge volume of 39 million mmBtu, which consisted of 30 million mmBtu of swaps and 9 million mmBtu of options. The weighted average swap contract cost was approximately $1.45 per mmBtu above market prices. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. All of the natural gas hedge gains and losses are recovered through Alabama Power’s fuel cost recovery clause.

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

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2012 and 2011 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 March 31, 2012 were as follows:

	March 31, 2012 Fair Value Measurements
	Total Fair Value		Maturity
			Year 1		Years 2&3		Years 4&5
	(in millions)
Level 1		$ —		$ —		$—		$—
Level 2		(53)		(42)		(11)		—
Level 3		—		—		—		—
Fair value of contracts outstanding at end of period		$(53)		$(42)		$(11)		$—

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 all relevant regulations are finalized.

48

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 January 2012, Alabama Power issued $250 million aggregate principal amount of Series 2012A 4.10% Senior Notes due January 15, 2042. The proceeds were used for general corporate purposes, including Alabama Power’s continuous construction program. Alabama Power settled $100 million of interest rate swaps related to this issuance at a loss of $1 million. The loss is being amortized to interest expense, in earnings, over 10 years.

In March 2012, Alabama Power redeemed approximately $1 million aggregate principal amount of The Industrial Development Board of the Town of West Jefferson Solid Waste Disposal Revenue Bonds (Alabama Power Company Miller Plant Project), Series 2008.

Subsequent to March 31, 2012, Alabama Power redeemed $250 million aggregate principal amount of its Series 2007B 5.875% Senior Notes due April 1, 2047.

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.

49

GEORGIA POWER COMPANY

50

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012		2011
	(in millions)
Operating Revenues:
Retail revenues	$	1,594	$	1,815
Wholesale revenues, non-affiliates		66		83
Wholesale revenues, affiliates		3		11
Other revenues		82		80
Total operating revenues		1,745		1,989
Operating Expenses:
Fuel		440		677
Purchased power, non-affiliates		93		74
Purchased power, affiliates		159		163
Other operations and maintenance		434		422
Depreciation and amortization		188		173
Taxes other than income taxes		87		87
Total operating expenses		1,401		1,596
Operating Income		344		393
Other Income and (Expense):
Allowance for equity funds used during construction		13		25
Interest expense, net of amounts capitalized		(91)		(96)
Other income (expense), net		(3)		(1)
Total other income and (expense)		(81)		(72)
Earnings Before Income Taxes		263		321
Income taxes		92		111
Net Income		171		210
Dividends on Preferred and Preference Stock		4		4
Net Income After Dividends on Preferred and Preference Stock	$	167	$	206

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012		2011
	(in millions)
Net Income After Dividends on Preferred and Preference Stock	$	167	$	206
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $- and $-, respectively		1		1
Comprehensive Income	$	168	$	207

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended  March 31,
	2012			2011
	(in millions)
Operating Activities:
Net income	$	171		$	210
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		229			210
Deferred income taxes		38			56
Allowance for equity funds used during construction		(13	)		(25	)
Other, net		33			(14	)
Changes in certain current assets and liabilities —
-Receivables		258			122
-Fossil fuel stock		(122	)		(30	)
-Prepaid income taxes		10			80
-Other current assets		(4	)		(14	)
-Accounts payable		(62	)		(50	)
-Accrued taxes		(206	)		(194	)
-Accrued compensation		(80	)		(65	)
-Other current liabilities		60			64
Net cash provided from operating activities		312			350
Investing Activities:
Property additions		(476	)		(513	)
Nuclear decommissioning trust fund purchases		(287	)		(830	)
Nuclear decommissioning trust fund sales		285			827
Cost of removal, net of salvage		(15	)		1
Change in construction payables, net of joint owner portion		(203	)		93
Other investing activities		15			(6	)
Net cash used for investing activities		(681	)		(428	)
Financing Activities:
Increase (decrease) in notes payable, net		99			(62	)
Proceeds —
Capital contributions from parent company		9			171
Pollution control revenue bonds issuances		—			137
Senior notes issuances		750			300
Other long-term debt issuances		—			250
Redemptions —
Pollution control revenue bonds		—			(84	)
Senior notes		—			(101	)
Other long-term debt		(250	)		(300	)
Payment of preferred and preference stock dividends		(4	)		(4	)
Payment of common stock dividends		(227	)		(224	)
Other financing activities		(8	)		(2	)
Net cash provided from financing activities		369			81
Net Change in Cash and Cash Equivalents		—			3
Cash and Cash Equivalents at Beginning of Period		13			8
Cash and Cash Equivalents at End of Period	$	13		$	11
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $6 and $9 capitalized for 2012 and 2011, respectively)	$	58		$	65
Income taxes (net of refunds)		28			(77	)
Noncash transactions — accrued property additions at end of period		178			350

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

52

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2012			At December 31, 2011
	(in millions)
Current Assets:
Cash and cash equivalents	$	13		$	13
Receivables —
Customer accounts receivable		490			571
Unbilled revenues		166			172
Under recovered regulatory clause revenues		—			137
Joint owner accounts receivable		59			87
Other accounts and notes receivable		45			61
Affiliated companies		35			26
Accumulated provision for uncollectible accounts		(12	)		(13	)
Fossil fuel stock, at average cost		844			723
Materials and supplies, at average cost		400			406
Vacation pay		84			82
Prepaid income taxes		122			71
Other regulatory assets, current		118			108
Other current assets		84			106
Total current assets		2,448			2,550
Property, Plant, and Equipment:
In service		27,884			27,804
Less accumulated provision for depreciation		10,294			10,296
Plant in service, net of depreciation		17,590			17,508
Other utility plant, net		54			55
Nuclear fuel, at amortized cost		468			443
Construction work in progress		3,456			3,274
Total property, plant, and equipment		21,568			21,280
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		62			63
Nuclear decommissioning trusts, at fair value		692			667
Miscellaneous property and investments		45			44
Total other property and investments		799			774
Deferred Charges and Other Assets:
Deferred charges related to income taxes		757			756
Other regulatory assets, deferred		1,562			1,604
Other deferred charges and assets		203			187
Total deferred charges and other assets		2,522			2,547
Total Assets	$	27,337		$	27,151

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

53

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At March 31, 2012			At December 31, 2011
	(in millions)
Current Liabilities:
Securities due within one year	$	855		$	455
Notes payable		614			515
Accounts payable —
Affiliated		287			337
Other		470			686
Customer deposits		222			213
Accrued taxes —
Accrued income taxes		47			36
Unrecognized tax benefits		9			14
Other accrued taxes		89			304
Accrued interest		119			92
Accrued vacation pay		60			60
Accrued compensation		47			125
Liabilities from risk management activities		80			68
Other regulatory liabilities, current		84			65
Nuclear decommissioning trust securities lending collateral		12			32
Other current liabilities		144			139
Total current liabilities		3,139			3,141
Long-term Debt		8,117			8,018
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		4,491			4,388
Deferred credits related to income taxes		120			122
Accumulated deferred investment tax credits		217			220
Employee benefit obligations		901			905
Asset retirement obligations		745			734
Other cost of removal obligations		105			110
Other deferred credits and liabilities		254			224
Total deferred credits and other liabilities		6,833			6,703
Total Liabilities		18,089			17,862
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		5,540			5,522
Retained earnings		3,052			3,112
Accumulated other comprehensive loss		(8	)		(9	)
Total common stockholder’s equity		8,982			9,023
Total Liabilities and Stockholder’s Equity	$	27,337		$	27,151

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

54

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2012 vs. FIRST QUARTER 2011

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales 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, and fuel prices. In addition, Georgia Power is currently constructing two new nuclear units and one new combined cycle generating unit. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.

Georgia Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, 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

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(39)	(18.9)

Georgia Power’s net income after dividends on preferred and preference stock for the first quarter 2012 was $167 million compared to $206 million for the corresponding period in 2011. The decrease was primarily due to a decrease in operating revenues as a result of milder weather, higher depreciation and operations and maintenance expense, and lower AFUDC, partially offset by an increase related to retail revenue rate effects and lower income taxes in the first quarter 2012.

Retail Revenues

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(221)	(12.2)

In the first quarter 2012, retail revenues were $1.59 billion compared to $1.82 billion for the corresponding period in 2011.

55

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues were as follows:

	First Quarter 2012
	(in millions)		(% change)
Retail — prior year	$	1,815
Estimated change in —
Rates and pricing		22		1.2
Sales growth (decline)		(7)		(0.4)
Weather		(50)		(2.8)
Fuel cost recovery		(186)		(10.2)
Retail – current year	$	1,594		(12.2)%

Revenues associated with changes in rates and pricing increased in the first quarter 2012 when compared to the corresponding period in 2011 due to the rate pricing effect of decreased customer usage and the NCCR and demand-side management tariff increases effective January 1, 2012, as approved by the Georgia PSC, partially offset by lower contributions from market-driven rates from commercial and industrial customers.

Revenues attributable to changes in sales decreased in the first quarter 2012 when compared to the corresponding period in 2011. Weather-adjusted commercial and industrial KWH sales decreased 2.4% and 0.2%, respectively, in the first quarter 2012 when compared to the corresponding period in 2011, while weather-adjusted residential KWH sales remained flat. The economy continues to impact commercial sales.

Revenues resulting from changes in weather decreased in the first quarter 2012 when compared to the corresponding period in 2011 due to mild weather in the first quarter 2012 and cold weather in January 2011.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased by $186 million in the first quarter of 2012 when compared to the corresponding period in 2011 due to decreased KWH energy sales and lower fuel costs. See “Fuel and Purchased Power Expenses” 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 fuel cost recovery 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

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(17)	(20.5)

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power’s and the Southern Company system’s generation, demand for energy within the Southern Company system’s service territory, and the availability of the Southern Company system’s generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power’s variable cost of energy.

56

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the first quarter 2012, wholesale revenues from non-affiliates were $66 million compared to $83 million in the corresponding period in 2011, primarily due to a $20 million decrease in energy revenues, partially offset by a $3 million increase in capacity revenues. The decrease in the first quarter 2012 was primarily due to a 41.3% decrease in KWH sales due to lower demand resulting from mild weather in the first quarter 2012 and cold weather in January 2011.

Wholesale Revenues — Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(8)	(72.7)

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

In the first quarter 2012, wholesale revenues from affiliates were $3 million compared to $11 million in the corresponding period in 2011. The decrease was primarily due to a 59.5% decrease in KWH sales due to lower demand resulting from milder weather and the availability of market energy at a lower cost than Georgia Power-owned generation.

Fuel and Purchased Power Expenses

First Quarter 2012 vs. First Quarter 2011
	(change in millions)		(% change)
Fuel	$	(237)		(35.0)
Purchased power — non-affiliates		19		25.7
Purchased power — affiliates		(4)		(2.5)
Total fuel and purchased power expenses	$	(222)

In the first quarter 2012, total fuel and purchased power expenses were $692 million compared to $914 million in the corresponding period in 2011. The decrease was primarily due to the lower cost of natural gas used for generation and lower demand related to mild weather in the first quarter 2012 compared to cold weather in January 2011.

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

57

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2012		First Quarter 2011
Total generation (billions of KWHs)		13		16
Total purchased power (billions of KWHs)		8		6
Sources of generation (percent) —
Coal		42		62
Nuclear		30		23
Gas		26		12
Hydro		2		3
Cost of fuel, generated (cents per net KWH) —
Coal		4.67		4.74
Nuclear		0.86		0.68
Gas		3.16		4.37
Average cost of fuel, generated (cents per net KWH)		3.10		3.73
Average cost of purchased power (cents per net KWH)*		3.86		5.57

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

Fuel

In the first quarter 2012, fuel expense was $440 million compared to $677 million in the corresponding period in 2011. The decrease was due to a 22.1% decrease of KWHs generated as a result of lower KWH demand and a 16.9% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.

Purchased Power – Non-Affiliates

In the first quarter 2012, purchased power expense from non-affiliates was $93 million compared to $74 million in the corresponding period in 2011. The increase was due to a 139.8% increase in KWHs purchased as the market cost of available energy was lower than the additional Georgia Power-owned generation available, partially offset by a decrease of 47.9% in the average cost per KWH purchased.

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

Other Operations and Maintenance Expenses

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$12	2.8

In the first quarter 2012, other operations and maintenance expenses were $434 million compared to $422 million in the corresponding period in 2011. The increase was primarily due to a $10 million increase in employee pension expense, a $5 million increase in customer assistance expense, and a $2 million increase in nuclear property insurance, partially offset by an $8 million decrease in power generation expense due to outage timing and scope of outage work performed and a decrease in KWH generated as a result of lower demand due to milder weather in the first quarter 2012.

58

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Depreciation and Amortization

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$15	8.7

In the first quarter 2012, depreciation and amortization was $188 million compared to $173 million in the corresponding period in 2011. The increase was primarily due to a $12 million increase in depreciation on additional plant in service related to new generation at Plant McDonough Unit 4 that went into service in December 2011, as well as additional transmission, distribution, and environmental projects.

Allowance for Equity Funds Used During Construction

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(12)	(48.0)

In the first quarter 2012, AFUDC equity was $13 million compared to $25 million in the corresponding period in 2011. The decrease was due to the completion of Plant McDonough Unit 4 in December 2011.

Interest Expense, Net of Amounts Capitalized

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(5)	(5.2)

In the first quarter 2012, interest expense, net of amounts capitalized was $91 million compared to $96 million for the corresponding period in 2011. The decrease for the first quarter 2012 when compared to the corresponding period in 2011 was primarily due to lower interest expense on existing variable rate pollution control revenue bonds.

Income Taxes

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(19)	(17.1)

In the first quarter 2012, income taxes were $92 million compared to $111 million in the corresponding period in 2011 due to lower pre-tax earnings.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power’s future earnings potential. The level of Georgia Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include Georgia Power’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power’s service territory. Changes in 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.

59

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

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

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power. At the same time, the EPA asked the U.S. Court of Appeals for the Eleventh Circuit to stay its appeal of the judgment in favor of Alabama Power. Alabama Power filed oppositions to the EPA’s motion and its request for a stay. On March 29, 2012, the U.S. Court of Appeals for the Eleventh Circuit denied the EPA’s request to stay its appeal. The U.S. District Court for the Northern District of Alabama has not ruled on the EPA’s motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.

Climate Change Litigation

Hurricane Katrina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Climate Change Litigation – Hurricane Katrina Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Climate Change Litigation – Hurricane Katrina Case” in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed on May 27, 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

General

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – General” of Georgia Power in Item 7 of the Form 10-K for information regarding Georgia Power’s estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Georgia Power’s preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA’s final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA’s proposed water and coal combustion byproducts rules. Georgia Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA’s proposed water and coal combustion byproducts rules.

60

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Georgia Power’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated, including any proposed environmental regulations; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Georgia Power’s fuel mix. These costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, 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 the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.

As part of Southern Electric Generating Company’s (SEGCO) environmental compliance strategy, the Board of Directors of SEGCO approved adding natural gas as the primary fuel source in 2015 for its 1,000 MWs of generating capacity and the construction of the necessary natural gas pipeline. SEGCO is jointly owned by Georgia Power and Alabama Power. The capacity of SEGCO’s units is sold to Georgia Power and Alabama Power through a PPA. See Note 4 to the financial statements of Georgia Power in Item 8 of the Form 10-K for additional information. The impact of SEGCO’s ultimate compliance strategy on such PPA costs cannot be determined at this time; however, if such costs cannot continue to be recovered through retail rates, they could have a material impact on Georgia Power’s financial statements.

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 on the eight-hour ozone air quality standards and the MATS rule.

On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. The only area within Georgia Power’s service territory designated as a nonattainment area was a 15-county area within metropolitan Atlanta.

Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Georgia Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court of Appeals for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Georgia Power in Item 7 of the Form 10-K for additional information. On April 5, 2012, 10 environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts as soon as possible. Other parties are expected to file similar challenges. The ultimate outcome of this matter cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Georgia Power in Item 7 of the Form 10-K for additional information. On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.

61

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 March 31, 2012, Georgia Power had a total over recovered fuel cost balance of approximately $22 million compared to an under recovered balance of $137 million at December 31, 2011. The over recovered fuel costs at March 31, 2012 are included in other deferred credits and liabilities on Georgia Power’s Condensed Balance Sheet herein. The under recovered fuel costs at December 31, 2011 are included in current assets on Georgia Power’s Condensed Balance Sheet herein. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.

On March 30, 2012, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 19%, which is expected to reduce annual billings by $567 million. The decrease in fuel costs is driven primarily by lower natural gas prices as a result of increased natural gas supplies. The Georgia PSC is scheduled to vote on this matter on June 21, 2012. As proposed, the rate decrease would become effective July 1, 2012; however, Georgia Power is currently working with the Georgia PSC to potentially implement the proposed decrease effective June 1, 2012. The ultimate outcome of this matter cannot be determined at this time.

2011 Integrated Resource Plan Update

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

On March 20, 2012, the Georgia PSC approved Georgia Power’s request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Power’s 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.

Income Tax Matters

Bonus Depreciation

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. Consequently, Georgia Power’s positive cash flow benefit is estimated to be between $320 million and $420 million in 2012.

62

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Construction

Nuclear

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Construction – Nuclear” in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4.

On February 16, 2012, a group of petitioners who had intervened in the NRC’s combined construction and operating licenses (COLs) proceedings for Plant Vogtle Units 3 and 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the NRC’s issuance of the COLs. In addition, on February 16, 2012, another group of petitioners filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC’s certification of the Westinghouse Design Certification Document, as amended (DCD). On April 3, 2012, the U.S. Court of Appeals for the District of Columbia Circuit granted a motion filed by these two groups of petitioners to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the COLs for Plant Vogtle Units 3 and 4 with the U.S. District Court for the District of Columbia. Georgia Power has filed a motion to intervene in these proceedings and intends to vigorously contest these petitions.

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve inclusion of the related CWIP accounts in rate base. Also in 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows Georgia Power to recover financing costs for nuclear construction projects by including the related CWIP accounts in rate base during the construction period. 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. The Georgia PSC has ordered Georgia Power to report against this total certified cost of approximately $6.1 billion. In addition, in December 2010, the Georgia PSC approved Georgia Power’s NCCR tariff. The NCCR tariff became effective January 1, 2011 and adjustments are filed with the Georgia PSC on November 1 of each year to become effective on January 1 of the following year. 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 March 31, 2012, approximately $68 million of these 2009 and 2010 costs remained in CWIP.

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 Westinghouse and Stone & Webster, Inc. (collectively, Consortium) have established both informal and formal dispute resolution procedures in accordance with the engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 MWs each and related facilities, structures, and improvements at Plant Vogtle entered into by the parties (Vogtle 3 and 4 Agreement) in order to resolve issues arising during the course of constructing a project of this magnitude. The Consortium and Georgia Power (on behalf of the Owners) have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

63

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

During the course of construction activities, issues have arisen that may impact the project budget and schedule, including costs associated with design changes to the DCD, and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the COLs. The Owners and the Consortium have begun negotiations regarding these issues, including the assertion by the Consortium that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. In preliminary discussions, the Consortium has provided its initial estimate of its proposed adjustment to the contract price. The Consortium’s estimated adjustment attributable to Georgia Power (based on Georgia Power’s ownership interest) is approximately $400 million (in 2008 dollars) with respect to these issues, which include an initial estimate of costs for efforts to maintain the projected in-service dates of 2016 and 2017 for Plant Vogtle Units 3 and 4, respectively. Georgia Power has not agreed with the amount of these proposed adjustments or that the Owners have responsibility for any costs related to these issues. Georgia Power expects negotiations with the Consortium to continue over the next several months during which time the parties will attempt to reach a mutually acceptable compromise of their positions. If a compromise cannot be reached, formal dispute resolution, including litigation, may follow. Georgia Power intends to vigorously defend its positions. If these costs are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. Additional claims by the Consortium or Georgia Power (on behalf of the Owners) are expected to arise throughout the construction of Plant Vogtle Units 3 and 4.

In addition, there are processes in place to assure compliance with the design requirements specified in the DCD and the COLs, including rigorous inspection by Southern Nuclear and the NRC that occurs throughout construction. A recent routine NRC inspection identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. Georgia Power expects to receive official notice of these findings from the NRC. Georgia Power, on behalf of the Owners, is currently engaged in constructive discussions with the Consortium to identify appropriate corrective actions. Various inspection issues are expected as construction proceeds.

There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including legal challenges to the NRC issuance of the COLs and certification of the DCD. Similar additional challenges at the state and federal level are expected as construction proceeds.

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

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

Other Construction

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction – Other Construction” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Construction – Other Construction” in Item 8 of the Form 10-K for additional information.

Georgia Power placed Plant McDonough Unit 5 into service on April 26, 2012. Plant McDonough Unit 6 is expected to be placed into service in November 2012. Plant McDonough Unit 1 was retired on February 29, 2012.

64

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury 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 a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Other Matters” of Georgia Power in Item 7 of the Form 10-K for additional information regarding the earthquake and tsunami that struck Japan in March 2011. On March 12, 2012, the NRC issued three orders and a request for information based on the NRC task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, including the one in use at Plant Hatch, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. The staff of the NRC expects to issue additional implementation guidance by August 2012. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the NRC and cannot be determined at this time. See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

65

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Overview” of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power’s financial condition remained stable at March 31, 2012. 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,” “Financing Activities,” and “Capital Requirements and Contractual Obligations” herein for additional information.

Net cash provided from operating activities totaled $312 million for the first three months of 2012 compared to $350 million for the corresponding period in 2011. The $38 million decrease is primarily due to lower retail operating revenues and higher fuel inventory additions in the first quarter 2012. Net cash used for investing activities totaled $681 million primarily due to gross property additions to utility plant in the first three months of 2012. Net cash provided from financing activities totaled $369 million for the first three months of 2012 compared to $81 million for the corresponding period in 2011. The $288 million increase is primarily due to increased debt issuances in the first quarter 2012.

Significant balance sheet changes for the first three months of 2012 include increases of $288 million in total property, plant, and equipment and $121 million in fossil fuel stock, as well as the elimination of $137 million in under recovered fuel.

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 $855 million will be required through March 31, 2013 to fund maturities of long-term debt.

On March 20, 2012, the Georgia PSC approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. However, these PPAs remain subject to FERC approval. See FUTURE EARNINGS POTENTIAL – “PSC Matters – 2011 Integrated Resource Plan Update” herein for additional information. These PPAs will be accounted for as leases and are expected to result in additional obligations of approximately $56 million in 2015, $66 million in 2016, and a total of $973 million thereafter. The ultimate outcome of this matter cannot be determined at this time.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet 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.

66

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 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.

At March 31, 2012, Georgia Power had approximately $13 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2012 were as follows:

Expires					Executable Term Loans		Due Within One Year(a)
2012	2013	2014 and     Beyond	Total	Unused	One     Year	Two   Year	Term     Out	No Term Out
(in millions)			(in millions)		(in millions)		(in millions)
$—	$—	$1,750	$1,750	$1,745	$—	$—	$—	$—

(a) Reflects facilities expiring on or before March 31, 2013.

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.

Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Georgia Power. Georgia Power is currently in compliance with all such covenants. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Georgia Power’s commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2012 was approximately $868 million.

67

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Details of short-term borrowings, excluding $2 million of notes payable related to other energy service contracts, were as follows:

	Short-term Debt at  the End of the Period				Short-term Debt During the Period (a)
	Amount Outstanding		Weighted     Average     Interest     Rate		Average     Outstanding		Weighted Average Interest Rate		Maximum     Amount     Outstanding
	(in millions)				(in millions)				(in millions)
March 31, 2012:
Commercial paper		$    312		0.3%		$    229		0.2%		$    517
Short-term bank debt		300		1.1%		290		1.2%		300
Total		$    612		0.7%		$    519		0.8%

(a) Average and maximum amounts are based upon daily balances during the period.

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. The maximum potential collateral requirements under these contracts at March 31, 2012 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$      68
Below BBB- and/or Baa3	1,540

Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

68

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 first quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts or heat-rate contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power had no material change in market risk exposure for the first quarter 2012 relative to fuel and electricity prices when compared with the December 31, 2011 reporting period.

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three months ended March 31, 2012 were as follows:

	First Quarter 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$(82)
Contracts realized or settled	19
Current period changes(a)	(23)
Contracts outstanding at the end of the period, assets (liabilities), net	$(86)

(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 months ended March 31, 2012 was a decrease of $4 million, of which $8 million related to a decrease from natural gas options, partially offset by an increase of $4 million from natural gas swaps. The change is attributable to both the volume of mmBtu and the price of natural gas. At March 31, 2012, Georgia Power had a net hedge volume of 85 million mmBtu, which consisted of 25 million mmBtu of swaps and 60 million mmBtu of options. The weighted average swap contract cost was approximately $2.13 per mmBtu above market prices. At December 31, 2011, Georgia Power had a net hedge volume of 73 million mmBtu, which consisted of 29 million mmBtu of swaps and 44 million mmBtu of options. The weighted average swap contract cost was approximately $1.65 per mmBtu above market prices. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. All natural gas hedge gains and losses are recovered through Georgia Power’s fuel cost recovery mechanism.

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

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.

69

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 March 31, 2012 were as follows:

	March 31, 2012 Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3
		(in millions)
Level 1	$ —	$ —	$ —
Level 2	(86)	(66)	(20)
Level 3	—	—	—
Fair value of contracts outstanding at end of period	$(86)	$(66)	$(20)

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 all relevant 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 January 2012, Georgia Power entered into a six-month floating rate bank loan in an aggregate amount of $100 million, bearing interest based on one-month LIBOR. The proceeds were used for general corporate purposes, including Georgia Power’s continuous construction program.

In March 2012, Georgia Power issued $750 million aggregate principal amount of Series 2012A 4.30% Senior Notes due March 15, 2042. The proceeds were used to repay a portion of Georgia Power’s short-term debt, to repay two bank loans, each in an aggregate principal amount of $125 million, and for general corporate purposes, including Georgia Power’s continuous construction program.

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.

70

GULF POWER COMPANY

71

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in thousands)
Operating Revenues:
Retail revenues	$	238,520		$	274,826
Wholesale revenues, non-affiliates		27,118			31,019
Wholesale revenues, affiliates		36,364			4,135
Other revenues		14,243			14,628
Total operating revenues		316,245			324,608
Operating Expenses:
Fuel		121,088			131,782
Purchased power, non-affiliates		11,225			7,003
Purchased power, affiliates		2,513			16,618
Other operations and maintenance		75,230			80,509
Depreciation and amortization		33,307			31,756
Taxes other than income taxes		23,784			24,896
Total operating expenses		267,147			292,564
Operating Income		49,098			32,044
Other Income and (Expense):
Allowance for equity funds used during construction		1,237			2,135
Interest expense, net of amounts capitalized		(15,368	)		(13,629	)
Other income (expense), net		(1,009	)		(549	)
Total other income and (expense)		(15,140	)		(12,043	)
Earnings Before Income Taxes		33,958			20,001
Income taxes		11,741			6,759
Net Income		22,217			13,242
Dividends on Preference Stock		1,551			1,551
Net Income After Dividends on Preference Stock	$	20,666		$	11,691

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012		2011
	(in thousands)
Net Income After Dividends on Preference Stock	$	20,666	$	11,691
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $90 and $90, respectively		143		143
Total other comprehensive income (loss)		143		143
Comprehensive Income	$	20,809	$	11,834

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

72

GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in thousands)
Operating Activities:
Net income	$	22,217		$	13,242
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		34,844			33,294
Deferred income taxes		32,505			6,249
Allowance for equity funds used during construction		(1,237	)		(2,135	)
Pension, postretirement, and other employee benefits		1,315			(1,256	)
Stock based compensation expense		685			518
Other, net		5,478			(3,793	)
Changes in certain current assets and liabilities —
-Receivables		14,754			35,336
-Prepayments		1,559			1,156
-Fossil fuel stock		1,543			(14,941	)
-Materials and supplies		(1,476	)		(726	)
-Prepaid income taxes		17,324			28,889
-Other current assets		-			7
-Accounts payable		(21,516	)		(8,863	)
-Accrued taxes		(1,453	)		4,053
-Accrued compensation		(9,190	)		(10,000	)
-Over recovered regulatory clause revenues		14,516			687
-Other current liabilities		5,637			5,440
Net cash provided from operating activities		117,505			87,157
Investing Activities:
Property additions		(94,879	)		(94,239	)
Cost of removal, net of salvage		(9,342	)		(5,314	)
Change in construction payables		7,773			3,171
Payments pursuant to long-term service agreements		(2,274	)		(2,198	)
Other investing activities		(76	)		68
Net cash used for investing activities		(98,798	)		(98,512	)
Financing Activities:
Decrease in notes payable, net		(27,338	)		(6,620	)
Proceeds —
Common stock issued to parent		40,000			50,000
Capital contributions from parent company		732			809
Redemptions —
Senior notes		(16	)		(125	)
Payment of preference stock dividends		(1,551	)		(1,551	)
Payment of common stock dividends		(28,950	)		(27,500	)
Other financing activities		198			110
Net cash provided from (used for) financing activities		(16,925	)		15,123
Net Change in Cash and Cash Equivalents		1,782			3,768
Cash and Cash Equivalents at Beginning of Period		17,328			16,434
Cash and Cash Equivalents at End of Period	$	19,110		$	20,202
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $493 and $851 capitalized for 2012 and 2011, respectively)	$	9,352		$	8,284
Income taxes (net of refunds)		(35,742	)		(29,557	)
Noncash transactions - accrued property additions at end of period		28,788			17,882

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

73

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2012			At December 31, 2011
	(in thousands)
Current Assets:
Cash and cash equivalents	$	19,110		$	17,328
Receivables —
Customer accounts receivable		54,868			72,754
Unbilled revenues		48,705			49,921
Under recovered regulatory clause revenues		4,536			5,530
Other accounts and notes receivable		11,546			13,350
Affiliated companies		19,986			14,844
Accumulated provision for uncollectible accounts		(1,433	)		(1,962	)
Fossil fuel stock, at average cost		146,023			147,567
Materials and supplies, at average cost		51,257			49,781
Other regulatory assets, current		44,521			35,849
Prepaid expenses		44,153			28,327
Other current assets		469			2,051
Total current assets		443,741			435,340
Property, Plant, and Equipment:
In service		3,898,726			3,846,446
Less accumulated provision for depreciation		1,140,589			1,124,291
Plant in service, net of depreciation		2,758,137			2,722,155
Construction work in progress		333,631			287,173
Total property, plant, and equipment		3,091,768			3,009,328
Other Property and Investments		16,469			16,394
Deferred Charges and Other Assets:
Deferred charges related to income taxes		49,453			48,210
Other regulatory assets, deferred		316,519			323,116
Other deferred charges and assets		29,433			39,493
Total deferred charges and other assets		395,405			410,819
Total Assets	$	3,947,383		$	3,871,881

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At March 31, 2012			At December 31, 2011
	(in thousands)
Current Liabilities:
Notes payable		83,589			114,507
Accounts payable —
Affiliated		45,716			54,874
Other		61,034			63,265
Customer deposits		36,010			35,779
Accrued taxes —
Accrued income taxes		104			1,362
Other accrued taxes		11,712			12,114
Accrued interest		19,312			14,018
Accrued compensation		5,294			14,485
Other regulatory liabilities, current		45,436			35,639
Liabilities from risk management activities		30,811			22,786
Other current liabilities		23,104			22,916
Total current liabilities		362,122			391,745
Long-term Debt		1,235,586			1,235,447
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		515,663			458,978
Accumulated deferred investment tax credits		6,422			6,760
Employee benefit obligations		109,589			109,740
Other cost of removal obligations		211,649			214,598
Other regulatory liabilities, deferred		45,300			44,843
Other deferred credits and liabilities		204,446			186,824
Total deferred credits and other liabilities		1,093,069			1,021,743
Total Liabilities		2,690,777			2,648,935
Preference Stock		97,998			97,998
Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - March 31, 2012: 4,542,717 shares
- December 31, 2011: 4,142,717 shares		393,060			353,060
Paid-in capital		544,510			542,709
Retained earnings		223,049			231,333
Accumulated other comprehensive loss		(2,011	)		(2,154	)
Total common stockholder’s equity		1,158,608			1,124,948
Total Liabilities and Stockholder’s Equity	$	3,947,383		$	3,871,881

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

75

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2012 vs. FIRST QUARTER 2011

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales 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 prices, and storm restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.

On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSC’s decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Power’s authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Power’s retail base rates and charges of $4 million to be effective in January 2013. On April 18, 2012, Gulf Power filed a motion to reconsider one aspect of the decision dealing with property acquired as a potential site for a future generating plant. If the motion is granted, the previously approved rates would be increased by an additional $2 million. The ultimate outcome of this matter cannot be determined at this time.

Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS — OVERVIEW — “Key Performance Indicators” of Gulf Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$9.0	76.8

Gulf Power’s net income after dividends on preference stock for the first quarter 2012 was $20.7 million compared to $11.7 million for the corresponding period in 2011. The increase was primarily due to an increase related to interim retail rate revenues, higher wholesale capacity revenues from non-affiliates, and a decrease in other operations and maintenance expenses in 2012, partially offset by milder weather in the first quarter 2012 compared to the corresponding period in 2011.

Retail Revenues

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(36.3)	(13.2)

In the first quarter 2012, retail revenues were $238.5 million compared to $274.8 million for the corresponding period in 2011.

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the change to retail revenues were as follows:

	First Quarter 2012
	(in millions)	(% change)
Retail – prior year	$274.8
Estimated change in –
Rates and pricing	12.5	4.5
Sales growth (decline)	1.3	0.5
Weather	(8.3)	(3.0)
Fuel and other cost recovery	(41.8)	(15.2)
Retail – current year	$238.5	(13.2)%

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information regarding Gulf Power’s retail base rate case and cost recovery clauses, including Gulf Power’s fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery.

Revenues associated with changes in rates and pricing increased in the first quarter 2012 when compared to the corresponding period in 2011 primarily due to an increase related to interim retail rate revenues and revenues associated with higher recoverable costs under Gulf Power’s energy conservation cost recovery clause, partially offset by revenues associated with lower recoverable costs under Gulf Power’s environmental cost recovery clause.

Revenues attributable to changes in sales increased in the first quarter 2012 when compared to the corresponding period in 2011. KWH energy sales to industrial customers decreased 6.8% primarily due to increased customer co-generation associated with the lower cost of natural gas in 2012 and changes in customer production levels. Weather-adjusted KWH energy sales to commercial customers increased 3.3% due to higher use per customer. Weather-adjusted KWH energy sales to residential customers remained relatively flat.

Revenues attributable to changes in weather decreased in the first quarter 2012 when compared to the corresponding period for 2011 due to milder weather in the first quarter 2012 compared to the corresponding period in 2011.

Fuel and other cost recovery revenues decreased in the first quarter 2012 when compared to the corresponding period for 2011 primarily due to revenues associated with lower recoverable fuel cost for generation and purchased power energy costs in addition to fewer KWH energy sales. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery” herein for additional information.

Wholesale Revenues – Non-Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(3.9)	(12.6)

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

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost.

In the first quarter 2012, wholesale revenues from non-affiliates were $27.1 million compared to $31.0 million for the corresponding period in 2011. The decrease was primarily due to lower energy revenues related to a 58.4% decrease in KWH sales resulting primarily from less energy scheduled by unit power customers, partially offset by a 31.6% increase in capacity revenues related to increased capacity rates resulting from contract provisions. These contracts include change-in-law provisions that provide for recovery of the environmental costs related to the generating resource.

Wholesale Revenues – Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$32.3	779.4

Wholesale revenues from sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the fuel revenue related to energy sales and the cost of energy purchases are both included in the determination of recoverable fuel costs and are generally offset by revenues collected in Gulf Power’s fuel cost recovery clause.

In the first quarter 2012, wholesale revenues from affiliates were $36.4 million compared to $4.1 million for the corresponding period in 2011. The increase was primarily due to higher energy revenues related to a 1,205% increase in KWH energy sales resulting from the availability of Gulf Power’s lower priced natural gas resources to serve affiliate demand.

Fuel and Purchased Power Expenses

First Quarter 2012 vs. First Quarter 2011
	(change in millions)	(% change)
Fuel	$(10.7)	(8.1)
Purchased power – non-affiliates	4.2	60.3
Purchased power – affiliates	(14.1)	(84.9)
Total fuel and purchased power expenses	$(20.6)

In the first quarter 2012, total fuel and purchased power expenses were $134.8 million compared to $155.4 million for the corresponding period in 2011. The net decrease in fuel and purchased power expenses was due to a $65.5 million decrease in the average cost of generated and purchased power and a $25.0 million decrease related to KWHs generated, partially offset by a $69.9 million increase related to KWHs purchased.

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

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2012	First Quarter 2011
Total generation (millions of KWHs)	2,341	2,801
Total purchased power (millions of KWHs)	1,750	448
Sources of generation (percent) –
Coal	53	67
Gas	47	33
Cost of fuel, generated (cents per net KWH) –
Coal	4.29	5.03
Gas	3.44	3.99
Average cost of fuel, generated (cents per net KWH)	3.89	4.69
Average cost of purchased power (cents per net KWH)*	2.50	5.37

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

Fuel

In the first quarter 2012, fuel expense was $121.1 million compared to $131.8 million for the corresponding period in 2011. The decrease was primarily the result of a 13.8% decrease in the average cost of natural gas per KWH generated, a higher percentage of utilization of lower cost natural gas-fired sources, and a 16.5% decrease in KWHs generated as a result of lower demand. These decreases were partially offset by a 290.6% increase in KWHs purchased.

In the first quarter 2012, the decrease in the average cost of fuel was a result of decreases in the average costs of natural gas and coal per KWH generated and a higher percentage of utilization of Gulf Power’s lower cost natural gas-fired generation sources.

Purchased Power – Non-Affiliates

In the first quarter 2012, purchased power expense from non-affiliates was $11.2 million compared to $7.0 million for the corresponding period in 2011. The increase was primarily due to a $4.2 million increase in energy costs resulting from a 1,957% increase in KWHs purchased.

In the first quarter 2012, the average cost of purchased power from non-affiliates was 2.4 cents per net KWH compared to 8.8 cents per net KWH for the corresponding period in 2011. The decrease was primarily the result of a decrease in the average cost of natural gas.

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

Purchased Power – Affiliates

In the first quarter 2012, purchased power expense from affiliates was $2.5 million compared to $16.6 million for the corresponding period in 2011. The decrease was primarily due to a $14.3 million decrease in energy costs resulting from a 95.2% decrease in KWHs purchased, partially offset by a $0.2 million increase in capacity costs.

In the first quarter 2012, the average cost of purchased power from affiliates was 14.5 cents per net KWH compared to 4.6 cents per net KWH for the corresponding period in 2011. The increase was primarily due to fewer KWHs purchased and increased capacity costs, partially offset by lower energy costs.

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, as approved by the FERC.

Other Operations and Maintenance Expenses

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(5.3)	(6.6)

In the first quarter 2012, other operations and maintenance expenses were $75.2 million compared to $80.5 million for the corresponding period in 2011. The decrease was primarily due to an $11.4 million decrease in routine and planned outage maintenance expense at generation facilities, partially offset by increases of $3.5 million for labor and benefit-related expenses, $1.4 million in marketing programs, and $0.6 million in other energy services projects. The increased expense from energy service projects did not have a material impact on earnings since it was offset by associated revenues.

Depreciation and Amortization

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$1.5	4.9

In the first quarter 2012, depreciation and amortization was $33.3 million compared to $31.8 million for the corresponding period in 2011. The increase was primarily due to net additions to transmission and distribution facilities.

Taxes Other Than Income Taxes

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(1.1)	(4.5)

In the first quarter 2012, taxes other than income taxes were $23.8 million compared to $24.9 million for the corresponding period in 2011. The decrease was primarily due to a $2.0 million decrease in gross receipt taxes and franchise fees, which have no impact on net income, partially offset by a $0.4 million increase in property taxes and a $0.5 million increase in payroll taxes.

Allowance for Equity Funds Used During Construction

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(0.9)	(42.1)

In the first quarter 2012, AFUDC equity was $1.2 million compared to $2.1 million for the corresponding period in 2011. The decrease was primarily due to an adjustment related to deferred future generation carrying costs, partially offset by increases related to construction of environmental control projects at generating facilities.

80

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$1.8	12.8

In the first quarter 2012, interest expense, net of amounts capitalized was $15.4 million compared to $13.6 million for the corresponding period in 2011. The increase was primarily due to net increases in long-term debt.

Income Taxes

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$4.9	73.7

In the first quarter 2012, income taxes were $11.7 million compared to $6.8 million for the corresponding period in 2011. The increase was primarily due to higher pre-tax earnings, partially offset by a decrease in unrecognized tax benefits.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Gulf Power’s future earnings potential. The level of Gulf Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include Gulf Power’s ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power’s service territory. Changes in 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 federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

81

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power. At the same time, the EPA asked the U.S. Court of Appeals for the Eleventh Circuit to stay its appeal of the judgment in favor of Alabama Power. Alabama Power filed oppositions to the EPA’s motion and its request for a stay. On March 29, 2012, the U.S. Court of Appeals for the Eleventh Circuit denied the EPA’s request to stay its appeal. The U.S. District Court for the Northern District of Alabama has not ruled on the EPA’s motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.

Climate Change Litigation

Hurricane Katrina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Climate Change Litigation – Hurricane Katrina Case” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Climate Change Litigation – Hurricane Katrina Case” in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed on May 27, 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

General

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – General” of Gulf Power in Item 7 of the Form 10-K for information regarding Gulf Power’s estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Gulf Power’s preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA’s final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA’s proposed water and coal combustion byproducts rules. Gulf Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA’s proposed water and coal combustion byproducts rules.

Gulf Power’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated, including any proposed environmental regulations; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Gulf Power’s fuel mix. These costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, 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 the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.

82

GULF POWER COMPANY

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 Gulf Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone air quality standards and the MATS rule.

On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Gulf Power’s service territory were designated as nonattainment areas.

Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Gulf Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court of Appeals for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Gulf Power in Item 7 of the Form 10-K for additional information. On April 5, 2012, 10 environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts as soon as possible. Other parties are expected to file similar challenges. The ultimate outcome of this matter cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Gulf Power in Item 7 of the Form 10-K for additional information. On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.

PSC Matters

Retail Base Rate Case

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

On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSC’s decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Power’s authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Power’s retail base rates and charges of $4 million to be effective in January 2013. On April 18, 2012, Gulf Power filed a motion to reconsider one aspect of the decision dealing with property acquired as a potential site for a future generating plant. If the motion is granted, the previously approved rates would be increased by an additional $2 million. The ultimate outcome of this matter cannot be determined at this time.

83

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost Recovery Clauses

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

Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – 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.

Over recovered fuel costs at March 31, 2012 totaled $28.8 million compared to $9.9 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

Purchased Power Capacity Recovery

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.

Over recovered purchased power capacity costs at March 31, 2012 totaled $9.6 million compared to $8.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

Environmental Cost Recovery

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.

Over recovered environmental costs at March 31, 2012 totaled $4.0 million compared to $10.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

On April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015.

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Energy Conservation Cost Recovery

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

Under recovered energy conservation costs at March 31, 2012 totaled $2.0 million compared to $3.1 million at December 31, 2011. These amounts are included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein.

Income Tax Matters

Bonus Depreciation

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. Consequently, Gulf Power’s positive cash flow benefit is estimated to be between $105 million and $135 million in 2012.

Other Matters

Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury 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 a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES –

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

“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

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Overview” of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power’s financial condition remained stable at March 31, 2012. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital,” “Financing Activities,” and “Capital Requirements and Contractual Obligations” herein for additional information.

Net cash provided from operating activities totaled $117.5 million for the first three months of 2012 compared to $87.2 million for the corresponding period in 2011. The $30.3 million increase was primarily due to a $26.3 million increase in deferred income taxes related to bonus depreciation and a $16.5 million increase related to reduced purchases of fossil fuel, partially offset by a $16.0 million decrease related to lower retail operating revenues. Net cash used for investing activities totaled $98.8 million in the first three months of 2012 compared to $98.5 million for the corresponding period in 2011. The $0.3 million increase was primarily due to a decrease in gross property additions. Net cash used for financing activities totaled $16.9 million for the first three months of 2012 compared to $15.1 million provided from financing activities for the corresponding period in 2011. The $32.0 million change was primarily due to a $20.7 million decrease in notes payable and a $10 million decrease in issuances of common stock.

Significant balance sheet changes for the first quarter 2012 include a net increase of $82.4 million in property, plant, and equipment, primarily due to the addition of environmental control projects, a $56.7 million increase in accumulated deferred income taxes, primarily related to bonus depreciation, and the issuance of common stock to Southern Company for $40 million.

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 March 31, 2013 to fund maturities of long-term debt.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet 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.

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sources of Capital

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

Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.

At March 31, 2012, Gulf Power had approximately $19.1 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2012 were as follows:

Expires					Executable Term Loans		Due Within One Year(a)
2012	2013	2014   and   Beyond	Total	Unused	One     Year	Two     Year	Term     Out	No Term Out
(in millions)			(in millions)		(in millions)		(in millions)
$75	$35	$165	$275	$275	$75	$—	$75	$35

(a) Reflects facilities expiring on or before March 31, 2013.

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.

During the first quarter 2012, Gulf Power entered into a new $35 million 364-day committed credit arrangement.

Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Gulf Power. Gulf Power is currently in compliance with all such covenants. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Gulf Power’s commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2012 was approximately $69 million.

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

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at  the End of the Period		Short-term Debt During the Period(a)
	Amount Outstanding	Weighted Average Interest Rate	Average Outstanding	Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)		(in millions)		(in millions)
March 31, 2012:
Commercial paper	$84	0.2%	$85	0.2%	$117

(a) Average and maximum amounts are based upon daily balances during the period.

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

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. The maximum potential collateral requirements under these contracts at March 31, 2012 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$126
Below BBB- and/or Baa3	539

Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Gulf Power’s market risk exposure relative to interest rate changes for the first quarter 2012 has not changed materially compared with the December 31, 2011 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

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

guidelines of the Florida PSC. As such, Gulf Power had no material change in market risk exposure for the first quarter 2012 when compared with the December 31, 2011 reporting period.

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three months ended March 31, 2012 were as follows:

	First Quarter 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$(41)
Contracts realized or settled	6
Current period changes(a)	(19)
Contracts outstanding at the end of the period, assets (liabilities), net	$(54)

(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 months ended March 31, 2012 was a decrease of $13 million, of which $12 million related to natural gas swaps and $1 million related to natural gas options. The change is attributable to both the volume of mmBtu and the price of natural gas. At March 31, 2012, Gulf Power had a net hedge volume of 43 million mmBtu, which consisted of 41 million mmBtu of swaps and 2 million mmBtu of options. The weighted average swap contract cost was approximately $1.27 per mmBtu above market prices. At December 31, 2011, Gulf Power had a net hedge volume of 38 million mmBtu, which consisted of 35 million mmBtu of swaps and 3 million mmBtu of options. The weighted average swap contract cost was approximately $1.14 per mmBtu above market prices. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Natural gas settlements are recovered through Gulf Power’s fuel cost recovery clause.

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

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2012 and 2011 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 March 31, 2012 were as follows:

	March 31, 2012     Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3	Years 4&5
	(in millions)
Level 1	$—	$—	$—	$—
Level 2	(54)	(33)	(20)	(1)
Level 3	—	—	—	—
Fair value of contracts outstanding at end of period	$(54)	$(33)	$(20)	$(1)

89

GULF POWER COMPANY

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 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 all relevant 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 2012, Gulf Power issued to Southern Company 400,000 shares of Gulf Power’s common stock, without par value, and realized proceeds of $40 million. The proceeds were used to repay a portion of Gulf Power’s short-term debt and for other general corporate purposes, including Gulf Power’s continuous construction program.

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

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MISSISSIPPI POWER COMPANY

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2012			2011
	(in thousands)
Operating Revenues:
Retail revenues	$	166,271		$	180,474
Wholesale revenues, non-affiliates		54,231			69,851
Wholesale revenues, affiliates		4,040			9,300
Other revenues		4,172			3,651
Total operating revenues		228,714			263,276
Operating Expenses:
Fuel		88,619			121,054
Purchased power, non-affiliates		1,943			1,010
Purchased power, affiliates		8,860			8,350
Other operations and maintenance		54,895			70,367
Depreciation and amortization		22,481			19,863
Taxes other than income taxes		21,703			17,481
Total operating expenses		198,501			238,125
Operating Income		30,213			25,151
Other Income and (Expense):
Allowance for equity funds used during construction		11,827			3,131
Interest income		120			342
Interest expense, net of amounts capitalized		(7,805	)		(6,013	)
Other income (expense), net		(242	)		(403	)
Total other income and (expense)		3,900			(2,943	)
Earnings Before Income Taxes		34,113			22,208
Income taxes		8,425			7,158
Net Income		25,688			15,050
Dividends on Preferred Stock		433			433
Net Income After Dividends on Preferred Stock	$	25,255		$	14,617

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months
	Ended March 31,
	2012			2011
	(in thousands)
Net Income After Dividends on Preferred Stock	$	25,255		$	14,617
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(296) and $(1), respectively		(478	)		(2	)
Reclassification adjustment for amounts included in net income, net of tax of $16 and $-, respectively		26			—
Total other comprehensive income (loss)		(452	)		(2	)
Comprehensive Income	$	24,803		$	14,615

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

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months
	Ended March 31,
	2012			2011
	(in thousands)
Operating Activities:
Net income	$	25,688		$	15,050
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		21,931			21,442
Deferred income taxes		(1,210	)		10,015
Investment tax credits received		13,974			9,750
Allowance for equity funds used during construction		(11,827	)		(3,131	)
Pension, postretirement, and other employee benefits		2,268			1,037
Hedge settlements		(15,983	)		—
Stock based compensation expense		957			813
Other, net		(1,127	)		(1,363	)
Changes in certain current assets and liabilities —
-Receivables		14,536			11,592
-Fossil fuel stock		(16,188	)		(538	)
-Materials and supplies		(538	)		(317	)
-Prepaid income taxes		4,168			15,976
-Other current assets		(4,357	)		1,649
-Accounts payable		(11,558	)		17,538
-Accrued taxes		(31,434	)		(31,213	)
-Accrued compensation		(10,803	)		(9,556	)
-Over recovered regulatory clause revenues		12,627			7,756
-Other current liabilities		9,480			(149	)
Net cash provided from operating activities		604			66,351
Investing Activities:
Property additions		(370,923	)		(148,917	)
Cost of removal, net of salvage		(1,149	)		(2,830	)
Construction payables		30,080			33,291
Capital grant proceeds		1,816			16,912
Distribution of restricted cash		—			50,000
Other investing activities		(4,207	)		(834	)
Net cash used for investing activities		(344,383	)		(52,378	)
Financing Activities:
Proceeds —
Capital contributions from parent company		150,735			50,610
Senior notes issuances		400,000			—
Interest-bearing refundable deposit related to asset sale		150,000			—
Redemptions —
Capital leases		(377	)		(349	)
Other long-term debt		(75,000	)		(130,000	)
Payment of preferred stock dividends		(433	)		(433	)
Payment of common stock dividends		(26,700	)		(18,875	)
Other financing activities		715			(312	)
Net cash provided from (used for) financing activities		598,940			(99,359	)
Net Change in Cash and Cash Equivalents		255,161			(85,386	)
Cash and Cash Equivalents at Beginning of Period		211,585			160,779
Cash and Cash Equivalents at End of Period	$	466,746		$	75,393
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (paid $5,965 and $7,129, net of $6,565 and $994 capitalized for 2012 and 2011, respectively)	$	—		$	6,135
Income taxes (net of refunds)		(11,994	)		(32,294	)
Noncash transactions — accrued property additions at end of period		165,982			72,114

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2012			At December 31, 2011
	(in thousands)
Current Assets:
Cash and cash equivalents	$	466,746		$	211,585
Receivables —
Customer accounts receivable		27,836			32,551
Unbilled revenues		27,231			27,239
Other accounts and notes receivable		3,716			7,080
Affiliated companies		19,463			23,078
Accumulated provision for uncollectible accounts		(415	)		(547	)
Fossil fuel stock, at average cost		156,360			140,173
Materials and supplies, at average cost		31,325			30,787
Other regulatory assets, current		75,249			69,201
Prepaid income taxes		37,408			37,793
Other current assets		10,000			8,881
Total current assets		854,919			587,821
Property, Plant, and Equipment:
In service		2,912,571			2,902,240
Less accumulated provision for depreciation		1,035,946			1,019,251
Plant in service, net of depreciation		1,876,625			1,882,989
Construction work in progress		1,323,400			955,135
Total property, plant, and equipment		3,200,025			2,838,124
Other Property and Investments		6,288			6,520
Deferred Charges and Other Assets:
Deferred charges related to income taxes		39,703			25,009
Other regulatory assets, deferred		190,894			185,694
Other deferred charges and assets		30,422			28,674
Total deferred charges and other assets		261,019			239,377
Total Assets	$	4,322,251		$	3,671,842

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At March 31, 2012			At December 31, 2011
	(in thousands)
Current Liabilities:
Securities due within one year	$	255,255		$	240,633
Interest-bearing refundable deposit related to asset sale		150,000			—
Accounts payable —
Affiliated		50,786			62,650
Other		198,396			168,309
Customer deposits		13,993			13,658
Accrued taxes —
Accrued income taxes		5,922			3,813
Other accrued taxes		20,364			53,825
Accrued interest		22,264			12,750
Accrued compensation		5,086			15,889
Other regulatory liabilities, current		5,535			5,779
Over recovered regulatory clause liabilities		73,129			60,502
Liabilities from risk management activities		39,649			54,127
Other current liabilities		20,797			17,533
Total current liabilities		861,176			709,468
Long-term Debt		1,412,662			1,103,596
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		259,903			270,397
Deferred credits related to income taxes		10,800			11,058
Accumulated deferred investment tax credits		150,983			109,761
Employee benefit obligations		162,007			161,065
Other cost of removal obligations		130,909			126,424
Other regulatory liabilities, deferred		61,831			60,848
Other deferred credits and liabilities		39,700			37,228
Total deferred credits and other liabilities		816,133			776,781
Total Liabilities		3,089,971			2,589,845
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		847,035			694,855
Retained earnings		324,123			325,568
Accumulated other comprehensive loss		(9,349	)		(8,897	)
Total common stockholder’s equity		1,199,500			1,049,217
Total Liabilities and Stockholder’s Equity	$	4,322,251		$	3,671,842

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

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2012 vs. FIRST QUARTER 2011

OVERVIEW

Mississippi Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Mississippi Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, capital expenditures, and restoration following major storms. In addition, Mississippi Power is currently constructing the Kemper IGCC. Mississippi Power has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

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

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$10.7	72.8

Mississippi Power’s net income after dividends on preferred stock for the first quarter 2012 was $25.3 million compared to $14.6 million for the corresponding period in 2011. The increase in net income after dividends on preferred stock for the first quarter 2012 was the result of an increase in AFUDC equity primarily related to the construction of the Kemper IGCC, which began in June 2010, and a decrease in operations and maintenance expenses. These factors were partially offset by a decrease in territorial base revenues resulting from milder weather in the first quarter 2012 compared to the corresponding period in 2011. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Integrated Coal Gasification Combined Cycle” and Note (B) to the Condensed Financial Statements herein for additional information regarding the Kemper IGCC.

96

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(14.2)	(7.9)

In the first quarter 2012, retail revenues were $166.3 million compared to $180.5 million for the corresponding period in 2011.

Details of the change to retail revenues were as follows:

	First Quarter 2012
	(in millions)	(% change)
Retail – prior year	$180.5
Estimated change in –
Rates and pricing	(1.1)	(0.6)
Sales growth (decline)	3.1	1.7
Weather	(4.9)	(2.7)
Fuel and other cost recovery	(11.3)	(6.3)
Retail – current year	$166.3	(7.9)%

Revenues associated with changes in rates and pricing decreased in the first quarter 2012 when compared to the corresponding period in 2011 due to a decrease of $1.1 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 – “PSC Matters – Environmental Compliance Overview Plan” herein for additional information.

Revenues attributable to changes in sales increased in the first quarter 2012 when compared to the corresponding period in 2011. KWH energy sales to industrial customers increased 4.7% due to increased production for several large industrial customers resulting from continued economic recovery. Weather-adjusted KWH energy sales to residential and commercial customers increased 1.2% and 0.9%, respectively, when compared to the corresponding period in 2011 due to a small increase in the number of customers.

Revenues attributable to changes in weather decreased in the first quarter 2012 when compared to the corresponding period for 2011 primarily due to milder weather in the first quarter 2012.

Fuel and other cost recovery revenues decreased in the first quarter 2012 when compared to the corresponding period in 2011 primarily as a result of lower 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.

97

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(15.7)	(22.4)

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

In the first quarter 2012, wholesale revenues from non-affiliates were $54.2 million compared to $69.9 million for the corresponding period in 2011. The decrease was due to a $10.9 million decrease in energy revenues, of which $5.0 million was associated with a decrease in KWH sales due to lower demand primarily resulting from milder weather in the first quarter 2012 compared to the corresponding period in 2011 and $5.9 million was associated with lower fuel prices, and a $4.8 million decrease in capacity revenues resulting from lower customer demand.

Wholesale Revenues – Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(5.3)	(56.6)

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

In the first quarter 2012, wholesale revenues from affiliates were $4.0 million compared to $9.3 million for the corresponding period in 2011. The decrease was primarily due to a $5.2 million decrease in energy revenues, of which $2.8 million was associated with a decrease in KWH sales and $2.4 million was associated with lower prices.

Fuel and Purchased Power Expenses

First Quarter 2012 vs. First Quarter 2011
	(change in millions)	(% change)
Fuel	($32.5)	(26.8)
Purchased power — non-affiliates	0.9	92.4
Purchased power — affiliates	0.6	6.1
Total fuel and purchased power expenses	($31.0)

In the first quarter 2012, total fuel and purchased power expenses were $99.4 million compared to $130.4 million for the corresponding period in 2011. The decrease was primarily due to an $18.0 million decrease in the cost of fuel and purchased power and a $13.0 million decrease in total KWHs generated and purchased as a result of lower KWH demand primarily due to milder weather in the first quarter 2012.

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

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2012	First Quarter 2011
Total generation (millions of KWHs)	2,982	3,364
Total purchased power (millions of KWHs)	447	304
Sources of generation (percent) –
Coal	21	35
Gas	79	65
Cost of fuel, generated (cents per net KWH) –
Coal	4.77	4.23
Gas	2.83	3.72
Average cost of fuel, generated (cents per net KWH)	3.29	3.92
Average cost of purchased power (cents per net KWH)	2.42	3.08

Fuel

In the first quarter 2012, fuel expense was $88.6 million compared to $121.1 million for the corresponding period in 2011. The decrease was primarily due to a 23.9% decrease in the average cost of natural gas per KWH generated primarily resulting from lower gas prices and a 12.7% decrease in generation from Mississippi Power’s facilities resulting from lower energy demand primarily due to milder weather in the first quarter 2012 compared to the corresponding period in 2011.

Purchased Power – Non-Affiliates

In the first quarter 2012, purchased power expense from non-affiliates was $1.9 million compared to $1.0 million for the corresponding period in 2011. The increase was primarily the result of a 77.6% increase in KWH volume purchased and an 8.3% increase in the average cost of purchased power per KWH. The increase in the volume of KWHs purchased was due to a decrease in generation from Mississippi Power’s facilities. The increase in the average cost per KWH purchased was due to a higher marginal cost of fuel.

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

Purchased Power – Affiliates

In the first quarter 2012, purchased power expense from affiliates was $8.9 million compared to $8.3 million for the corresponding period in 2011. The increase was primarily due to a 40.3% increase in KWH volume purchased, partially offset by a 24.4% decrease in the average cost of purchased power per KWH.

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

99

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(15.5)	(22.0)

In the first quarter 2012, other operations and maintenance expenses were $54.9 million compared to $70.4 million for the corresponding period in 2011. The decrease was primarily due to a $10.8 million decrease in rent expense and expenses under a long-term service agreement resulting from the expiration of an operating lease for Plant Daniel Units 3 and 4 in October 2011 and a $6.5 million decrease in generation expenses primarily related to scheduled outages. These decreases were partially offset by a $1.3 million increase in administrative and general expenses. See Note 1 to the financial statements of Mississippi Power under “Purchase of the Plant Daniel Combined Cycle Generating Units” in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$2.6	13.2

In the first quarter 2012, depreciation and amortization was $22.5 million compared to $19.9 million for the corresponding period in 2011. The increase was primarily due to a $3.3 million increase in depreciation on additional plant in service and a $1.9 million increase in amortization resulting from the plant acquisition adjustment related to the purchase of Plant Daniel Units 3 and 4. These increases were partially offset by a $2.6 million decrease in amortization primarily resulting from a regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4.

See Note 1 to the financial statements of Mississippi Power under “Purchase of the Plant Daniel Combined Cycle Generating Units” and “Depreciation and Amortization” in Item 8 of the Form 10-K for additional information.

Taxes Other Than Income Taxes

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$4.2	24.2

In the first quarter 2012, taxes other than income taxes were $21.7 million compared to $17.5 million for the corresponding period in 2011. The increase was primarily due to a $4.0 million increase in ad valorem taxes and a $0.2 million increase in franchise taxes.

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

Allowance for Equity Funds Used During Construction

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$8.7	N/M

N/M — Not meaningful

In the first quarter 2012, AFUDC equity was $11.8 million compared to $3.1 million for the corresponding period in 2011. The increase was primarily due to the construction of the Kemper IGCC.

100

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.

Interest Expense, Net of Amounts Capitalized

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$1.8	29.8

In the first quarter 2012, interest expense, net of amounts capitalized was $7.8 million compared to $6.0 million for the corresponding period in 2011. The increase was primarily due to an $8.6 million increase in interest expense associated with the issuances of new long-term debt in April 2011, September 2011, October 2011, and March 2012 and a $1.1 million increase in interest expense resulting from the receipt of a $150 million interest-bearing refundable deposit from SMEPA in March 2012 related to its pending purchase of a 17.5% undivided interest in the Kemper IGCC. The increase was partially offset by a $5.6 million increase in capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC and a $1.9 million decrease in interest expense resulting from the amortization of the fair value adjustment on the assumed debt related to the purchase of Plant Daniel Units 3 and 4 in October 2011.

See Note 1 to the financial statements of Mississippi Power under “Purchase of the Plant Daniel Combined Cycle Generating Units” in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL — “Integrated Coal Gasification Combined Cycle” herein for additional information.

Income Taxes

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$1.2	17.7

In the first quarter 2012, income taxes were $8.4 million compared to $7.2 million for the corresponding period in 2011. The increase was primarily due to a $4.7 million increase resulting from higher pre-tax earnings and a $0.3 million increase due to lower State of Mississippi manufacturing investment tax credits, partially offset by a $3.4 million decrease due to higher AFUDC equity, which is non-taxable, and a $0.3 million decrease in unrecognized tax benefits.

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 territory. Changes in economic conditions impact 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.

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

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

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. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to a unit co-owned by Mississippi Power). At the same time, the EPA asked the U.S. Court of Appeals for the Eleventh Circuit to stay its appeal of the judgment in favor of Alabama Power. Alabama Power filed oppositions to the EPA’s motion and its request for a stay. On March 29, 2012, the U.S. Court of Appeals for the Eleventh Circuit denied the EPA’s request to stay its appeal. The U.S. District Court for the Northern District of Alabama has not ruled on the EPA’s motion seeking vacatur of the judgment. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

General

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — General” of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s estimated base level capital expenditures to comply with existing statutes and regulations for 2012 through 2014, as well as Mississippi Power’s preliminary estimates for potential incremental environmental compliance investments associated with complying with the EPA’s final Mercury and Air Toxics Standards (MATS) rule (formerly referred to as the Utility Maximum Achievable Control Technology rule) and the EPA’s proposed water and coal combustion byproducts rules. Mississippi Power is continuing to develop its compliance strategy and to assess the potential costs of complying with the MATS rule and the EPA’s proposed water and coal combustion byproducts rules.

Mississippi Power’s compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures are dependent on a final assessment of the MATS rule and will be affected by the final requirements of new or revised environmental regulations that are promulgated, including any proposed environmental regulations; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and Mississippi Power’s fuel mix. These costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, 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 the MATS rule could significantly affect electric system reliability and cause an increase in costs of materials and services. The ultimate outcome of these matters cannot be determined at this time.

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MISSISSIPPI POWER COMPANY

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 Mississippi Power in Item 7 of the Form 10-K for additional information on the eight-hour ozone air quality standards and the MATS rule.

On May 1, 2012, the EPA released its final determination of nonattainment areas based on the 2008 eight-hour ozone air quality standards. None of the areas within Mississippi Power’s service territory were designated as nonattainment areas.

Numerous petitions for administrative reconsideration of the MATS rule, including a petition by Southern Company and its subsidiaries, including Mississippi Power, have been filed with the EPA. Challenges to the final rule have also been filed in the U.S. District Court of Appeals for the District of Columbia by numerous states, environmental organizations, industry groups, and others. The impact of the MATS rule will depend on the outcome of these and any other legal challenges and, therefore, cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts” of Mississippi Power in Item 7 of the Form 10-K for additional information. On April 5, 2012, 10 environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia seeking to require the EPA to complete its rulemaking process and issue final regulations pertaining to the regulation of coal combustion byproducts as soon as possible. Other parties are expected to file similar challenges. The ultimate outcome of this matter cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Global Climate Issues” of Mississippi Power in Item 7 of the Form 10-K for additional information. On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.

FERC Matters

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC Matters” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information.

On January 20, 2012, Mississippi Power reached a settlement agreement with its wholesale customers, which was executed by all parties on March 9, 2012. The settlement agreement provides that base rates under the cost-based electric tariff will increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. In 2012, the amount of base rate revenues to be received from the agreed upon increase will be approximately $17.0 million. On March 12, 2012, Mississippi Power filed an unopposed motion to place wholesale Municipal and Rural Associations (MRA) interim rates into effect pending approval of the settlement agreement between the parties by the FERC. On March 28, 2012, the FERC approved the motion to place interim rates into effect beginning in May 2012. Approval of the settlement agreement by the FERC has been delayed until later in the year.

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

103

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

PSC Matters

Performance Evaluation Plan

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

On April 2, 2012, Mississippi Power filed a motion to suspend the 2011 PEP lookback filing. Unresolved matters related to certain costs included in the 2010 PEP lookback filing also impact the 2011 PEP lookback filing, making it impractical to determine Mississippi Power’s actual retail return on investment for 2011 for purposes of the 2011 PEP lookback filing. The ultimate outcome of these matters cannot be determined at this time.

Environmental Compliance Overview Plan

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

On April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power’s portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power’s portion of the cost is expected to be recovered through the ECO Plan. As of March 31, 2012, total project expenditures were $55.6 million, with Mississippi Power’s portion being $27.8 million.

On February 14, 2012, Mississippi Power submitted its 2012 ECO Plan notice, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct scrubbers on Plant Daniel Units 1 and 2, Mississippi Power will revise the 2012 ECO Plan notice excluding scrubber expenditures from rate base, which is expected to result in little or no rate change.

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

Fuel Cost Recovery

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

At March 31, 2012, the amount of over recovered retail fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $50.9 million compared to $42.4 million at December 31, 2011. Mississippi Power also has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At March 31, 2012, the amount of over recovered

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MISSISSIPPI POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

wholesale MRA and MB fuel costs included in Mississippi Power’s Condensed Balance Sheets was $18.1 million and $2.4 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at March 31, 2012 and December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Power’s Condensed Balance Sheets herein was $1.7 million. 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.

Integrated Coal Gasification Combined Cycle

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

In May 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the Mississippi PSC order confirming Mississippi Power’s application for a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. In June 2010, the Mississippi PSC issued the CPCN (2010 MPSC Order).

In June 2010, the Sierra Club filed an appeal of the Mississippi PSC’s June 2010 decision to grant the CPCN 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 2010 MPSC Order and, on March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court. On March 15, 2012, the Mississippi Supreme Court reversed the Chancery Court’s decision and the 2010 MPSC Order and remanded the matter to the Mississippi PSC to correct the 2010 MPSC Order. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN.

On March 30, 2012, the Mississippi PSC issued temporary authorization for the continuation of construction of the Kemper IGCC until the earlier of the conclusion of the Mississippi PSC’s May 2012 open meeting or immediately upon the issuance of any final order issued by the Mississippi PSC on remand that conclusively addresses the mandate. On April 24, 2012, the Mississippi PSC issued a detailed order on remand (2012 MPSC Order) confirming the CPCN for the Kemper IGCC subject to the same conditions set forth in the 2010 MPSC Order. On April 26, 2012, the Sierra Club filed a motion for stay and a notice of appeal of the 2012 MPSC Order with the Chancery Court. On May 2, 2012, Mississippi Power filed a petition to join the appeal.

The certificated cost estimate of the Kemper IGCC is $2.4 billion, net of $245.3 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2) and excluding the cost of the lignite mine and equipment and the carbon dioxide (CO₂) pipeline facilities. The 2012 MPSC Order, like the 2010 MPSC Order, (1) approved a construction cost cap of up to $2.88 billion (exemptions from the cost cap include the cost of the lignite mine and equipment and the CO₂ pipeline facilities), (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal, and (3) approved financing cost recovery on CWIP balances not to exceed the certificated cost estimate, which provided for the accrual of AFUDC in 2010 and 2011 and provides for the current recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014, (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). As of March 31, 2012, Mississippi Power had utilized substantially all of its contingency contained in the certificated cost estimate. Mississippi Power anticipates that the costs to complete construction of the portion of the Kemper IGCC subject to the construction cost cap will be less than the cost cap but will likely exceed the certificated cost estimate.

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. Of the total costs incurred through March 2009, $46 million has been reviewed and approved by the Mississippi PSC. A decision regarding the remaining $5 million has been deferred to a later date. The timing of the review of the remaining Kemper IGCC costs has not been determined.

The Kemper IGCC plant, expected to begin commercial operation in May 2014, will use locally mined lignite (an abundant, lower heating value coal) from a mine adjacent to the plant as fuel. The mine is scheduled to be placed into service in June 2013. In conjunction with the Kemper IGCC, Mississippi Power will own the 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 million, of which $79.7 million has been incurred through March 31, 2012. The asset retirement obligation associated with the reclamation and restoration of the mine currently under construction was immaterial at March 31, 2012. In May 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage the mining operations. The contract with Liberty Fuels is effective June 2010 through the end of the mine reclamation. On December 13, 2011, the Mississippi Department of Environmental Quality (MDEQ) approved the surface coal mining and the water pollution control permits for the mining operations operated by Liberty Fuels. On January 12, 2012, two individuals each filed a notice of appeal and a request for evidentiary hearing with the MDEQ regarding the surface coal mining and water pollution control permits. On March 8, 2012, the MDEQ permit board affirmed its issuance of the surface coal mining and water pollution control permits.

In 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 credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the recapture rules for Section 48A investment tax credits. Through March 31, 2012, Mississippi Power received or accrued tax benefits totaling $141.1 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. As a result of 100% bonus tax depreciation on certain assets placed, or to be placed, in service in 2011 and 2012, and the subsequent reduction in federal taxable income, Mississippi Power estimates that it will not be able to utilize $105.0 million of these tax credits until after 2012. IRS guidelines allow the resulting unused credits to be carried forward for 20 years.

In July 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In December 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval of SMEPA’s 17.5% undivided interest in the Kemper IGCC. On February 28, 2012, the Mississippi PSC approved the joint petition for the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power’s senior unsecured credit rating falls below a BBB+ and/or Baa1. Given the interest-bearing nature of the deposit and SMEPA’s ability to request a refund, the deposit has been presented as a current liability in Mississippi Power’s Condensed Balance Sheet herein and as financing proceeds in the statement of cash flows.

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As of March 31, 2012, Mississippi Power had spent a total of $1.30 billion on the Kemper IGCC including the cost of the lignite mine and equipment, the CO₂ pipeline facilities, and regulatory filing costs. Of this total, $1.28 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $22.9 million was recorded in other regulatory assets, $2.3 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Certificated New Plant” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Certificated New Plant” in Item 8 of the Form 10-K for information on the proposed rate schedules related to the Kemper IGCC.

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

Income Tax Matters

Bonus Depreciation

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). Due to the significant amount of estimated bonus depreciation for 2012 for Southern Company, a portion of Mississippi Power’s tax credit utilization will be deferred, thus eliminating the positive cash flow benefit for Mississippi Power.

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Integrated Coal Gasification Combined Cycle” herein for additional information.

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury 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 a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Overview” of Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Power’s financial condition remained stable at March 31, 2012. 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,” “Financing Activities,” and “Capital Requirements and Contractual Obligations” herein for additional information.

Net cash provided from operating activities totaled $0.6 million for the first three months of 2012 compared to $66.4 million for the corresponding period in 2011. The $65.8 million decrease in cash provided from operating activities is primarily due to a $16.0 million decrease in hedge settlements related to the settlement of interest rate swaps, a $15.7 million increase in fuel inventory, and a decrease in accounts payable of $29.1 million primarily due to timing of cash payments.

Net cash used for investing activities totaled $344.4 million for the first three months of 2012 compared to $52.4 million for the corresponding period in 2011. The $292.0 million increase in net cash used for investing activities is primarily due to an increase in property additions of $222.0 million primarily related to the Kemper IGCC, a $50.0 million decrease in restricted cash, and a $15.1 million decrease in capital grant proceeds related to CCPI2 and smart grid investment grants.

Net cash provided from financing activities totaled $598.9 million for the first three months of 2012 compared to net cash used for financing activities of $99.4 million for the corresponding period in 2011. The $698.3 million increase in net cash provided from financing activities was primarily due to a $100.1 million increase in capital contributions from Southern Company, the issuance of $400.0 million of senior notes in March 2012, the receipt of a $150.0 million interest-bearing refundable deposit related to a pending asset sale, and a $55.0 million decrease in redemptions of long-term debt in the first quarter 2012 compared to the corresponding period in 2011.

Significant balance sheet changes for the first three months of 2012 include an increase in cash and cash equivalents of $255.2 million primarily due to the issuance of $400.0 million of senior notes and the receipt of a $150.0 million interest-bearing refundable deposit from SMEPA to be applied towards its pending purchase of a 17.5% undivided interest in the Kemper IGCC. Total property, plant, and equipment increased $361.9 million primarily due to the increase in CWIP related to the Kemper IGCC. Interest-bearing refundable deposit related to an asset sale increased $150.0 million due to the receipt of the $150.0 million interest-bearing refundable deposit from SMEPA. Long-term debt

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

increased $309.1 million primarily due to the issuance of $400.0 million of senior notes. Paid-in capital increased $152.2 million due to a $150.0 million capital contribution from Southern Company.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Mississippi Power in Item 7 of the Form 10-K 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 $255 million will be required through March 31, 2013 to fund maturities and announced redemptions of long-term debt.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet 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.

Sources of Capital

Except as described below with respect to potential DOE loan guarantees, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily funds from operating cash flows, security issuances, term loans, short-term borrowings, 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. On February 27, 2012, Mississippi Power received a $150 million capital contribution from Southern Company. On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA towards its pending purchase of a 17.5% undivided interest in the Kemper IGCC. Until the acquisition is closed, Mississippi Power has agreed to pay interest on the deposit at its AFUDC rate, which was 10.196% at March 31, 2012. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power’s senior unsecured credit rating falls below a BBB+ and/or Baa1. 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. Mississippi Power has received $245.3 million in DOE CCPI2 grant funds that were used for the construction of the Kemper IGCC. An additional $25 million in CCPI2 grant funds is expected to be received for the initial operation of the Kemper IGCC. Investment tax credits related to the Kemper IGCC of $105.0 million are not expected to be utilized until after 2012, which could result in additional financing needs.

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.

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At March 31, 2012, Mississippi Power had approximately $466.7 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2012 were as follows:

Expires					Executable Term Loans		Due Within One Year(a)
2012	2013	2014   and   Beyond	Total	Unused	One     Year	Two     Year	Term     Out	No Term Out
(in millions)			(in millions)		(in millions)		(in millions)
$106	$25	$165	$296	$296	$25	$41	$66	$65

(a) Reflects facilities expiring on or before March 31, 2013.

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.

Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of Mississippi Power. Mississippi Power is currently in compliance with all such covenants. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Mississippi Power’s commercial paper borrowings and variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2012 was approximately $40 million.

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

Mississippi Power had no commercial paper or short-term debt outstanding during the three months ended March 31, 2012.

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

Credit Rating Risk

Mississippi Power does not have any credit arrangements with banks 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 March 31, 2012, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $329 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Mississippi Power also has entered into an asset purchase agreement with SMEPA for the pending purchase of a 17.5% undivided interest in the Kemper IGCC that could require a refund of the deposit within 15 days at SMEPA’s discretion in the event that Mississippi Power’s senior unsecured credit rating falls below a BBB+ and/or Baa1. Additionally, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Market Price Risk

Mississippi Power’s market risk exposure relative to interest rate changes for the first quarter 2012 has not changed materially compared with the December 31, 2011 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. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts or heat-rate contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power had no material change in market risk exposure for the first quarter 2012 when compared with the December 31, 2011 reporting period.

The changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, for the three months ended March 31, 2012 were as follows:

	First Quarter 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$(51)
Contracts realized or settled	10
Current period changes(a)	(15)
Contracts outstanding at the end of the period, assets (liabilities), net	$(56)

(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 months ended March 31, 2012 was a decrease of $5 million, of which $3 million related to natural gas swaps and $2 million related to natural gas options. The change is attributable to both the volume of mmBtu and the price of natural gas. At March 31, 2012, Mississippi Power had a net hedge volume of 28 million mmBtu, which consisted of 21 million mmBtu of swaps and 7 million mmBtu of options. The weighted average swap contract cost was approximately $2.13 per mmBtu above market prices. At December 31, 2011, Mississippi Power had a net hedge volume of 31 million mmBtu, which consisted of 22 million mmBtu of swaps and 9 million mmBtu of options. The weighted average swap contract cost was approximately $1.98 per mmBtu above market prices. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majority of the costs associated with natural gas hedges are recovered through Mississippi Power’s energy cost management clause (ECM).

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 Mississippi Power’s ECM.

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2012 were as follows:

	March 31, 2012     Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3	Years 4&5
	(in millions)
Level 1	$ —	$ —	$ —	$—
Level 2	(56)	(40)	(15)	(1)
Level 3	—	—	—	—
Fair value of contracts outstanding at end of period	$(56)	$(40)	$(15)	$(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 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 all relevant 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 March 2012, Mississippi Power issued $250 million aggregate principal amount of Series 2012A 4.25% Senior Notes due March 15, 2042 and an additional $150 million aggregate principal amount of Series 2011A 2.35% Senior Notes due October 15, 2016. The Series 2011A 2.35% Senior Notes due October 15, 2016 were of the same series of notes that were originally issued in October 2011 in the aggregate principal amount of $150 million. Upon completion of this offering, the aggregate principal amount of the outstanding Series 2011A 2.35% Senior Notes was $300 million. The proceeds from the sale of the Series 2012A Senior Notes and the Series 2011A Senior Notes were used to repay a bank loan in an aggregate principal amount of $75 million, and for general corporate purposes, including Mississippi Power’s continuous construction program.

In March 2012, $300 million in interest rate swaps were settled; $250 million related to its Series 2012A 4.25% Senior Notes at a loss of approximately $13.3 million, which will be amortized to interest expense, in earnings, over 10 years, and $50 million related to its Series 2011A 2.35% Senior Notes at a loss of approximately $2.7 million, which will be amortized to interest expense, in earnings, over 10 years.

On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of a 17.5% undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power’s AFUDC rate and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power’s senior unsecured credit rating falls below a BBB+ and/or Baa1.

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MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to March 31, 2012, Mississippi Power announced the redemption of $90 million aggregate principal amount of Series E 5-5/8% Senior Notes due May 1, 2033 that will occur on May 15, 2012.

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

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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates		$140,557			$197,166
Wholesale revenues, affiliates		111,788			83,274
Other revenues		1,336			1,347
Total operating revenues		253,681			281,787
Operating Expenses:
Fuel		89,078			102,715
Purchased power, non-affiliates		20,650			8,942
Purchased power, affiliates		2,340			15,099
Other operations and maintenance		48,389			42,754
Depreciation and amortization		31,913			30,167
Taxes other than income taxes		4,968			4,763
Total operating expenses		197,338			204,440
Operating Income		56,343			77,347
Other Income and (Expense):
Interest expense, net of amounts capitalized		(13,642	)		(18,829	)
Other income (expense), net		30			59
Total other income and (expense)		(13,612	)		(18,770	)
Earnings Before Income Taxes		42,731			58,577
Income taxes		13,415			20,834
Net Income		$  29,316			$  37,743

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in thousands)
Net Income	$	29,316		$	37,743
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(173) and $423, respectively		(274	)		643
Reclassification adjustment for amounts included in net income, net of tax of $956 and $1,071, respectively		1,510			1,630
Total other comprehensive income (loss)		1,236			2,273
Comprehensive Income	$	30,552		$	40,016

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2012			2011
	(in thousands)
Operating Activities:
Net income	$	29,316		$	37,743
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		34,887			33,580
Deferred income taxes		9,917			8,601
Convertible investment tax credits		(3,900	)		38,068
Deferred revenues		(16,686	)		(21,476	)
Mark-to-market adjustments		6,467			(63	)
Other, net		1,326			1,752
Changes in certain current assets and liabilities —
-Receivables		12,400			20,759
-Fossil fuel stock		(755	)		625
-Materials and supplies		(1,167	)		253
-Prepaid income taxes		(5,105	)		15,744
-Other current assets		(2,083	)		(137	)
-Accounts payable		(14,590	)		(21,645	)
-Accrued taxes		4,375			4,888
-Accrued interest		(10,172	)		(12,281	)
-Other current liabilities		(2	)		(519	)
Net cash provided from operating activities		44,228			105,892
Investing Activities:
Property additions		(32,450	)		(113,518	)
Change in construction payables		(999	)		43,259
Payments pursuant to long-term service agreements		(11,415	)		(11,320	)
Other investing activities		(2,848	)		(3,165	)
Net cash used for investing activities		(47,712	)		(84,744	)
Financing Activities:
Increase (decrease) in notes payable, net		20,165			(20,360	)
Proceeds — Capital contributions		1,219			17,179
Repayments — Other long-term debt		(150	)		(3,066	)
Payment of common stock dividends		(31,750	)		(22,800	)
Other financing activities		25			38
Net cash used for financing activities		(10,491	)		(29,009	)
Net Change in Cash and Cash Equivalents		(13,975	)		(7,861	)
Cash and Cash Equivalents at Beginning of Period		16,943			14,204
Cash and Cash Equivalents at End of Period	$	2,968		$	6,343
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $6,556 and $4,240 capitalized for 2012 and 2011, respectively)	$	20,966		$	26,993
Income taxes (net of refunds)		10,820			(44,721	)
Noncash transactions — accrued property additions at end of period		31,591			78,567

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2012		At December 31, 2011
	(in thousands)
Current Assets:
Cash and cash equivalents	$	2,968	$	16,943
Receivables —
Customer accounts receivable		58,192		59,360
Other accounts receivable		1,779		2,122
Affiliated companies		25,609		36,508
Fossil fuel stock, at average cost		13,793		13,038
Materials and supplies, at average cost		38,769		37,603
Prepaid service agreements — current		27,234		28,621
Prepaid income taxes		19,050		5,192
Other prepaid expenses		6,095		4,645
Assets from risk management activities		89		177
Total current assets		193,578		204,209
Property, Plant, and Equipment:
In service		3,158,331		3,167,840
Less accumulated provision for depreciation		680,297		652,087
Plant in service, net of depreciation		2,478,034		2,515,753
Construction work in progress		737,751		666,280
Total property, plant, and equipment		3,215,785		3,182,033
Other Property and Investments:
Goodwill		1,839		1,839
Other intangible assets, net of amortization of $1,671 and $1,476 at March 31, 2012 and December 31, 2011, respectively		47,448		47,644
Total other property and investments		49,287		49,483
Deferred Charges and Other Assets:
Prepaid long-term service agreements		104,959		115,838
Other deferred charges and assets — affiliated		2,969		3,029
Other deferred charges and assets — non-affiliated		29,451		26,385
Total deferred charges and other assets		137,379		145,252
Total Assets	$	3,596,029	$	3,580,977

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At March 31, 2012			At December 31, 2011
	(in thousands)
Current Liabilities:
Securities due within one year	$	550		$	555
Notes payable — non-affiliated		199,685			179,520
Accounts payable —
Affiliated		42,838			63,609
Other		49,762			44,321
Accrued taxes —
Accrued income taxes		1,260			2,548
Other accrued taxes		5,812			2,158
Accrued interest		11,702			21,874
Liabilities from risk management activities		16,447			9,651
Other current liabilities		17,470			7,401
Total current liabilities		345,526			331,637
Long-term Debt		1,302,620			1,302,758
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		333,698			319,790
Deferred convertible investment tax credits		128,411			125,065
Deferred capacity revenues — affiliated		4,658			20,637
Other deferred credits and liabilities — affiliated		3,359			3,618
Other deferred credits and liabilities — non-affiliated		5,130			4,965
Total deferred credits and other liabilities		475,256			474,075
Total Liabilities		2,123,402			2,108,470
Redeemable Noncontrolling Interest		3,923			3,825
Common Stockholder’s Equity:
Common stock, par value $.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		1,029,430			1,028,210
Retained earnings		444,867			447,301
Accumulated other comprehensive loss		(5,593	)		(6,829	)
Total common stockholder’s equity		1,468,704			1,468,682
Total Liabilities and Stockholder’s Equity	$	3,596,029		$	3,580,977

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2012 vs. FIRST QUARTER 2011

OVERVIEW

Southern Power and its wholly-owned subsidiaries construct, acquire, own, and manage generation assets, including renewable energy projects, 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 primarily with investor owned utilities, independent power producers, municipalities, and electric cooperatives.

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

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(8.4)	(22.3)

Southern Power’s net income for the first quarter 2012 was $29.3 million compared to $37.7 million for the corresponding period in 2011. The decrease was primarily due to a decrease in energy revenues from existing PPAs, a decrease in capacity revenues due to a reduction in total MWs of capacity under long-term contracts, and an increase in other operations and maintenance expenses. The decrease was partially offset by an increase in energy revenues from sales to affiliates under the IIC, lower fuel expenses, lower interest expenses, and lower income taxes.

Wholesale Revenues — Non-Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(56.6)	(28.7)

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 first quarter 2012 were $140.6 million compared to $197.2 million for the corresponding period in 2011. The decrease was primarily due to a $60.5 million decrease in energy sales, reflecting a 12.3% decrease in KWH sales and a 43.3% decrease in the average price of energy. The decrease in revenue from energy sales was partially offset by a $3.9 million increase in capacity revenue due to an increase in the total MWs of capacity under contract with non-affiliates.

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.

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Wholesale Revenues — Affiliates

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$28.5	34.2

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.

Wholesale revenues from affiliates for the first quarter 2012 were $111.8 million compared to $83.3 million for the corresponding period in 2011. The increase was primarily the result of a $41.8 million increase in energy sales under the IIC, reflecting a 314.1% increase in KWH sales, partially offset by a 43.3% reduction in the average price of energy. The increase in revenue from energy sales was partially offset by an $11.9 million decrease in capacity revenue due to a decrease in total MWs of capacity under contract with affiliates.

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

First Quarter 2012 vs. First Quarter 2011
	(change in millions)		(% change)
Fuel		$(13.6)		(13.3)
Purchased power — non-affiliates		11.7		130.9
Purchased power — affiliates		(12.7)		(84.5)
Total fuel and purchased power expenses		$(14.6)

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.

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

In the first quarter 2012, total fuel and purchased power expenses were $112.1 million compared to $126.8 million for the corresponding period in 2011. Fuel and purchased power expenses decreased $64.0 million due to a 38.8% decrease in the average cost of fuel and a 26.0% decrease in the average cost of purchased power. The decrease was partially offset by a $49.4 million increase associated with a 39.4% increase in volume of KWHs generated and purchased.

In the first quarter 2012, fuel expense was $89.1 million compared to $102.7 million for the corresponding period in 2011. Fuel expense decreased $56.0 million associated with a 38.8% decrease in the average cost of fuel. The decrease was partially offset by a $42.4 million increase associated with a 41.3% increase in the volume of KWHs generated.

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In the first quarter 2012, purchased power expense was $23.0 million compared to $24.0 million for the corresponding period in 2011. Purchased power expenses decreased $8.0 million due to a 26.0% decrease in the average cost of purchased power, partially offset by a $7.0 million increase associated with a 29.2% increase in the volume of KWHs purchased.

Other Operations and Maintenance Expenses

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$5.7	13.2

In the first quarter 2012, other operations and maintenance expenses were $48.4 million compared to $42.7 million for the corresponding period in 2011. The increase was primarily due to a $3.4 million increase in administrative and general expenses primarily due to increases in business development expenses and affiliate service company expense allocated based on load and fuel burn and a $1.8 million increase related to a scheduled outage at Plant Rowan.

Interest Expense, Net of Amounts Capitalized

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(5.2)	(27.5)

In the first quarter 2012, interest expense, net of amounts capitalized was $13.6 million compared to $18.8 million for the corresponding period in 2011. The decrease was primarily due to a $2.2 million expense reduction associated with the refinancing of $575 million in long-term debt in 2011 and a $2.3 million increase in capitalized interest associated with the construction of the Cleveland County combustion turbine generating plant and the Nacogdoches biomass plant. See FUTURE EARNINGS POTENTIAL — “Construction Projects” herein for additional information.

Income Taxes

First Quarter 2012 vs. First Quarter 2011
(change in millions)	(% change)
$(7.4)	(35.6)

In the first quarter 2012, income taxes were $13.4 million compared to $20.8 million for the corresponding period in 2011. The decrease was primarily due to lower pre-tax earnings.

FUTURE EARNINGS POTENTIAL

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

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

Climate Change Litigation

Hurricane Katrina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL — “Environmental Matters — Climate Change Litigation — Hurricane Katrina Case” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Climate Change Litigation — Hurricane Katrina Case” in Item 8 of the Form 10-K for additional information. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the amended class action complaint filed on May 27, 2011 by the plaintiffs. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. The ultimate outcome of this matter cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Global Climate Issues” of Southern Power in Item 7 of the Form 10-K for additional information. On April 13, 2012, the EPA published proposed regulations to establish standards of performance for greenhouse gas emissions from new fossil fuel steam electric generating units. As proposed, the standards would not apply to existing units. The EPA has delayed its plans to propose greenhouse gas emissions performance standards for modified sources and emissions guidelines for existing sources. The impact of this rulemaking will depend on the scope and specific requirements of the final rule and the outcome of any legal challenges and, therefore, cannot be determined at this time.

Income Tax Matters

Bonus Depreciation

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 Power through 2013. Consequently, Southern Power’s positive cash flow benefit is estimated to be between $140 million and $185 million in 2012.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Construction Projects

Cleveland County Units 1-4

In 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 December 2012. Construction costs incurred through March 31, 2012 were $277.4 million. The total estimated cost of the project is expected to be between $335 million and $365 million.

Nacogdoches Biomass Plant

In 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 June 2012. Construction costs incurred through March 31, 2012 were $406.4 million. The total estimated cost of the project is expected to be between $470 million and $490 million.

Power Sales Agreements

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

In June 2011, Southern Power entered into three PPAs with Georgia Power subject to Georgia PSC and FERC approval. These PPAs were approved by the Georgia PSC on March 20, 2012 and are still subject to approval by the FERC. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally 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.

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

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power’s financial condition remained stable at March 31, 2012. 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 $44.2 million for the first three months of 2012 compared to $105.9 million for the corresponding period in 2011. This decrease was mainly due to the effect of cash received in 2011 for convertible ITCs. Net cash used for investing activities totaled $47.7 million for the first three months of 2012 compared to $84.7 million for the corresponding period in 2011. This decrease was primarily due to a decrease in CWIP expenditures related to construction activities at Cleveland County and Nacogdoches. Net cash used for financing activities totaled $10.5 million for the first three months of 2012 compared to $29.0 million for the corresponding period in 2011. This decrease was primarily due to a net repayment of notes payable in 2011 compared to an increase in notes payable in 2012, partially offset by a decrease in capital contributions from Southern Company and an increase in dividends paid.

Significant asset changes in the balance sheet for the first quarter 2012 include: a $14.0 million decrease in cash and cash equivalents; a $10.9 million decrease in accounts receivables from affiliated companies primarily due to a decrease in the amount due for energy sales under the IIC; a $13.9 million increase in prepaid income taxes; a $71.5 million increase in CWIP due to Cleveland County and Nacogdoches construction activities and capital equipment replacements during outages in progress; and a $12.3 million decrease in prepaid long-term service agreements due to costs incurred related to scheduled plant maintenance.

Significant liability and stockholder’s equity changes in the balance sheet for the first quarter 2012 include: a $20.2 million increase in notes payable non-affiliated primarily due to the timing of operating cash flows; a $20.8 million decrease in accounts payable — affiliated primarily due to timing of payments to service company affiliates; a $10.2 million decrease in accrued interest due to scheduled debt service; and a $16.0 million decrease in deferred capacity revenues — affiliated due to seasonality.

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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. There are no requirements through March 31, 2013 to fund maturities of long-term debt.

The construction program is subject to periodic review and revision; these amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements and work to be performed under long-term service agreements. Planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

Sources of Capital

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

Southern Power’s current liabilities frequently exceed current assets due to the use of short-term debt as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at March 31, 2012 cash and cash equivalents of approximately $3.0 million and a committed credit facility of $500 million (Facility) expiring in 2016. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power is currently in compliance with all such covenants. Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power’s commercial paper program. See Note 6 to the financial statements of Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at  the End of the Period		Short-term Debt During the Period (a)
	Amount Outstanding	Weighted     Average Interest Rate	Average     Outstanding	Weighted Average Interest Rate	Maximum Amount     Outstanding
	(in millions)		(in millions)		(in millions)
March 31, 2012:
Commercial paper	$200	0.5%	$193	0.4%	$226

(a) Average and maximum amounts are based upon daily balances during the period.

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

The maximum potential collateral requirements under these contracts at March 31, 2012 were as follows:

Credit Ratings	Maximum Potential         Collateral Requirements
	(in millions)
At BBB and Baa2	$       9
At BBB- and/or Baa3	454
Below BBB- and/or Baa3	1,218

Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Power’s ability to access capital markets, particularly the short-term debt market.

In addition, through the acquisition of Plant Rowan, Southern Power assumed a PPA with North Carolina Municipal Power Agency No. 1 that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power’s credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 first quarter 2012 has not changed materially compared with the December 31, 2011 reporting period. Since a significant portion of outstanding indebtedness bears interest at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

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

The changes in fair value of energy-related derivative contracts for the three months ended March 31, 2012 were as follows:

	First Quarter       2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(9.2)
Contracts realized or settled		0.8
Current period changes(a)		(7.7)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(16.1)

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

The decrease in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2012 was $6.9 million, which is due to both power and natural gas positions. This change is attributable to both the volume and prices of power and natural gas as follows:

	March 31, 2012			December 31, 2011
Power — net purchased or (sold)
MWHs (in millions)		(0.1	)		0.1
Weighted average contract cost per MWH above (below) market prices (in dollars)		$(5.20	)		$(1.04	)
Natural gas net purchased
Commodity — million mmBtu		28.2			8.3
Commodity — weighted average contract cost per mmBtu above (below) market prices (in dollars)		$1.57			$1.18

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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	March 31,   2012		December 31,   2011
	(in millions)
Cash flow hedges		$  (1.2)		$(0.8)
Not designated		(14.9)		(8.4)
Total fair value		$(16.1)		$(9.2)

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 months ended March 31, 2012 for energy-related derivative contracts that were not hedges were $(6.5) million and will continue to be marked to market until the settlement date. Included in this amount are gains (losses) on derivative contracts reimbursable by third parties in the amount of $(5.2) million. For the three months ended March 31, 2011, the total net unrealized pre-tax gains (losses) recognized in the statements of income for energy-related derivative contracts that were not hedges were not material.

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 March 31, 2012 were as follows:

	March 31, 2012 Fair Value Measurements
	Total		Maturity
	Fair Value		Year 1		Years 2&3		Years 4&5
	(in millions)
Level 1	$	—	$	—	$	—	$	—
Level 2		(16.1)		(16.3)		(0.2)		0.4
Level 3		—		—		—		—
Fair value of contracts outstanding at end of period	$	(16.1)	$	(16.3)	$	(0.2)	$	0.4

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 all relevant 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

For the three months ended March 31, 2012, Southern Power did not issue or redeem any long-term securities.

During the three months ended March 31, 2012, Southern Power prepaid $0.2 million of long-term debt.

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.

129

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(A) INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2011 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 March 31, 2012 and 2011. 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.

Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

Investments in Leveraged Leases

See Note 1 to the financial statements of Southern Company under “Leveraged Leases” in Item 8 of the Form 10-K for additional information.

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 assets. Southern Company is currently engaged in discussions with the lessee and the holders of the project’s nonrecourse debt to restructure the debt payments and the related rental payments to allow additional capital investment in the project to be made to improve the operation of the generation assets and the financial viability of the lease transaction. Southern Company continues to monitor the performance of the underlying assets and to evaluate the ability of the lessee to continue to make the required lease payments. If the attempts at restructuring the project are unsuccessful and the project is ultimately abandoned, the potential impairment loss that would be incurred is approximately $90 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.

(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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury 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 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 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. The EPA alleged NSR violations at five coal-fired generating facilities operated by Alabama Power, including a unit co-owned by Mississippi Power, and three coal-fired generating facilities operated by Georgia Power, including a unit co-owned by Gulf Power. The civil action sought penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The case against Georgia Power (including claims related to the unit co-owned by Gulf Power) was administratively closed in 2001 and has not been reopened. After Alabama Power was dismissed from the original action, the EPA filed a separate action in 2001 against Alabama Power (including claims related to the unit co-owned by Mississippi Power) in the U.S. District Court for the Northern District of Alabama.

In 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree, resolving claims relating to the alleged NSR violations at Plant Miller. In September 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims, including one relating to the unit co-owned by Mississippi Power. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power summary judgment on all remaining claims and dismissed the case with prejudice. That judgment is on appeal to the U.S. Court of Appeals for the Eleventh Circuit. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to a unit co-owned by Mississippi Power). At the same time, the EPA asked the U.S. Court of Appeals for the Eleventh Circuit to stay its appeal of the judgment in favor of Alabama Power. Alabama Power filed oppositions to the EPA’s motion and its request for a stay. On March 29, 2012, the U.S. Court of Appeals for the Eleventh Circuit denied the EPA’s request to stay its appeal. The U.S. District Court for the Northern District of Alabama has not ruled on the EPA’s motion seeking vacatur of the judgment.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Climate Change Litigation

Kivalina Case

In 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs allege that the village is being destroyed by erosion allegedly 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 (including Southern Company) 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. In 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case. The plaintiffs appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. Southern Company believes that these claims are without merit. While Southern Company believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether Southern Company will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.

Hurricane Katrina Case

In 2005, immediately following Hurricane Katrina, a lawsuit was filed in the U.S. District Court for the Southern District of Mississippi by Ned Comer on behalf of Mississippi residents seeking recovery for property damage and personal injuries caused by Hurricane Katrina. In 2006, the plaintiffs amended the complaint to include Southern Company and many other electric utilities, oil companies, chemical companies, and coal producers. The plaintiffs allege that the defendants contributed to climate change, which contributed to the intensity of Hurricane Katrina. In 2007, the U.S. District Court for the Southern District of Mississippi dismissed the case. On appeal to the U.S. Court of Appeals for the Fifth Circuit, a three-judge panel reversed the U.S. District Court for the Southern District of Mississippi, holding that the case could proceed, but, on rehearing, the full U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal, resulting in reinstatement of the decision of the U.S. District Court for the Southern District of Mississippi in favor of the defendants. On May 27, 2011, the plaintiffs filed an amended version of their class action complaint, arguing that the earlier dismissal was on procedural grounds and under Mississippi law the plaintiffs have a right to re-file. The amended complaint was also filed against numerous chemical, coal, oil, and utility companies, including Alabama Power, Georgia Power, Gulf Power, and Southern Power. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the plaintiffs’ amended complaint. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. Each Southern Company entity named in the lawsuit believes that these claims are without merit. While each Southern Company entity named in the lawsuit believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether any Southern Company entity named in the lawsuit will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

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

Georgia Power’s environmental remediation liability as of March 31, 2012 was $20 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated.

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In 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.

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. On November 22, 2011, the EPA sent Georgia Power a letter stating that the EPA does not consider Georgia Power to be in compliance with the UAO. The EPA also stated that it is considering enforcement options against Georgia Power and other UAO recipients who are not complying with the UAO.

The EPA may seek to enforce the UAO in court pursuant to its enforcement authority under CERCLA and may seek recovery of its costs in undertaking the UAO work. 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.

In addition to the EPA’s action at the Ward Transformer Superfund site, in 2009, Georgia Power, along with many other parties, was sued by several existing PRPs for cost recovery for a removal action that is currently taking place. Georgia Power and numerous other defendants moved for a dismissal of these lawsuits. The court denied the dismissal of the lawsuits in March 2010 but granted Georgia Power’s motion regarding the dismissal of the claim pertaining to the plaintiffs’ joint and several liability.

The ultimate outcome of the Brunswick CERCLA NPL and Ward Transformer Superfund site matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the regulatory treatment, it is not expected to have a material impact on Southern Company’s or Georgia Power’s financial statements.

Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $60 million as of March 31, 2012. 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 potentially responsible party at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. The feasibility study/presumptive remedy document was originally filed with TCEQ in June 2011 and remains under consideration by the agency. Amounts expensed and accrued related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan.

The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

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Nuclear Fuel Disposal Cost Litigation

Alabama Power and Georgia Power have contracts with the U.S., acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract.

In 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 Southern Company system’s direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004.

In 2008, the government filed an appeal and, 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. On July 12, 2011, the court entered final judgment in favor of Alabama Power and awarded Alabama Power approximately $17 million. In April 2012, the award was credited to cost of service for the benefit of Alabama Power customers.

On April 5, 2012, Georgia Power and the government entered into a stipulation to conclude this litigation, which provided for judgment in favor of Georgia Power and awarded Georgia Power approximately $27 million in damages, based on its ownership interests. On April 5, 2012, the stipulation was approved by the U.S. Court of Federal Claims. The proceeds will be credited to the Georgia Power accounts where the original costs were charged and will be used to reduce rate base, fuel, and cost of service for the benefit of Georgia Power customers.

In 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 March 31, 2012 for the second claim. The final outcome of this matter cannot be determined at this time.

Sufficient pool storage capacity for spent fuel is available at Plant Vogtle Units 1 and 2 to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle Units 1 and 2 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.

FERC Matters

See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s request for revised rates related to the wholesale Municipal and Rural Associations (MRA) cost-based electric tariff. See Note 3 to the financial statements of Southern Company 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.

On January 20, 2012, Mississippi Power reached a settlement agreement with its wholesale customers, which was executed by all parties on March 9, 2012. The settlement agreement provides that base rates under the cost-based electric tariff will increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. In 2012, the amount of base rate revenues to be received from the agreed upon increase will be approximately $17.0 million. On March 12, 2012, Mississippi Power filed an unopposed motion to place wholesale MRA interim rates into effect pending approval of the settlement agreement between the parties by the FERC. On March 28, 2012, the FERC approved the motion to place interim rates into effect beginning in May 2012. Approval of the settlement agreement by the FERC has been delayed until later in the year.

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

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Retail Regulatory Matters

Georgia Power

Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

As of March 31, 2012, Georgia Power had a total over recovered fuel cost balance of approximately $22 million compared to an under recovered balance of $137 million at December 31, 2011. The over recovered fuel costs at March 31, 2012 are included in other deferred credits and liabilities on Southern Company’s and Georgia Power’s Condensed Balance Sheets herein. The under recovered fuel costs at December 31, 2011 are included in current assets on Southern Company’s and Georgia Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Southern Company’s or Georgia Power’s revenues or net income, but will affect cash flow.

On March 30, 2012, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 19%, which is expected to reduce annual billings by $567 million. The decrease in fuel costs is driven primarily by lower natural gas prices as a result of increased natural gas supplies. The Georgia PSC is scheduled to vote on this matter on June 21, 2012. As proposed, the rate decrease would become effective July 1, 2012; however, Georgia Power is currently working with the Georgia PSC to potentially implement the proposed decrease effective June 1, 2012. 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 — 2011 Integrated Resource Plan Update” and “Retail Regulatory Matters — 2011 Integrated Resource Plan Update,” respectively, in Item 8 of the Form 10-K for additional information.

On March 20, 2012, the Georgia PSC approved Georgia Power’s request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Power’s 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.

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.

On February 16, 2012, a group of petitioners who had intervened in the NRC’s combined construction and operating licenses (COLs) proceedings for Plant Vogtle Units 3 and 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the NRC’s issuance of the COLs. In addition, on February 16, 2012, another group of petitioners filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC’s certification of the Westinghouse Design Certification Document, as amended (DCD). On April 3, 2012, the U.S. Court of Appeals for the District of Columbia Circuit granted a motion filed by these two groups of petitioners to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the COLs for Plant Vogtle Units 3 and 4 with the U.S. District Court for the

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District of Columbia. Georgia Power has filed a motion to intervene in these proceedings and intends to vigorously contest these petitions.

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve inclusion of the related CWIP accounts in rate base. Also in 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows Georgia Power to recover financing costs for nuclear construction projects by including the related CWIP accounts in rate base during the construction period. 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. The Georgia PSC has ordered Georgia Power to report against this total certified cost of approximately $6.1 billion. In addition, in December 2010, the Georgia PSC approved Georgia Power’s NCCR tariff. The NCCR tariff became effective January 1, 2011 and adjustments are filed with the Georgia PSC on November 1 of each year to become effective on January 1 of the following year. 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 March 31, 2012, approximately $68 million of these 2009 and 2010 costs remained in CWIP.

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 Westinghouse and Stone & Webster, Inc. (collectively, Consortium) have established both informal and formal dispute resolution procedures in accordance with the engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 MWs each and related facilities, structures, and improvements at Plant Vogtle entered into by the parties (Vogtle 3 and 4 Agreement) in order to resolve issues arising during the course of constructing a project of this magnitude. The Consortium and Georgia Power (on behalf of the Owners) have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

During the course of construction activities, issues have arisen that may impact the project budget and schedule, including costs associated with design changes to the DCD, and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the COLs. The Owners and the Consortium have begun negotiations regarding these issues, including the assertion by the Consortium that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. In preliminary discussions, the Consortium has provided its initial estimate of its proposed adjustment to the contract price. The Consortium’s estimated adjustment attributable to Georgia Power (based on Georgia Power’s ownership interest) is approximately $400 million (in 2008 dollars) with respect to these issues, which include an initial estimate of costs for efforts to maintain the projected in-service dates of 2016 and 2017 for Plant Vogtle Units 3 and 4, respectively. Georgia Power has not agreed with the amount of these proposed adjustments or that the Owners have responsibility for any costs related to these issues. Georgia Power expects negotiations with the Consortium to continue over the next several months during which time the parties will attempt to reach a mutually acceptable compromise of their positions. If a compromise cannot be reached, formal dispute resolution, including litigation, may follow. Georgia Power intends to vigorously defend its positions. If these costs are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. Additional claims by the Consortium or Georgia Power (on behalf of the Owners) are expected to arise throughout the construction of Plant Vogtle Units 3 and 4.

In addition, there are processes in place to assure compliance with the design requirements specified in the DCD and the COLs, including rigorous inspection by Southern Nuclear and the NRC that occurs throughout construction. A recent routine NRC inspection identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. Georgia Power expects to receive official notice of these findings from the NRC. Georgia Power, on behalf of the Owners, is currently engaged in constructive discussions with the Consortium to identify appropriate corrective actions. Various inspection issues are expected as construction proceeds.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including legal challenges to the NRC issuance of the COLs and certification of the DCD. 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

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters — Georgia Power — Other Construction” and “Construction — Other Construction,” respectively, in Item 8 of the Form 10-K for additional information.

Georgia Power placed Plant McDonough Unit 5 into service on April 26, 2012. Plant McDonough Unit 6 is expected to be placed into service in November 2012. Plant McDonough Unit 1 was retired on February 29, 2012.

Gulf Power

Retail Base Rate Case

See Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Retail Base Rate Case” in Item 8 of the Form 10-K for additional information.

On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSC’s decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Power’s authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Power’s retail base rates and charges of $4 million to be effective in January 2013. On April 18, 2012, Gulf Power filed a motion to reconsider one aspect of the decision dealing with property acquired as a potential site for a future generating plant. If the motion is granted, the previously approved rates would be increased by an additional $2 million. The ultimate outcome of this matter cannot be determined at this time.

Cost Recovery Clauses

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

Fuel Cost Recovery

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

Over recovered fuel costs at March 31, 2012 totaled $28.8 million compared to $9.9 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

Purchased Power Capacity Recovery

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.

Over recovered purchased power capacity costs at March 31, 2012 totaled $9.6 million compared to $8.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

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Environmental Cost Recovery

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.

Over recovered environmental costs at March 31, 2012 totaled $4.0 million compared to $10.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

On April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015.

Energy Conservation Cost Recovery

See Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Energy Conservation Cost Recovery” in Item 8 of the Form 10-K for additional information.

Under recovered energy conservation costs at March 31, 2012 totaled $2.0 million compared to $3.1 million at December 31, 2011. These amounts are included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein.

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.

On April 2, 2012, Mississippi Power filed a motion to suspend the 2011 PEP lookback filing. Unresolved matters related to certain costs included in the 2010 PEP lookback filing also impact the 2011 PEP lookback filing, making it impractical to determine Mississippi Power’s actual retail return on investment for 2011 for purposes of the 2011 PEP lookback filing. The ultimate outcome of these matters cannot be determined at this time.

System Restoration Rider

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

On February 2, 2012, Mississippi Power submitted its 2012 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2012 SRR rate level remain at zero and Mississippi Power be allowed to accrue approximately $3.7 million to the property damage reserve in 2012. On April 3, 2012, the filing was approved by the Mississippi PSC.

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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 April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power’s portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power’s portion of the cost is expected to be recovered through the ECO Plan. As of March 31, 2012, total project expenditures were $55.6 million, with Mississippi Power’s portion being $27.8 million.

On February 14, 2012, Mississippi Power submitted its 2012 ECO Plan notice, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct scrubbers on Plant Daniel Units 1 and 2, Mississippi Power will revise the 2012 ECO Plan notice excluding scrubber expenditures from rate base, which is expected to result in little or no rate change.

The ultimate outcome of these matters 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.

At March 31, 2012, the amount of over recovered retail fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $50.9 million compared to $42.4 million at December 31, 2011. Mississippi Power also has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At March 31, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $18.1 million and $2.4 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at March 31, 2012 and December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Power’s Condensed Balance Sheets herein was $1.7 million. 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.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding Mississippi Power’s construction of the Kemper IGCC.

In May 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the Mississippi PSC order confirming Mississippi Power’s application for a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. In June 2010, the Mississippi PSC issued the CPCN (2010 MPSC Order).

In June 2010, the Sierra Club filed an appeal of the Mississippi PSC’s June 2010 decision to grant the CPCN 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 2010 MPSC Order and, on March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court. On March 15, 2012, the Mississippi Supreme Court reversed the Chancery Court’s decision and the 2010 MPSC Order and remanded the matter to the Mississippi PSC to correct the 2010 MPSC Order. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN.

On March 30, 2012, the Mississippi PSC issued temporary authorization for the continuation of construction of the Kemper IGCC until the earlier of the conclusion of the Mississippi PSC’s May 2012 open meeting or immediately upon the issuance of any final order issued by the Mississippi PSC on remand that conclusively addresses the mandate. On April 24, 2012, the Mississippi PSC issued a detailed order on remand (2012 MPSC Order) confirming the CPCN for the Kemper IGCC subject to the same conditions set forth in the 2010 MPSC Order. On April 26, 2012, the Sierra Club filed a motion for stay and a notice of appeal of the 2012 MPSC Order with the Chancery Court. On May 2, 2012, Mississippi Power filed a petition to join the appeal.

The certificated cost estimate of the Kemper IGCC is $2.4 billion, net of $245.3 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2) and excluding the cost of the lignite mine and equipment and the carbon dioxide (CO₂) pipeline facilities. The 2012 MPSC Order, like the 2010 MPSC Order, (1) approved a construction cost cap of up to $2.88 billion (exemptions from the cost cap include the cost of the lignite mine and equipment and the CO₂ pipeline facilities), (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal, and (3) approved financing cost recovery on CWIP balances not to exceed the certificated cost estimate, which provided for the accrual of AFUDC in 2010 and 2011 and provides for the current recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014, (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). As of March 31, 2012, Mississippi Power had utilized substantially all of its contingency contained in the certificated cost estimate. Mississippi Power anticipates that the costs to complete construction of the portion of the Kemper IGCC subject to the construction cost cap will be less than the cost cap but will likely exceed the certificated cost estimate.

The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. Of the total costs incurred through March 2009, $46 million has been reviewed and approved by the Mississippi PSC. A decision regarding the remaining $5 million has been deferred to a later date. The timing of the review of the remaining Kemper IGCC costs has not been determined.

The Kemper IGCC plant, expected to begin commercial operation in May 2014, will use locally mined lignite (an abundant, lower heating value coal) from a mine adjacent to the plant as fuel. The mine is scheduled to be placed into service in June 2013. In conjunction with the Kemper IGCC, Mississippi Power will own the 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 million, of which $79.7 million has been incurred through March 31, 2012. The asset retirement obligation associated with the reclamation and restoration of the mine currently under construction was immaterial at March 31, 2012. In May 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage the mining operations. The contract with Liberty Fuels is effective June 2010 through the end of the mine reclamation. On December 13, 2011, the Mississippi Department of Environmental Quality (MDEQ) approved the surface coal mining and the water pollution control permits for the mining operations operated by Liberty Fuels. On January 12, 2012, two individuals each filed a notice of appeal and a request for evidentiary hearing with the MDEQ regarding the surface coal mining and water pollution control permits. On March 8, 2012, the MDEQ permit board affirmed its issuance of the surface coal mining and water pollution control permits.

In 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 credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the recapture rules for Section 48A investment tax credits. Through March 31, 2012, Mississippi Power received or accrued tax benefits totaling $141.1 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. As a result of 100% bonus tax depreciation on certain assets placed, or to be placed, in service in 2011 and 2012, and the subsequent reduction in federal

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

taxable income, Mississippi Power estimates that it will not be able to utilize $105.0 million of these tax credits until after 2012. IRS guidelines allow the resulting unused credits to be carried forward for 20 years.

In July 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In December 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval of SMEPA’s 17.5% undivided interest in the Kemper IGCC. On February 28, 2012, the Mississippi PSC approved the joint petition for the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power’s senior unsecured credit rating falls below a BBB+ and/or Baa1. Given the interest-bearing nature of the deposit and SMEPA’s ability to request a refund, the deposit has been presented as a current liability in Mississippi Power’s Condensed Balance Sheet herein and as financing proceeds in the statement of cash flows.

As of March 31, 2012, Mississippi Power had spent a total of $1.30 billion on the Kemper IGCC including the cost of the lignite mine and equipment, the CO₂ pipeline facilities, and regulatory filing costs. Of this total, $1.28 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $22.9 million was recorded in other regulatory assets, $2.3 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Certificated New Plant” in Item 8 of the Form 10-K for information on the proposed rate schedules related to the Kemper IGCC.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(C) FAIR VALUE MEASUREMENTS

As of March 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
As of March 31, 2012:	Quoted Prices   in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$     —	$  24	$—		$     24
Interest rate derivatives	—	14	—		14
Foreign currency derivatives	—	1	—		1
Nuclear decommissioning trusts(a)	490	788	—		1,278
Cash equivalents and restricted cash	862	—	—		862
Other investments	4	50	15		69
Total	$1,356	$877	$15		$2,248
Liabilities:
Energy-related derivatives	$     —	$289	$—		$   289
Interest rate derivatives	—	10	—		10
Foreign currency derivatives	—	1	—		1
Total	$     —	$300	$—		$   300
Alabama Power
Assets:
Energy-related derivatives	$     —	$    1	$—		$       1
Nuclear decommissioning trusts:(b)
Domestic equity	283	63	—		346
Foreign equity(d)	27	56	—		83
U.S. Treasury and government agency securities	15	8	—		23
Corporate bonds	—	99	—		99
Mortgage and asset backed securities	—	26	—		26
Other	—	10	—		10
Cash equivalents and restricted cash	234	—	—		234
Total	$   559	$263	$—		$   822
Liabilities:
Energy-related derivatives	$     —	$  54	$—		$     54
Interest rate derivatives	—	10	—		10
Total	$     —	$  64	$—		$     64

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Fair Value Measurements Using
As of March 31, 2012:	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$  —	$  22	$  —	$  22
Nuclear decommissioning trusts:(c)
Domestic equity	165	1	—	166
Foreign equity(d)	—	109	—	109
U.S. Treasury and government agency securities	—	52	—	52
Municipal bonds	—	83	—	83
Corporate bonds	—	123	—	123
Mortgage and asset backed securities	—	127	—	127
Other	—	31	—	31
Total	$165	$548	$  —	$713
Liabilities:
Energy-related derivatives	$  —	$108	$  —	$108
Gulf Power
Assets:
Cash equivalents	$  15	$  —	$  —	$  15
Liabilities:
Energy-related derivatives	$  —	$  54	$  —	$  54
Mississippi Power
Assets:
Foreign currency derivatives	$  —	$    1	$  —	$    1
Cash equivalents	439	—	—	439
Total	$439	$    1	$  —	$440
Liabilities:
Energy-related derivatives	$  —	$  56	$  —	$  56
Foreign currency derivatives	—	1	—	1
Total	$  —	$  57	$  —	$  57
Southern Power
Assets:
Energy-related derivatives	$  —	$    1	$  —	$    1
Liabilities:
Energy-related derivatives	$  —	$  17	$  —	$  17

(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 March 31, 2012, approximately $41 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.

(d) Level 1 securities consist of actively traded stocks, while Level 2 securities consist of pooled funds.

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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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

As of March 31, 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

As of March 31, 2012:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	12	None	Daily	1 to 3 days
Other — commingled funds		87	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		93	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		862	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Other — commingled funds		56	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		93	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		234	None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds		12	None	Daily	1 to 3 days
Other — commingled funds		31	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds		15	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds		439	None	Daily	Not applicable

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC’s regulations. The 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 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 may include U.S. Treasury and government agency fixed income securities,

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 months ended March 31, 2012, the increase in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $86 million for Southern Company, $49 million for Alabama Power, and $37 million for Georgia Power.

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.

At March 31, 2012, 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	$20,843	$25,499
Alabama Power	$  6,380	$  7,789
Georgia Power	$  8,918	$11,837
Gulf Power	$  1,236	$  1,349
Mississippi Power	$  1,668	$  1,740
Southern Power	$  1,303	$  1,393

The fair values were Level 2 and are based on quoted market prices for the same or similar issues or on the current rates offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.

(D) STOCKHOLDERS’ EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effects of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended March 31, 2012	Three Months Ended March 31, 2011
	(in millions)
As reported shares	868	848
Effect of options and performance share award units	9	6
Diluted shares	877	854

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 1 million and 7 million for the three months ended March 31, 2012 and 2011, respectively.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Changes in Stockholders’ Equity

The following table presents year-to-date changes in stockholders’ equity of Southern Company:

	Number of Common Shares		Common Stockholders’	Preferred and Preference Stock of	Total     Stockholders’
	Issued	Treasury	Equity	Subsidiaries	Equity
	(in thousands)			(in millions)
Balance at December 31, 2011	865,664	(539)	$17,578	$707	$18,285
Net income after dividends on preferred and preference stock	—	—	368	—	368
Other comprehensive income (loss)	—	—	6	—	6
Stock issued	3,571	—	157	—	157
Cash dividends on common stock	—	—	(410)	—	(410)
Other	—	(6)	—	—	—
Balance at March 31, 2012	869,235	(545)	$17,699	$707	$18,406
Balance at December 31, 2010	843,814	(474)	$16,202	$707	$16,909
Net income after dividends on preferred and preference stock	—	—	422	—	422
Other comprehensive income (loss)	—	—	4	—	4
Stock issued	5,784	—	222	—	222
Cash dividends on common stock	—	—	(385)	—	(385)
Other	—	(1)	—	—	—
Balance at March 31, 2011	849,598	(475)	$16,465	$707	$17,172

(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 March 31, 2012:

	Expires										Executable Term Loans				Due Within One Year(a)
Company	2012		2013		2014     and     Beyond		Total		Unused		One     Year		Two     Years		Term     Out		No     Term     Out
	(in millions)						(in millions)				(in millions)				(in millions)
Southern Company		$  —		$  —		$1,000		$1,000		$1,000		$  —		$—		$  —		$  —
Alabama Power		121		35		1,150		1,306		1,306		51		—		51		71
Georgia Power		—		—		1,750		1,750		1,745		—		—		—		—
Gulf Power		75		35		165		275		275		75		—		75		35
Mississippi Power		106		25		165		296		296		25		41		66		65
Southern Power		—		—		500		500		500		—		—		—		—
Other		25		25		—		50		50		25		—		25		—
Total		$327		$120		$4,730		$5,177		$5,172		$176		$41		$217		$171

(a) Reflects facilities expiring on or before March 31, 2013.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(F) RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2012. 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 months ended March 31, 2012 and 2011 were as follows:

	000000	000000	000000	000000	000000
Pension Plans	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended March 31, 2012
Service cost	$   50	$ 11	$ 15	$   2	$ 2
Interest cost	98	23	35	4	5
Expected return on plan assets	(145)	(40)	(55)	(6)	(6)
Net amortization	31	8	11	1	1
Net cost (income)	$   34	$   2	$   6	$   1	$ 2
Three Months Ended March 31, 2011
Service cost	$   46	$ 11	$ 14	$   2	$ 2
Interest cost	98	24	36	4	4
Expected return on plan assets	(152)	(43)	(59)	(7)	(6)
Net amortization	13	3	5	1	1
Net cost (income)	$     5	$  (5)	$   (4)	$—	$ 1
Postretirement Benefits	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended March 31, 2012
Service cost	$   5	$ 1	$   1	$—	$—
Interest cost	21	5	9	1	1
Expected return on plan assets	(15)	(6)	(7)	—	—
Net amortization	5	2	3	—	—
Net cost (income)	$ 16	$ 2	$   6	$  1	$  1
Three Months Ended March 31, 2011
Service cost	$   5	$ 1	$   2	$—	$—
Interest cost	23	6	10	1	1
Expected return on plan assets	(16)	(6)	(8)	—	—
Net amortization	5	2	3	—	—
Net cost (income)	$ 17	$ 3	$   7	$1	$  1

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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 34.2% for the three months ended March 31, 2012 compared to 34.6% for the corresponding period in 2011. Southern Company’s effective tax rate is lower than the statutory rate primarily due to its employee stock plans’ dividend deduction and non-taxable AFUDC equity.

Alabama Power

Alabama Power’s effective tax rate was 38.3% for the three months ended March 31, 2012 compared to 37.1 % for the corresponding period in 2011. 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 34.9% for the three months ended March 31, 2012 compared to 34.6% for the corresponding period in 2011. The increase was primarily due to a decrease in AFUDC equity, which is non-taxable.

Gulf Power

Gulf Power’s effective tax rate was 34.6% for the three months ended March 31, 2012 compared to 33.8% for the corresponding period in 2011. The increase was primarily due to a decrease in AFUDC equity, which is non-taxable.

Mississippi Power

Mississippi Power’s effective tax rate was 24.7% for the three months ended March 31, 2012 compared to 32.2% for the corresponding period in 2011. The decrease was primarily due to an increase in AFUDC equity, which is non-taxable, related to the Kemper IGCC.

Southern Power

Southern Power’s effective tax rate was 31.3% for the three months ended March 31, 2012 compared to 35.6% for the corresponding period in 2011. The decrease was primarily due to lower earnings before income taxes and a settlement with the IRS related to the production activities deduction. See “Unrecognized Tax Benefits” herein for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Unrecognized Tax Benefits

Changes during 2012 for unrecognized tax benefits were as follows:

	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern Power
	(in millions)
Unrecognized tax benefits as of December 31, 2011	$ 120	$ 32	$ 47	$   3	$   5	$   3
Tax positions from current periods	3	1	1	—	—	—
Tax positions from prior periods	(6)	(3)	(1)	—	(1)	(2)
Reductions due to settlements	(5)	(2)	(3)	(1)	—	1
Reductions due to expired statute of limitations	—	—	—	—	—	—
Balance as of March 31, 2012	$ 112	$ 28	$ 44	$   2	$   4	$   2

The tax positions from current periods relate primarily to state investment tax credits and the tax accounting method change for repairs-generation assets. See “Tax Method of Accounting for Repairs” herein for additional information. The decreases in tax positions from prior periods and reductions due to settlements relate to a settlement with the IRS of the calculation methodology for the production activities deduction.

The impact on the effective tax rate, if recognized, was as follows:

	As of March 31, 2012			As of   December 31,   2011
	Georgia Power	Other Registrants	Southern Company	Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$24	$  5	$  59	$  69
Tax positions not impacting the effective tax rate	20	32	53	51
Balance of unrecognized tax benefits	$44	$37	$112	$120

The tax positions impacting the effective tax rate primarily relate to state investment tax credits and a litigation settlement refund claim for Southern Company. See Note 5 to the financial statements of Southern Company under “Effective Tax Rate” in Item 8 of the Form 10-K 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. See “Tax Method of Accounting for Repairs” herein for additional information. 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 Power	Other Registrants	Southern Company
	(in millions)
Interest accrued as of December 31, 2011	$ 6	$   3	$ 10
Interest reclassified due to settlements	(2)	(3)	(5)
Interest accrued during the period	1	—	1
Balance as of March 31, 2012	$ 5	$ —	$   6

All of the registrants classify interest on tax uncertainties as interest expense. The interest reclassified due to settlements is primarily associated with a settlement with the IRS related to the calculation methodology for the production activities deduction.

None of the registrants accrued any penalties on uncertain tax positions.

151

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the registrants’ unrecognized tax positions will significantly increase or decrease within 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. On August 19, 2011, the IRS issued a revenue procedure, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. 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. On December 23, 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2012. The utility industry anticipates more detailed guidance concerning these regulations. 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 traditional operating companies and Southern Power 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 traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

152

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 and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions, are reflected in earnings.

• Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At March 31, 2012, the net volume of energy-related derivative contracts for power and natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

	Power			Gas
	Net (Sold) MWHs	Longest Hedge Date	Longest Non-Hedge Date	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)			(in millions)
Southern Company	(0.1)	—	2012	221	2017	2017
Alabama Power	—	—	—	37	2017	—
Georgia Power	—	—	—	85	2017	—
Gulf Power	—	—	—	43	2017	—
Mississippi Power	—	—	—	28	2017	—
Southern Power	(0.1)	—	2012	28	2012	2017

In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 9 million mmBtu for Southern Company, 4 million mmBtu for Georgia Power, 2 million mmBtu for Southern Power, and is 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 March 31, 2013 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.

153

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At March 31, 2012, the following interest rate derivatives were outstanding:

	Notional Amount	Interest Rate   Received	Interest Rate   Paid	Hedge Maturity Date	Fair Value Gain (Loss)   March 31, 2012
	(in millions)				(in millions)
Cash flow hedges of forecasted transactions
Alabama Power	$300	3-month LIBOR	2.90%*	December 2022	$(10)
Fair value hedges of existing debt
Southern Company	350	4.15%	3-month LIBOR + 1.96%*	May 2014	14
Total	$650				$  4

* 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 March 31, 2013, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.

Registrant	Estimated Gain (Loss) to be Reclassified for the 12 Months Ending March 31, 2013	Total Deferred Gains (Losses) Amortized Through
	(in millions)
Southern Company	$(16)	2037
Alabama Power	1	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 typically recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

154

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At March 31, 2012, the following foreign currency derivatives were outstanding:

	Notional Amount	Forward Rate	Hedge Maturity Date	Fair Value Gain (Loss) March 31, 2012
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR6.8	1.3805 Dollars per Euro*	Various through March 2014	$—
Derivatives not designated as hedges
Mississippi Power	EUR18.1	1.3209 Dollars per Euro*	N/A	—
Total	EUR24.9			$—

* Weighted Average

Derivative Financial Statement Presentation and Amounts

At March 31, 2012, 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 March 31, 2012
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern   Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$17	$—	$17	$—	$—
Other deferred charges and assets	6	1	5	—	—
Total derivatives designated as hedging instruments for regulatory purposes	$23	$  1	$22	$—	$—	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	8	—	—	—	—	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$14	$—	$—	$—	$—	$—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	$  1	$—	$—	$—	$—	$  1
Foreign currency derivatives
Other current assets	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$  2	$—	$—	$—	$  1	$  1
Total asset derivatives	$39	$  1	$22	$—	$  1	$  1

155

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Liability Derivatives at March 31, 2012
	Fair Value
Derivative Category and Balance Sheet Location	Southern   Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern   Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$191	$41	$  80	$31	$39
Other deferred credits and liabilities	81	13	28	23	17
Total derivatives designated as hedging instruments for regulatory purposes	$272	$54	$108	$54	$56	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities	$    2	$—	$  —	$—	$—	$    2
Interest rate derivatives:
Liabilities from risk management activities	10	10	—	—	—	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$  12	$10	$  —	$—	$—	$    2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$  15	$—	$  —	$—	$—	$  15
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$  16	$—	$  —	$—	$  1	$  15
Total liability derivatives	$300	$64	$108	$54	$57	$  17

All derivative instruments are measured at fair value. See Note (C) herein for additional information.

At March 31, 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$(191)	$(41)	$(80)	$(31)	$(39)
Other regulatory assets, deferred	(81)	(13)	(28)	(23)	(17)
Other regulatory liabilities, current	17	—	17	—	—
Other regulatory liabilities, deferred	6	1	—	—	—
Other deferred credits and liabilities*	—	—	5	—	—
Total energy-related derivative gains (losses)	$(249)	$(53)	$(86)	$(54)	$(56)

* Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

For the three months ended March 31, 2012 and March 31, 2011, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were immaterial.

156

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months ended March 31, 2012, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were immaterial. For the three months ended March 31, 2011, 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 $3 million. This amount was offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there was no impact on Southern Company’s or Mississippi Power’s statements of income.

For the three months ended March 31, 2012 and March 31, 2011, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

Derivatives in Cash Flow	Gain (Loss) Recognized in OCI on Derivative		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Hedging Relationships	(Effective Portion)		Statements of Income Location	Amount
	2012	2011		2012	2011
	(in millions)			(in millions)
Southern Company
Energy-related derivatives	$     (1)	$       1	Fuel	$            —	$            —
Interest rate derivatives	6	4	Interest expense, net of amounts capitalized	(3)	(5)
Total	$      5	$       5		$            (3)	$            (5)
Alabama Power
Interest rate derivatives	$      7	$       4	Interest expense, net of amounts capitalized	$            —	$            —
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (1)	$            (1)
Gulf Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Mississippi Power
Interest rate derivatives	$    (1)	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Southern Power
Energy-related derivatives	$    (1)	$       1	Fuel	$            —	$            —
Interest rate derivatives	—	—	Interest expense, net of amounts capitalized	(2)	(3)
Total	$    (1)	$       1		$            (2)	$            (3)

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three months ended March 31, 2012, the pre-tax losses from energy-related derivatives not designated as hedging instruments on the statements of income were $6 million for Southern Company and Southern Power. For the three months ended March 31, 2011, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for Southern Company and Southern Power.

For the three months ended March 31, 2012, the pre-tax effects of foreign currency derivatives not designated as hedging instruments were recorded as regulatory assets and liabilities and were immaterial for Southern Company and Mississippi Power.

157

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 March 31, 2012, the fair value of derivative liabilities with contingent features, by registrant, was as follows:

	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern Power
			(in millions)
Derivative liabilities	$36	$9	$10	$7	$6	$4

At March 31, 2012, the registrants had no collateral posted with their derivative counterparties. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $36 million for each registrant. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade.

158

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(I) SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Southern Power’s revenues from sales to the traditional operating companies were $112 million and $83 million for the three months ended March 31, 2012 and March 31, 2011, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:

	Electric Utilities
	Traditional         Operating         Companies	Southern         Power	Eliminations	Total	All   Other	Eliminations	Consolidated
	(in millions)
Three Months Ended March 31, 2012:
Operating revenues	$  3,449	$   254	$            (114)	$  3,589	$     38	$  (23)	$  3,604
Segment net income *	339	29	1	369	2	(3)	368
Total assets at March 31, 2012	$55,698	$3,596	$              (81)	$59,213	$1,086	$(425)	$59,874
Three Months Ended March 31, 2011:
Operating revenues	$  3,810	$   282	$              (98)	$  3,994	$     38	$  (20)	$  4,012
Segment net income (loss)*	385	38	—	423	1	(2)	422
Total assets at December 31, 2011	$54,622	$3,581	$            (127)	$58,076	$1,592	$(401)	$59,267

* 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 March 31, 2012	$3,092	$349	$148	$3,589
Three Months Ended March 31, 2011	$3,396	$449	$149	$3,994

159

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.

160

Item 6.   Exhibits.

(4) Instruments Describing Rights of Security Holders, Including Indentures

Georgia Power

(c)1 - Forty-Sixth Supplemental Indenture to Senior Note Indenture dated as of March 6, 2012, providing for the issuance of the Series 2012A 4.30% Senior Notes due March 15, 2042. (Designated in Form 8-K dated February 29, 2012, File No. 1-6468, as Exhibit 4.2.)

Mississippi Power

(e)1 - Thirteenth Supplemental Indenture to Senior Note Indenture dated as of March 9, 2012, providing for the issuance of the Series 2012A 4.25% Senior Notes due March 15, 2042. (Designated in Form 8-K dated March 5, 2012, File No. 001-11229, as Exhibit 4.2(b).)

(10) Material Contracts

Southern Company

(a)1 - Base Salaries of Named Executive Officers.

Alabama Power

(b)1 - Base Salaries of Named Executive Officers.

Georgia Power

(c)1 - Base Salaries of Named Executive Officers.

(c)2 - Amendment No. 5, dated as of February 7, 2012, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, Inc., as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power has omitted such portions from the filing and filed them separately with the SEC.)

Mississippi Power

(e)1 - Base Salaries of Named Executive Officers.

(24) Power of Attorney and Resolutions

Southern Company

(a)1 - Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, 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, 2011, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)

161

Georgia Power
(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, 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, 2011, File No. 001-31737 as Exhibit 24(d) and incorporated herein by reference.)
Mississippi Power
(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2011, 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, 2011, 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.

162

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.

163

(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

164

THE SOUTHERN COMPANY

SIGNATURES

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

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

Date: May 7, 2012

165

ALABAMA POWER COMPANY

SIGNATURES

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

	ALABAMA POWER COMPANY
By	Charles D. McCrary
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Philip C. Raymond
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 7, 2012

166

GEORGIA POWER COMPANY

SIGNATURES

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

	GEORGIA POWER COMPANY
By	W. Paul Bowers
	President and Chief Executive Officer
	(Principal Executive Officer)
By	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: May 7, 2012

167

GULF POWER COMPANY

SIGNATURES

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

	GULF POWER COMPANY
By	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: May 7, 2012

168

MISSISSIPPI POWER COMPANY

SIGNATURES

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

	MISSISSIPPI POWER COMPANY
By	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: May 7, 2012

169

SOUTHERN POWER COMPANY

SIGNATURES

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

	SOUTHERN POWER COMPANY
By	Oscar C. Harper, IV
	President and Chief Executive Officer
	(Principal Executive Officer)
By	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: May 7, 2012

170

EX-10

Exhibit 10(a)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

THE SOUTHERN COMPANY

The following are the annual base salaries, effective March 1, 2012, of the Chief Executive Officer and Chief Financial Officer of The Southern Company (the “Company”) and certain other executive officers of the Company who served during 2011.

Thomas A. Fanning Chairman, President and Chief Executive Officer	$1,125,000
Art P. Beattie Executive Vice President and Chief Financial Officer	$628,732
W. Paul Bowers Executive Vice President of the Company, President and Chief Executive Officer of Georgia Power Company	$743,585
Charles D. McCrary Executive Vice President of the Company, President and Chief Executive Officer of Alabama Power Company	$781,369
Anthony J. Topazi Executive Vice President and Chief Operating  Officer	$646,089

EX-10

EXHIBIT 10(b)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

ALABAMA POWER COMPANY

The following are the annual base salaries, effective March 1, 2012, of the Chief Executive Officer and Chief Financial Officer of Alabama Power Company and certain other executive officers of Alabama Power Company who served during 2011.

Charles D. McCrary President and Chief Executive Officer	$781,369
Philip C. Raymond Executive Vice President, Chief Financial Officer, and Treasurer	$284,591
Theodore J. McCullough Senior Vice President	$225,884
Zeke W. Smith Executive Vice President	$283,541
Steven R. Spencer Executive Vice President	$428,784

EX-10

EXHIBIT 10(c)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

GEORGIA POWER COMPANY

The following are the annual base salaries, effective March 1, 2012, of the Chief Executive Officer and Chief Financial Officer of Georgia Power Company and certain other executive officers of Georgia Power Company who served during 2011.

W. Paul Bowers President and Chief Executive Officer	$743,585
Ronnie R. Labrato Executive Vice President, Chief Financial Officer and Treasurer	$302,575
W. Craig Barrs Executive Vice President	$312,000
Mickey A. Brown* Executive Vice President	$383,877
Joseph A. Miller Executive Vice President	$403,065

*Retired February 1, 2012

EX-10

Exhibit 10(c)(2)

Georgia Power Company has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the Securities and Exchange Commission. Georgia Power Company has omitted such portions from this filing and filed them separately with the Securities and Exchange Commission. Such omissions are designated as “[***].”

AMENDMENT NO. 5

TO

ENGINEERING, PROCUREMENT AND CONSTRUCTION

AGREEMENT

BETWEEN

GEORGIA POWER COMPANY, FOR ITSELF AND AS AGENT

FOR OGLETHORPE POWER CORPORATION (AN ELECTRIC

MEMBERSHIP CORPORATION), MUNICIPAL ELECTRIC

AUTHORITY OF GEORGIA AND THE CITY OF DALTON,

GEORGIA, ACTING BY AND THROUGH ITS BOARD OF WATER,

LIGHT AND SINKING FUND COMMISSIONERS, AS OWNERS

AND

A CONSORTIUM CONSISTING OF WESTINGHOUSE ELECTRIC

COMPANY LLC AND STONE & WEBSTER, INC., AS

CONTRACTOR

FOR

UNITS 3 & 4 AT THE VOGTLE ELECTRIC GENERATING PLANT

SITE

IN WAYNESBORO, GEORGIA

DATED AS OF APRIL 8, 2008

1

AMENDMENT NO. 5 TO

ENGINEERING, PROCUREMENT AND CONSTRUCTION AGREEMENT

This AMENDMENT NO. 5 (the “Amendment”) TO THE ENGINEERING, PROCUREMENT AND CONSTRUCTION AGREEMENT, dated April 8, 2008, as amended (the “Agreement”) by and between GEORGIA POWER COMPANY, a Georgia corporation (“GPC”), acting for itself and as agent for OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION), an electric membership corporation formed under the laws of the State of Georgia, MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA, a public body corporate and politic and an instrumentality of the State 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 (hereinafter referred to collectively as “Owners”), and a consortium consisting of WESTINGHOUSE ELECTRIC COMPANY LLC, a Delaware limited liability company having a place of business in Cranberry Township, Pennsylvania (“Westinghouse”), and STONE & WEBSTER, INC. a Louisiana corporation having a place of business in Charlotte, North Carolina (“Stone & Webster”) (hereinafter referred to collectively as “Contractor”), is entered into as of the 7th day of February 2012.

RECITALS

WHEREAS, Owners and Contractor entered into the Agreement, as of April 8, 2008, to provide for, among other things, the design, engineering, procurement, installation, construction and technical support of start-up and testing of equipment, materials and structures comprising the Facility;

WHEREAS, the Parties have entered into four (4) prior amendments to the Agreement and, have agreed that it would be beneficial to amend the Agreement a fifth time to memorialize a recent agreement between them regarding access to certain Westinghouse information

WHEREAS, the Parties’ recent agreement and this  revision  will not affect the Project Schedule or the Contract Price; and

WHEREAS, the Parties agree that, with the exception of the changes expressly stated herein, this Amendment will not change the terms and conditions of the Agreement.

NOW, THEREFORE, in consideration of the recitals, the mutual promises herein and other good and valuable consideration, the receipt and sufficiency of which the Parties acknowledge, the Parties, intending to be legally bound, stipulate and agree as follows:

1.   Contractor hereby agrees and represents that this Amendment shall not cause, directly or indirectly, any delay in the Project Schedule or any increase in the Contract Price.

2. Article 1 Definitions. Article 1 is hereby amended to add the definition of “Westinghouse Accessible Information” as follows:

2

“‘Westinghouse Accessible Information’ has the meaning set forth in Section 19.3(h).”

3. Article 19 Confidential and Proprietary Information, Section 19.3 – Special Procedures Pertaining to Contractor’s Confidential and Proprietary Information. Section 19.3 is hereby amended by adding the following new subsection (h):

“(h)                 Westinghouse Accessible Information.  Westinghouse Accessible Information shall consist of the Westinghouse information and Westinghouse documents referenced or cited in the current revision of the AP1000 design certification document and required to be incorporated into or referenced in the COLA that are not otherwise Documentation deliverable to Owners under this Agreement.  Owners, Southern Nuclear and the NRC will have the right to access and review Westinghouse Accessible Information at any of Westinghouse’s offices at reasonable times and subject to reasonable requirements of Westinghouse.  Neither Southern Nuclear nor any Owner shall have the right to copy or remove Westinghouse Accessible Information from Westinghouse’s facility.  Owners and Southern Nuclear agree not to use Westinghouse Accessible Information unless such use is solely for Facility Purposes.  Owners and Southern Nuclear shall maintain Westinghouse Accessible Information in confidence and shall not disclose it to any Third Party without Westinghouse’s prior written approval. Owners or Southern Nuclear may disclose Westinghouse Accessible Information to the NRC, but only after Owners provide Contractor with prior written notice of any such proposed disclosure.  Any disclosure to the NRC shall be made on a confidential basis and Owner shall advise the NRC that the information being disclosed is proprietary to Westinghouse at the time of the disclosure.  All requests for access to Westinghouse Accessible Information will be handled on a case-by-case basis.  Any and all effort incurred by Westinghouse, including but not limited to making the necessary arrangements for access, time spent in preparing for such access, and review of notes prior to exit from Westinghouse’s facility, [***].  Any work required of Westinghouse in support of Owners’ access and review of Westinghouse Accessible Information, including, but not limited to, analyses, manipulation of data, and running of computer models, [***].  The terms of this Section 19.3(h) are self-contained and are not altered by other provisions of this Article 19. ”

4.           Miscellaneous

4.1 Capitalized terms used herein and not defined herein have the meanings assigned in the Agreement.

4.2 This Amendment No. 5 shall be construed in connection with and as part of the Agreement, and all terms, conditions, and covenants contained in the Agreement, except as herein modified, shall be and shall remain in full force and effect.  The Parties hereto agree that they are bound by the terms, conditions and covenants of the Agreement as amended hereby.

3

4.3 The validity, interpretation, and performance of this Amendment and each of its provisions shall be governed by the laws of the State of Georgia, without giving effect to the principles thereof relating to conflicts of laws.

4.4 Except as expressly provided for in this Amendment No. 5, all other Articles, Sections and Exhibits of and to the Agreement and guarantees associated with this Agreement remain unchanged.

4.5 This Amendment may be executed simultaneously in two or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument.

IN WITNESS WHEREOF, the Parties have duly executed this Amendment No. 5 as of the date first above written.

WESTINGHOUSE ELECTRIC COMPANY LLC

By:  /s/ Thomas H. Dent________

Name: Thomas H. Dent

Title: VP & Consortium Director

Attest:  /s/ Rolf F. Ziesing_______

Its: OPS Director

(CORPORATE SEAL)

STONE & WEBSTER, INC.

By:  /s/ R.M. Glover___________

Name: R.M. Glover

Title: Authorized Representative

Attest:  /s/ T. Jason Dunaway____

Its: Director/ Business Manager

(CORPORATE SEAL)

GEORGIA POWER COMPANY, as an Owner

and as agent for the other Owners

By:  /s/ Joseph A. Miller________

Name:  Joseph A. Miller

Title: Executive VP

Attest: /s/ Thomas P. Bishop_____

Its: SVP & Corporate Secretary

(CORPORATE SEAL)

4

EX-10

EXHIBIT 10(e)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

MISSISSIPPI POWER COMPANY

The following are the annual base salaries, effective March 1, 2012, of the Chief Executive Officer and Chief Financial Officer of Mississippi Power Company and certain other executive officers of Mississippi Power Company who served during 2011.

Edward Day, VI President and Chief Executive Officer	$407,056
Moses H. Feagin Vice President, Treasurer and Chief Financial Officer	$234,073
Thomas O. Anderson, IV Vice President	$194,461
John W. Atherton Vice President	$234,073
Jeff G. Franklin Vice President	$237,652
Donald R. Horsley* Vice President	$300,706

*Served as an executive officer of Mississippi Power Company through July 31, 2011

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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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:  May 7, 2012

               /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 March 31, 2012, 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 March 31, 2012, 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 March 31, 2012, 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

May 7, 2012

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 March 31, 2012, 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 March 31, 2012, 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 March 31, 2012, 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

May 7, 2012

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 March 31, 2012, 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 March 31, 2012, 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 March 31, 2012, 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

May 7, 2012

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 March 31, 2012, 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 March 31, 2012, 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 March 31, 2012, 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

May 7, 2012

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 March 31, 2012, 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 March 31, 2012, 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 March 31, 2012, 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

May 7, 2012

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 March 31, 2012, 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 March 31, 2012, 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 March 31, 2012, 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

May 7, 2012

XML

Effective Tax Rate and Unrecognized Tax Benefits (Details Textual)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	34.20%	34.60%
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern	Next 12 Months
Alabama Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	38.30%	37.10%
Georgia Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	34.90%	34.60%
Gulf Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	34.60%	33.80%
Mississippi Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	24.70%	32.20%
Southern Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	31.30%	35.60%

XML

Segment and Related Information (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Financial data for Products and Services
Electric Utilities Revenues	$ 3,589	$ 3,994
Retail [Member]
Financial data for Products and Services
Electric Utilities Revenues	3,092	3,396
Wholesale [Member]
Financial data for Products and Services
Electric Utilities Revenues	349	449
Other Electric Revenue [Member]
Financial data for Products and Services
Electric Utilities Revenues	$ 148	$ 149

XML

Stockholder's Equity (Details 1) (USD $) Share data in Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012 Number of Common shares Issued [Member]	Mar. 31, 2011 Number of Common shares Issued [Member]	Mar. 31, 2012 Number of Common shares Treasury [Member]	Mar. 31, 2011 Number of Common shares Treasury [Member]	Mar. 31, 2012 Common Stockholders' Equity [Member]	Mar. 31, 2011 Common Stockholders' Equity [Member]	Mar. 31, 2012 Preferred and Preference Stock of Subsidiaries [Member]	Dec. 31, 2011 Preferred and Preference Stock of Subsidiaries [Member]	Mar. 31, 2011 Preferred and Preference Stock of Subsidiaries [Member]	Dec. 31, 2010 Preferred and Preference Stock of Subsidiaries [Member]
Changes in Stockholders' Equity
Beginning Balance	$ 18,285,000,000	$ 16,909,000,000					$ 17,578,000,000	$ 16,202,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000
Beginning Balance, Shares			(865,664)	(843,814)	(539)	(474)
Net Income After Dividends on Preferred and Preference Stock	368,000,000	422,000,000					368,000,000	422,000,000
Other comprehensive income (loss)	6,000,000	4,000,000					6,000,000	4,000,000
Stock issued, shares			3,571	5,784
Stock issued	157,000,000	222,000,000					157,000,000	222,000,000
Cash dividends on common stock	(410,000,000)	(385,000,000)					(410,000,000)	(385,000,000)
Other, shares					(6)	(1)
Ending Balance	$ 18,406,000,000	$ 17,172,000,000					$ 17,699,000,000	$ 16,465,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000
Ending Balance, Shares			(869,235)	(849,598)	(545)	(475)

XML

Segment and Related Information (Tables)

3 Months Ended

Mar. 31, 2012

Segment and Related Information [Abstract]

Financial data for business segments

	Electric Utilities
	Traditional         Operating         Companies	Southern         Power	Eliminations	Total	All   Other	Eliminations	Consolidated
	(in millions)
Three Months Ended March 31, 2012:
Operating revenues	$  3,449	$   254	$            (114)	$  3,589	$     38	$  (23)	$  3,604
Segment net income *	339	29	1	369	2	(3)	368
Total assets at March 31, 2012	$55,698	$3,596	$              (81)	$59,213	$1,086	$(425)	$59,874
Three Months Ended March 31, 2011:
Operating revenues	$  3,810	$   282	$              (98)	$  3,994	$     38	$  (20)	$  4,012
Segment net income (loss)*	385	38	—	423	1	(2)	422
Total assets at December 31, 2011	$54,622	$3,581	$            (127)	$58,076	$1,592	$(401)	$59,267

* 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 March 31, 2012	$3,092	$349	$148	$3,589
Three Months Ended March 31, 2011	$3,396	$449	$149	$3,994

XML

Derivatives (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	$ 5	$ 5
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(3)	(5)
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)	(5)
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)	(1)
Southern Power [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(1)	1
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(2)	(3)
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)	(2)	(3)
Energy-related derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(1)	1
Energy-related derivatives [Member] | Southern Power [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(1)	1
Interest rate derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	6	4
Interest rate derivatives [Member] | Alabama Power [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	7	4
Interest rate derivatives [Member] | Mississippi Power [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	$ (1)

XML

Effective Tax Rate and Unrecognized Tax Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	$ 120
Tax positions from current periods	3
Tax positions from prior periods	(6)
Reductions due to settlements	(5)
Reductions due to expired statute of limitations
Unrecognized tax benefits as of March 31, 2012	112
Alabama Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	32
Tax positions from current periods	1
Tax positions from prior periods	(3)
Reductions due to settlements	(2)
Reductions due to expired statute of limitations
Unrecognized tax benefits as of March 31, 2012	28
Georgia Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	47
Tax positions from current periods	1
Tax positions from prior periods	(1)
Reductions due to settlements	(3)
Reductions due to expired statute of limitations
Unrecognized tax benefits as of March 31, 2012	44
Gulf Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	3
Reductions due to settlements	(1)
Reductions due to expired statute of limitations
Unrecognized tax benefits as of March 31, 2012	2
Mississippi Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	5
Tax positions from prior periods	(1)
Reductions due to expired statute of limitations
Unrecognized tax benefits as of March 31, 2012	4
Southern Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	3
Tax positions from prior periods	(2)
Reductions due to settlements	1
Reductions due to expired statute of limitations
Unrecognized tax benefits as of March 31, 2012	$ 2

XML

Introduction

3 Months Ended

Mar. 31, 2012

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, 2011 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 March 31, 2012 and 2011. 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.

Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

Investments in Leveraged Leases

See Note 1 to the financial statements of Southern Company under “Leveraged Leases” in Item 8 of the Form 10-K for additional information.

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 assets. Southern Company is currently engaged in discussions with the lessee and the holders of the project’s nonrecourse debt to restructure the debt payments and the related rental payments to allow additional capital investment in the project to be made to improve the operation of the generation assets and the financial viability of the lease transaction. Southern Company continues to monitor the performance of the underlying assets and to evaluate the ability of the lessee to continue to make the required lease payments. If the attempts at restructuring the project are unsuccessful and the project is ultimately abandoned, the potential impairment loss that would be incurred is approximately $90 million on an after-tax basis. The ultimate outcome of this matter cannot be determined at this time.

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Derivatives (Details 3) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Fair value of derivative liabilities with contingent features
Derivative liabilities	$ 36
Alabama Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	9
Georgia Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	10
Gulf Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	7
Mississippi Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	6
Southern Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	$ 4

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Fair Value Measurements (Details 1) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
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	$ 12
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	1 to 3 days
Corporate bonds - commingled funds [Member] | Georgia Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	12
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	87
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period	Daily/7days
Other - commingled funds [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	56
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period	Daily/7days
Other - commingled funds [Member] | Georgia Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	31
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	93
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	15 days
Trust owned life insurance [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	93
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	862
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Money market funds [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	234
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Money market funds [Member] | Gulf Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	15
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Money market funds [Member] | Mississippi Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	439
Unfunded Commitments	$ 0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	$ 24
Interest rate derivatives	14
Foreign currency derivatives	1
Nuclear decommissioning trusts	1,278
Cash equivalents and restricted cash	862
Other	69
Fair value assets, total	2,248
Liabilities:
Energy-related derivatives	289
Interest rate derivatives	10
Foreign currency derivatives	1
Fair value liabilities, total	300
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Nuclear decommissioning trusts	490
Cash equivalents and restricted cash	862
Other	4
Fair value assets, total	1,356
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	24
Interest rate derivatives	14
Foreign currency derivatives	1
Nuclear decommissioning trusts	788
Other	50
Fair value assets, total	877
Liabilities:
Energy-related derivatives	289
Interest rate derivatives	10
Foreign currency derivatives	1
Fair value liabilities, total	300
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Other	15
Fair value assets, total	15
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	1
Cash equivalents and restricted cash	234
Fair value assets, total	822
Liabilities:
Energy-related derivatives	54
Interest rate derivatives	10
Fair value liabilities, total	64
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	346
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	83
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	23
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	99
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	26
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	10
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents and restricted cash	234
Fair value assets, total	559
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	283
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	27
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	15
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	1
Fair value assets, total	263
Liabilities:
Energy-related derivatives	54
Interest rate derivatives	10
Fair value liabilities, total	64
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	63
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	56
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	8
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	99
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	26
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	10
Georgia Power [Member]
Assets:
Nuclear decommissioning trusts	41
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	22
Fair value assets, total	713
Liabilities:
Energy-related derivatives	108
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	166
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	109
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	52
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	83
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	123
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	127
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	31
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Fair value assets, total	165
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	165
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	22
Fair value assets, total	548
Liabilities:
Energy-related derivatives	108
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	1
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	109
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	52
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	83
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	123
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	127
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	31
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents and restricted cash	15
Liabilities:
Energy-related derivatives	54
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents and restricted cash	15
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Liabilities:
Energy-related derivatives	54
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Foreign currency derivatives	1
Cash equivalents and restricted cash	439
Fair value assets, total	440
Liabilities:
Energy-related derivatives	56
Foreign currency derivatives	1
Fair value liabilities, total	57
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents and restricted cash	439
Fair value assets, total	439
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Foreign currency derivatives	1
Fair value assets, total	1
Liabilities:
Energy-related derivatives	56
Foreign currency derivatives	1
Fair value liabilities, total	57
Southern Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	1
Liabilities:
Energy-related derivatives	17
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	1
Liabilities:
Energy-related derivatives	$ 17

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Derivatives (Details Textual) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 MMBTU
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	9,000,000
Pre-tax gains from foreign currency derivatives designated as fair value hedging instruments	$ 3
Maximum potential collateral requirements arising the from credit-risk-related contingent features	36
Energy-related derivatives [Member]
Derivatives (Textual) [Abstract]
Pre-tax losses from energy-related derivatives not designated as hedging instruments on the statements of income	6
Alabama Power [Member]
Derivatives (Textual) [Abstract]
Maximum potential collateral requirements arising the from credit-risk-related contingent features	36
Georgia Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	4,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	36
Gulf Power [Member]
Derivatives (Textual) [Abstract]
Maximum potential collateral requirements arising the from credit-risk-related contingent features	36
Mississippi Power [Member]
Derivatives (Textual) [Abstract]
Pre-tax gains from foreign currency derivatives designated as fair value hedging instruments	3
Maximum potential collateral requirements arising the from credit-risk-related contingent features	36
Southern Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	2,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	36
Southern Power [Member] | Energy-related derivatives [Member]
Derivatives (Textual) [Abstract]
Pre-tax losses from energy-related derivatives not designated as hedging instruments on the statements of income	$ 6

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Long-term debt:
Long-term debt, Carrying Amount	$ 20,843
Long-term debt, Fair Value	25,499
Alabama Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	6,380
Long-term debt, Fair Value	7,789
Georgia Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	8,918
Long-term debt, Fair Value	11,837
Gulf Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,236
Long-term debt, Fair Value	1,349
Mississippi Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,668
Long-term debt, Fair Value	1,740
Southern Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,303
Long-term debt, Fair Value	$ 1,393

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Fair Value Measurements (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Fair Value Measurements (Textual) [Abstract]
Increase in fair value of funds including reinvested interest and dividends	$ 86
Fair Value Measurement (Textual) [Abstract]
Maximum number of months related to maturities in the portfolio not to exceeded from date of purchase	13 months
Maximum number of days related to dollar-weighted average portfolio maturities regarding commingled funds	90 days
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]
Increase in fair value of funds including reinvested interest and dividends	49
Georgia Power [Member]
Fair Value Measurements (Textual) [Abstract]
Nuclear decommissioning trusts	41
Increase in fair value of funds including reinvested interest and dividends	$ 37

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Changes in fair value of qualifying hedges, tax	$ 2,000,000	$ 2,000,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1,000,000	2,000,000
Change in fair value of marketable securities, tax	0
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	1,000,000	1,000,000
Alabama Power [Member]
Changes in fair value of qualifying hedges, tax	3,000,000	2,000,000
Georgia Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	0
Gulf Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	90,000	90,000
Mississippi Power [Member]
Changes in fair value of qualifying hedges, tax	(296,000)	(1,000)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	16,000
Southern Power [Member]
Changes in fair value of qualifying hedges, tax	(173,000)	423,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 956,000	$ 1,071,000

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Stockholder's Equity (Details) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Earnings per Share
As reported shares	868	848
Effect of options and performance share award units	9	6
Diluted shares	877	854

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Derivatives (Details) In Millions, unless otherwise specified	3 Months Ended		3 Months Ended									3 Months Ended
	Mar. 31, 2012 USD ($)	Mar. 31, 2012 Fair Value Hedging [Member] USD ($)	Mar. 31, 2012 Alabama Power [Member] USD ($)	Mar. 31, 2012 Georgia Power [Member] USD ($)	Mar. 31, 2012 Gulf Power [Member] USD ($)	Mar. 31, 2012 Mississippi Power [Member] USD ($)	Mar. 31, 2012 Mississippi Power [Member] EUR (€)	Mar. 31, 2012 Mississippi Power [Member] Derivatives not designated as hedges [Member] USD ($)	Mar. 31, 2012 Mississippi Power [Member] Derivatives not designated as hedges [Member] EUR (€)	Mar. 31, 2012 Mississippi Power [Member] Fair Value Hedging [Member] USD ($)	Mar. 31, 2012 Mississippi Power [Member] Fair Value Hedging [Member] EUR (€)	Mar. 31, 2012 Southern Power [Member] USD ($)	Mar. 31, 2012 Power [Member] MWh	Mar. 31, 2012 Power [Member] Alabama Power [Member]	Mar. 31, 2012 Power [Member] Georgia Power [Member]	Mar. 31, 2012 Power [Member] Gulf Power [Member]	Mar. 31, 2012 Power [Member] Mississippi Power [Member]	Mar. 31, 2012 Power [Member] Southern Power [Member] MWh	Mar. 31, 2012 Gas [Member] MMBTU	Mar. 31, 2012 Gas [Member] Alabama Power [Member] MMBTU	Mar. 31, 2012 Gas [Member] Georgia Power [Member] MMBTU	Mar. 31, 2012 Gas [Member] Gulf Power [Member] MMBTU	Mar. 31, 2012 Gas [Member] Mississippi Power [Member] MMBTU	Mar. 31, 2012 Gas [Member] Southern Power [Member] MMBTU	Mar. 31, 2012 Hedge Maturity Date December 2022 [Member] Alabama Power [Member] USD ($)	Mar. 31, 2012 Hedge Maturity Date December 2022 [Member] Alabama Power [Member] Cash Flow Hedging [Member] USD ($)
Energy-related derivative contracts
Net Purchased MWHs													(100,000)					(100,000)
Net Purchased mmBtu																			221,000,000	37,000,000	85,000,000	43,000,000	28,000,000	28,000,000
Longest Hedge Date																			2017	2017	2017	2017	2017	2012
Longest Non-Hedge Date													2012					2012	2017					2017
Notional amount of interest rate derivatives
Notional Amount																									$ 300
Notional Amount, Fair Value	350
Notional Amount of interest rate derivatives, Total	650
Interest Rate Received		0.0415																								3-month LIBOR
Interest Rate Paid		3-month LIBOR + 1.96%																								0.0290
Hedge Maturity Date		May 01, 2014																								Dec. 01, 2022
Fair Value Gain (Loss) March 31, 2012	4	14																								(10)
Total deferred gains and losses are expected to be amortized into earnings
Estimated Gain (Loss) to be Reclassified for the 12 Months Ending March 31, 2013	(16)		1	(3)	(1)	(1)						(11)
Total Deferred Gains (Losses) Amortized Through	2037		2035	2037	2020	2022	2022					2016
Notional amount of outstanding foreign currency derivatives
Notional Amount							24.9		18.1		6.8
Forward Rate								1.3209		1.3805
Hedge Maturity Date										Various through March 2014	Various through March 2014
Fair Value Gain (Loss) March 31, 2012

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Condensed Consolidated Statements of Income (Unaudited) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Revenues:
Retail revenues	$ 3,092,000,000	$ 3,396,000,000
Wholesale revenues	349,000,000	449,000,000
Other electric revenues	148,000,000	150,000,000
Other revenues	15,000,000	17,000,000
Total operating revenues	3,604,000,000	4,012,000,000
Operating Expenses:
Fuel	1,064,000,000	1,476,000,000
Purchased power	141,000,000	100,000,000
Other operations and maintenance	967,000,000	944,000,000
Depreciation and amortization	441,000,000	418,000,000
Taxes other than income taxes	225,000,000	220,000,000
Total operating expenses	2,838,000,000	3,158,000,000
Operating Income	766,000,000	854,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	31,000,000	35,000,000
Interest expense, net of amounts capitalized	(211,000,000)	(222,000,000)
Other income (expense), net	(2,000,000)	2,000,000
Total other income and (expense)	(182,000,000)	(185,000,000)
Earnings Before Income Taxes	584,000,000	669,000,000
Income taxes	200,000,000	231,000,000
Consolidated Net Income	384,000,000	438,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	16,000,000	16,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	368,000,000	422,000,000
Earnings per share (EPS) -
Basic EPS	$ 0.42	$ 0.50
Diluted EPS	$ 0.42	$ 0.49
Average number of shares of common stock outstanding (in millions)
Basic	868	848
Diluted	877	854
Cash dividends paid per share of common stock	$ 0.4725	$ 0.4550
Alabama Power [Member]
Operating Revenues:
Retail revenues	1,092,000,000	1,126,000,000
Wholesale revenues, non-affiliates	61,000,000	68,000,000
Wholesale revenues, affiliates	14,000,000	75,000,000
Other revenues	49,000,000	51,000,000
Total operating revenues	1,216,000,000	1,320,000,000
Operating Expenses:
Fuel	306,000,000	395,000,000
Purchased power, non-affiliates	15,000,000	11,000,000
Purchased power, affiliates	40,000,000	46,000,000
Other operations and maintenance	321,000,000	297,000,000
Depreciation and amortization	157,000,000	157,000,000
Taxes other than income taxes	86,000,000	85,000,000
Total operating expenses	925,000,000	991,000,000
Operating Income	291,000,000	329,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	5,000,000	5,000,000
Interest income	4,000,000	4,000,000
Interest expense, net of amounts capitalized	(73,000,000)	(74,000,000)
Other income (expense), net	(7,000,000)	(6,000,000)
Total other income and (expense)	(71,000,000)	(71,000,000)
Earnings Before Income Taxes	220,000,000	258,000,000
Income taxes	84,000,000	96,000,000
Consolidated Net Income	136,000,000	162,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	10,000,000	10,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	126,000,000	152,000,000
Georgia Power [Member]
Operating Revenues:
Retail revenues	1,594,000,000	1,815,000,000
Wholesale revenues, non-affiliates	66,000,000	83,000,000
Wholesale revenues, affiliates	3,000,000	11,000,000
Other revenues	82,000,000	80,000,000
Total operating revenues	1,745,000,000	1,989,000,000
Operating Expenses:
Fuel	440,000,000	677,000,000
Purchased power, non-affiliates	93,000,000	74,000,000
Purchased power, affiliates	159,000,000	163,000,000
Other operations and maintenance	434,000,000	422,000,000
Depreciation and amortization	188,000,000	173,000,000
Taxes other than income taxes	87,000,000	87,000,000
Total operating expenses	1,401,000,000	1,596,000,000
Operating Income	344,000,000	393,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	13,000,000	25,000,000
Interest expense, net of amounts capitalized	(91,000,000)	(96,000,000)
Other income (expense), net	(3,000,000)	(1,000,000)
Total other income and (expense)	(81,000,000)	(72,000,000)
Earnings Before Income Taxes	263,000,000	321,000,000
Income taxes	92,000,000	111,000,000
Consolidated Net Income	171,000,000	210,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	4,000,000	4,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	167,000,000	206,000,000
Gulf Power [Member]
Operating Revenues:
Retail revenues	238,520,000	274,826,000
Wholesale revenues, non-affiliates	27,118,000	31,019,000
Wholesale revenues, affiliates	36,364,000	4,135,000
Other revenues	14,243,000	14,628,000
Total operating revenues	316,245,000	324,608,000
Operating Expenses:
Fuel	121,088,000	131,782,000
Purchased power, non-affiliates	11,225,000	7,003,000
Purchased power, affiliates	2,513,000	16,618,000
Other operations and maintenance	75,230,000	80,509,000
Depreciation and amortization	33,307,000	31,756,000
Taxes other than income taxes	23,784,000	24,896,000
Total operating expenses	267,147,000	292,564,000
Operating Income	49,098,000	32,044,000
Other Income and (Expense):
Allowance for equity funds used during construction	1,237,000	2,135,000
Interest expense, net of amounts capitalized	(15,368,000)	(13,629,000)
Other income (expense), net	(1,009,000)	(549,000)
Total other income and (expense)	(15,140,000)	(12,043,000)
Earnings Before Income Taxes	33,958,000	20,001,000
Income taxes	11,741,000	6,759,000
Consolidated Net Income	22,217,000	13,242,000
Dividends on Preferred and Preference Stock of Subsidiaries	1,551,000	1,551,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	20,666,000	11,691,000
Mississippi Power [Member]
Operating Revenues:
Retail revenues	166,271,000	180,474,000
Wholesale revenues, non-affiliates	54,231,000	69,851,000
Wholesale revenues, affiliates	4,040,000	9,300,000
Other revenues	4,172,000	3,651,000
Total operating revenues	228,714,000	263,276,000
Operating Expenses:
Fuel	88,619,000	121,054,000
Purchased power, non-affiliates	1,943,000	1,010,000
Purchased power, affiliates	8,860,000	8,350,000
Other operations and maintenance	54,895,000	70,367,000
Depreciation and amortization	22,481,000	19,863,000
Taxes other than income taxes	21,703,000	17,481,000
Total operating expenses	198,501,000	238,125,000
Operating Income	30,213,000	25,151,000
Other Income and (Expense):
Allowance for equity funds used during construction	11,827,000	3,131,000
Interest income	120,000	342,000
Interest expense, net of amounts capitalized	(7,805,000)	(6,013,000)
Other income (expense), net	(242,000)	(403,000)
Total other income and (expense)	3,900,000	(2,943,000)
Earnings Before Income Taxes	34,113,000	22,208,000
Income taxes	8,425,000	7,158,000
Consolidated Net Income	25,688,000	15,050,000
Dividends on Preferred and Preference Stock of Subsidiaries	433,000	433,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	25,255,000	14,617,000
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	140,557,000	197,166,000
Wholesale revenues, affiliates	111,788,000	83,274,000
Other revenues	1,336,000	1,347,000
Total operating revenues	253,681,000	281,787,000
Operating Expenses:
Fuel	89,078,000	102,715,000
Purchased power, non-affiliates	20,650,000	8,942,000
Purchased power, affiliates	2,340,000	15,099,000
Other operations and maintenance	48,389,000	42,754,000
Depreciation and amortization	31,913,000	30,167,000
Taxes other than income taxes	4,968,000	4,763,000
Total operating expenses	197,338,000	204,440,000
Operating Income	56,343,000	77,347,000
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13,642,000)	(18,829,000)
Other income (expense), net	30,000	59,000
Total other income and (expense)	(13,612,000)	(18,770,000)
Earnings Before Income Taxes	42,731,000	58,577,000
Income taxes	13,415,000	20,834,000
Consolidated Net Income	$ 29,316,000	$ 37,743,000

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Segment and Related Information (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Financial data for business segments
Operating revenues	$ 3,604,000,000	$ 4,012,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	368,000,000	422,000,000
Total Assets	59,874,000,000		59,267,000,000
Electric Utilities [Member]
Financial data for business segments
Operating revenues	3,589,000,000	3,994,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	369,000,000	423,000,000
Total Assets	59,213,000,000		58,076,000,000
Traditional Operating Companies [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	3,449,000,000	3,810,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	339,000,000	385,000,000
Total Assets	55,698,000,000		54,622,000,000
Southern Power [Member]
Segment and Related Information (Textual) [Abstract]
Southern Power's revenues from sales to the traditional operating companies	112,000,000	83,000,000
Southern Power [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	254,000,000	282,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	29,000,000	38,000,000
Total Assets	3,596,000,000		3,581,000,000
Eliminations [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	(114,000,000)	(98,000,000)
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	1,000,000
Total Assets	(81,000,000)		(127,000,000)
All Other [Member]
Financial data for business segments
Operating revenues	38,000,000	38,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	2,000,000	1,000,000
Total Assets	1,086,000,000		1,592,000,000
Eliminations [Member]
Financial data for business segments
Operating revenues	(23,000,000)	(20,000,000)
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	(3,000,000)	(2,000,000)
Total Assets	$ (425,000,000)		$ (401,000,000)

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Common stock, par value per share	$ 5	$ 5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Common stock, shares issued	869,000,000	866,000,000
Treasury shares at cost	500,000	500,000
Alabama Power [Member]
Common stock, par value per share	$ 40	$ 40
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares outstanding	30,537,500	30,537,500
Georgia Power [Member]
Common stock, no par value
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	9,261,500	9,261,500
Gulf Power [Member]
Common stock, no par value
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	4,542,717	4,142,717
Mississippi Power [Member]
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]
Amortization expense on other intangible assets	$ 1,671	$ 1,476
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

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Financing (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Credit arrangements by company
Expires, 2012	$ 327
Expires, 2013	120
Expires, 2014 and Beyond	4,730
Total	5,177
Unused	5,172
Executable Term-Loans, One Year	176
Executable Term-Loans, Two Years	41
Due Within One Year, Term Out	217
Due Within One Year, No Term Out	171
Southern Company [Member]
Credit arrangements by company
Expires, 2014 and Beyond	1,000
Total	1,000
Unused	1,000
Alabama Power [Member]
Credit arrangements by company
Expires, 2012	121
Expires, 2013	35
Expires, 2014 and Beyond	1,150
Total	1,306
Unused	1,306
Executable Term-Loans, One Year	51
Due Within One Year, Term Out	51
Due Within One Year, No Term Out	71
Georgia Power [Member]
Credit arrangements by company
Expires, 2014 and Beyond	1,750
Total	1,750
Unused	1,745
Gulf Power [Member]
Credit arrangements by company
Expires, 2012	75
Expires, 2013	35
Expires, 2014 and Beyond	165
Total	275
Unused	275
Executable Term-Loans, One Year	75
Due Within One Year, Term Out	75
Due Within One Year, No Term Out	35
Mississippi Power [Member]
Credit arrangements by company
Expires, 2012	106
Expires, 2013	25
Expires, 2014 and Beyond	165
Total	296
Unused	296
Executable Term-Loans, One Year	25
Executable Term-Loans, Two Years	41
Due Within One Year, Term Out	66
Due Within One Year, No Term Out	65
Southern Power [Member]
Credit arrangements by company
Expires, 2014 and Beyond	500
Total	500
Unused	500
Other Subsidiaries [Member]
Credit arrangements by company
Expires, 2012	25
Expires, 2013	25
Total	50
Unused	50
Executable Term-Loans, One Year	25
Due Within One Year, Term Out	$ 25

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2012

Retirement Benefits [Abstract]

Pension Plans and Postretirement Plans

	000000	000000	000000	000000	000000
Pension Plans	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended March 31, 2012
Service cost	$   50	$ 11	$ 15	$   2	$ 2
Interest cost	98	23	35	4	5
Expected return on plan assets	(145)	(40)	(55)	(6)	(6)
Net amortization	31	8	11	1	1
Net cost (income)	$   34	$   2	$   6	$   1	$ 2
Three Months Ended March 31, 2011
Service cost	$   46	$ 11	$ 14	$   2	$ 2
Interest cost	98	24	36	4	4
Expected return on plan assets	(152)	(43)	(59)	(7)	(6)
Net amortization	13	3	5	1	1
Net cost (income)	$     5	$  (5)	$   (4)	$—	$ 1
Postretirement Benefits	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended March 31, 2012
Service cost	$   5	$ 1	$   1	$—	$—
Interest cost	21	5	9	1	1
Expected return on plan assets	(15)	(6)	(7)	—	—
Net amortization	5	2	3	—	—
Net cost (income)	$ 16	$ 2	$   6	$  1	$  1
Three Months Ended March 31, 2011
Service cost	$   5	$ 1	$   2	$—	$—
Interest cost	23	6	10	1	1
Expected return on plan assets	(16)	(6)	(8)	—	—
Net amortization	5	2	3	—	—
Net cost (income)	$ 17	$ 3	$   7	$1	$  1

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Retirement Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	$ 50	$ 46
Interest cost	98	98
Expected return on plan assets	(145)	(152)
Net amortization	31	13
Net cost (income)	34	5
Pension Plans [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	11	11
Interest cost	23	24
Expected return on plan assets	(40)	(43)
Net amortization	8	3
Net cost (income)	2	(5)
Pension Plans [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	15	14
Interest cost	35	36
Expected return on plan assets	(55)	(59)
Net amortization	11	5
Net cost (income)	6	(4)
Pension Plans [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	2
Interest cost	4	4
Expected return on plan assets	(6)	(7)
Net amortization	1	1
Net cost (income)	1
Pension Plans [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	2
Interest cost	5	4
Expected return on plan assets	(6)	(6)
Net amortization	1	1
Net cost (income)	2	1
Other Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost	5	5
Interest cost	21	23
Expected return on plan assets	(15)	(16)
Net amortization	5	5
Net cost (income)	16	17
Other Postretirement Benefits [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	1
Interest cost	5	6
Expected return on plan assets	(6)	(6)
Net amortization	2	2
Net cost (income)	2	3
Other Postretirement Benefits [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	2
Interest cost	9	10
Expected return on plan assets	(7)	(8)
Net amortization	3	3
Net cost (income)	6	7
Other Postretirement Benefits [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Interest cost	1	1
Net cost (income)	1	1
Other Postretirement Benefits [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Interest cost	1	1
Net cost (income)	$ 1	$ 1

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2012

Derivatives [Abstract]

Energy-related derivative contracts

	Power			Gas
	Net (Sold) MWHs	Longest Hedge Date	Longest Non-Hedge Date	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)			(in millions)
Southern Company	(0.1)	—	2012	221	2017	2017
Alabama Power	—	—	—	37	2017	—
Georgia Power	—	—	—	85	2017	—
Gulf Power	—	—	—	43	2017	—
Mississippi Power	—	—	—	28	2017	—
Southern Power	(0.1)	—	2012	28	2012	2017

Notional amount of interest rate derivatives

	Notional Amount	Interest Rate   Received	Interest Rate   Paid	Hedge Maturity Date	Fair Value Gain (Loss)   March 31, 2012
	(in millions)				(in millions)
Cash flow hedges of forecasted transactions
Alabama Power	$300	3-month LIBOR	2.90%*	December 2022	$(10)
Fair value hedges of existing debt
Southern Company	350	4.15%	3-month LIBOR + 1.96%*	May 2014	14
Total	$650				$  4

* Weighted Average

Total deferred gains and losses are expected to be amortized into earnings

Registrant	Estimated Gain (Loss) to be Reclassified for the 12 Months Ending March 31, 2013	Total Deferred Gains (Losses) Amortized Through
	(in millions)
Southern Company	$(16)	2037
Alabama Power	1	2035
Georgia Power	(3)	2037
Gulf Power	(1)	2020
Mississippi Power	(1)	2022
Southern Power	(11)	2016

Outstanding foreign currency derivatives

	Notional Amount	Forward Rate	Hedge Maturity Date	Fair Value Gain (Loss) March 31, 2012
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR6.8	1.3805 Dollars per Euro*	Various through March 2014	$—
Derivatives not designated as hedges
Mississippi Power	EUR18.1	1.3209 Dollars per Euro*	N/A	—
Total	EUR24.9			$—

* Weighted Average

Fair value of energy-related derivatives and interest rate derivatives

Asset Derivatives at March 31, 2012
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern   Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$17	$—	$17	$—	$—
Other deferred charges and assets	6	1	5	—	—
Total derivatives designated as hedging instruments for regulatory purposes	$23	$  1	$22	$—	$—	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	8	—	—	—	—	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$14	$—	$—	$—	$—	$—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	$  1	$—	$—	$—	$—	$  1
Foreign currency derivatives
Other current assets	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$  2	$—	$—	$—	$  1	$  1
Total asset derivatives	$39	$  1	$22	$—	$  1	$  1

Liability Derivatives at March 31, 2012
	Fair Value
Derivative Category and Balance Sheet Location	Southern   Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern   Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$191	$41	$  80	$31	$39
Other deferred credits and liabilities	81	13	28	23	17
Total derivatives designated as hedging instruments for regulatory purposes	$272	$54	$108	$54	$56	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities	$    2	$—	$  —	$—	$—	$    2
Interest rate derivatives:
Liabilities from risk management activities	10	10	—	—	—	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$  12	$10	$  —	$—	$—	$    2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$  15	$—	$  —	$—	$—	$  15
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$  16	$—	$  —	$—	$  1	$  15
Total liability derivatives	$300	$64	$108	$54	$57	$  17

Pre-tax effect of unrealized derivative gains (losses)

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$(191)	$(41)	$(80)	$(31)	$(39)
Other regulatory assets, deferred	(81)	(13)	(28)	(23)	(17)
Other regulatory liabilities, current	17	—	17	—	—
Other regulatory liabilities, deferred	6	1	—	—	—
Other deferred credits and liabilities*	—	—	5	—	—
Total energy-related derivative gains (losses)	$(249)	$(53)	$(86)	$(54)	$(56)

* Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

Pre-tax effect of derivatives designated as cash flow hedging instruments

Derivatives in Cash Flow	Gain (Loss) Recognized in OCI on Derivative		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Hedging Relationships	(Effective Portion)		Statements of Income Location	Amount
	2012	2011		2012	2011
	(in millions)			(in millions)
Southern Company
Energy-related derivatives	$     (1)	$       1	Fuel	$            —	$            —
Interest rate derivatives	6	4	Interest expense, net of amounts capitalized	(3)	(5)
Total	$      5	$       5		$            (3)	$            (5)
Alabama Power
Interest rate derivatives	$      7	$       4	Interest expense, net of amounts capitalized	$            —	$            —
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (1)	$            (1)
Gulf Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Mississippi Power
Interest rate derivatives	$    (1)	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Southern Power
Energy-related derivatives	$    (1)	$       1	Fuel	$            —	$            —
Interest rate derivatives	—	—	Interest expense, net of amounts capitalized	(2)	(3)
Total	$    (1)	$       1		$            (2)	$            (3)

Fair value of derivative liabilities with contingent features

	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern Power
			(in millions)
Derivative liabilities	$36	$9	$10	$7	$6	$4

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Consolidated Net Income	$ 384,000,000	$ 438,000,000
Net Income After Dividends on Preferred and Preference Stock	368,000,000	422,000,000
Qualifying hedges:
Changes in fair value, net of tax	3,000,000	3,000,000
Reclassification adjustment for amounts included in net income, net of tax	2,000,000	3,000,000
Marketable securities:
Change in fair value, net of tax of $- and $-, respectively		(1,000,000)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1 and $1, respectively	1,000,000	(1,000,000)
Total other comprehensive income (loss)	6,000,000	4,000,000
Dividends on preferred and preference stock of subsidiaries	(16,000,000)	(16,000,000)
Consolidated Comprehensive Income	374,000,000	426,000,000
Alabama Power [Member]
Consolidated Net Income	136,000,000	162,000,000
Net Income After Dividends on Preferred and Preference Stock	126,000,000	152,000,000
Qualifying hedges:
Changes in fair value, net of tax	4,000,000	2,000,000
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	4,000,000	2,000,000
Dividends on preferred and preference stock of subsidiaries	(10,000,000)	(10,000,000)
Consolidated Comprehensive Income	130,000,000	154,000,000
Georgia Power [Member]
Consolidated Net Income	171,000,000	210,000,000
Net Income After Dividends on Preferred and Preference Stock	167,000,000	206,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	1,000,000
Pension and other postretirement benefit plans:
Dividends on preferred and preference stock of subsidiaries	(4,000,000)	(4,000,000)
Consolidated Comprehensive Income	168,000,000	207,000,000
Gulf Power [Member]
Consolidated Net Income	22,217,000	13,242,000
Net Income After Dividends on Preferred and Preference Stock	20,666,000	11,691,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	143,000	143,000
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	143,000	143,000
Dividends on preferred and preference stock of subsidiaries	(1,551,000)	(1,551,000)
Consolidated Comprehensive Income	20,809,000	11,834,000
Mississippi Power [Member]
Consolidated Net Income	25,688,000	15,050,000
Net Income After Dividends on Preferred and Preference Stock	25,255,000	14,617,000
Qualifying hedges:
Changes in fair value, net of tax	(478,000)	(2,000)
Reclassification adjustment for amounts included in net income, net of tax	26,000
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	(452,000)	(2,000)
Dividends on preferred and preference stock of subsidiaries	(433,000)	(433,000)
Consolidated Comprehensive Income	24,803,000	14,615,000
Southern Power [Member]
Consolidated Net Income	29,316,000	37,743,000
Qualifying hedges:
Changes in fair value, net of tax	(274,000)	643,000
Reclassification adjustment for amounts included in net income, net of tax	1,510,000	1,630,000
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1,236,000	2,273,000
Consolidated Comprehensive Income	$ 30,552,000	$ 40,016,000

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Activities:
Consolidated Net Income	$ 384,000,000	$ 438,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	529,000,000	501,000,000
Deferred income taxes	104,000,000	174,000,000
Allowance for equity funds used during construction	(31,000,000)	(35,000,000)
Pension, postretirement, and other employee benefits	16,000,000	(11,000,000)
Stock based compensation expense	25,000,000	21,000,000
Other, net	2,000,000	(16,000,000)
Changes in certain current assets and liabilities --
-Receivables	372,000,000	276,000,000
-Fossil fuel stock	(218,000,000)	(42,000,000)
-Other current assets	(60,000,000)	(77,000,000)
-Accounts payable	(136,000,000)	(108,000,000)
-Accrued taxes	(167,000,000)	131,000,000
-Accrued compensation	(305,000,000)	(277,000,000)
-Other current liabilities	53,000,000	23,000,000
Net cash provided from operating activities	568,000,000	998,000,000
Investing Activities:
Property additions	(1,231,000,000)	(1,086,000,000)
Distribution of restricted cash		61,000,000
Nuclear decommissioning trust fund purchases	(336,000,000)	(928,000,000)
Nuclear decommissioning trust fund sales	334,000,000	924,000,000
Proceeds from property sales	2,000,000	14,000,000
Cost of removal, net of salvage	(32,000,000)	(15,000,000)
Change in construction payables	(156,000,000)	136,000,000
Other investing activities	(8,000,000)	10,000,000
Net cash used for investing activities	(1,427,000,000)	(884,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	174,000,000	(54,000,000)
Proceeds --
Long-term debt issuances	1,400,000,000	937,000,000
Interest-bearing refundable deposit related to asset sale	150,000,000
Common stock issuances	116,000,000	193,000,000
Redemptions --
Long-term debt	(827,000,000)	(824,000,000)
Payment of common stock dividends	(410,000,000)	(385,000,000)
Payment of dividends on preferred and preference stock of subsidiaries	(16,000,000)	(16,000,000)
Other financing activities	1,000,000	(2,000,000)
Net cash provided from (used for) financing activities	588,000,000	(151,000,000)
Net Change in Cash and Cash Equivalents	(271,000,000)	(37,000,000)
Cash and Cash Equivalents at Beginning of Period	1,315,000,000	447,000,000
Cash and Cash Equivalents at End of Period	1,044,000,000	410,000,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2012 and 2011, respectively)	178,000,000	197,000,000
Income taxes (net of refunds)	2,000,000	(357,000,000)
Noncash transactions - accrued property additions at end of period	420,000,000	531,000,000
Alabama Power [Member]
Operating Activities:
Consolidated Net Income	136,000,000	162,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	189,000,000	185,000,000
Deferred income taxes	31,000,000	59,000,000
Allowance for equity funds used during construction	(5,000,000)	(5,000,000)
Pension, postretirement, and other employee benefits	(1,000,000)	(11,000,000)
Stock based compensation expense	4,000,000	3,000,000
Other, net	(10,000,000)	1,000,000
Changes in certain current assets and liabilities --
-Receivables	89,000,000	51,000,000
-Fossil fuel stock	(81,000,000)	3,000,000
-Materials and supplies	2,000,000	10,000,000
-Other current assets	(51,000,000)	(69,000,000)
-Accounts payable	(149,000,000)	(153,000,000)
-Accrued taxes	43,000,000	160,000,000
-Accrued compensation	(63,000,000)	(67,000,000)
-Other current liabilities	6,000,000	(2,000,000)
Net cash provided from operating activities	140,000,000	327,000,000
Investing Activities:
Property additions	(244,000,000)	(213,000,000)
Distribution of restricted cash from pollution control revenue bonds		11,000,000
Nuclear decommissioning trust fund purchases	(49,000,000)	(97,000,000)
Nuclear decommissioning trust fund sales	49,000,000	97,000,000
Cost of removal, net of salvage	(6,000,000)	(8,000,000)
Change in construction payables	14,000,000	(2,000,000)
Other investing activities	1,000,000	(12,000,000)
Net cash used for investing activities	(235,000,000)	(224,000,000)
Proceeds --
Capital contributions from parent company	5,000,000	5,000,000
Senior note issuances	250,000,000	250,000,000
Redemptions --
Pollution control revenue bonds	(1,000,000)
Senior notes		(200,000,000)
Payment of preferred and preference stock dividends	(10,000,000)	(10,000,000)
Payment of common stock dividends	(135,000,000)	(138,000,000)
Other financing activities	(3,000,000)	(5,000,000)
Net cash provided from (used for) financing activities	106,000,000	(98,000,000)
Net Change in Cash and Cash Equivalents	11,000,000	5,000,000
Cash and Cash Equivalents at Beginning of Period	344,000,000	154,000,000
Cash and Cash Equivalents at End of Period	355,000,000	159,000,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2012 and 2011, respectively)	66,000,000	72,000,000
Income taxes (net of refunds)	22,000,000	(110,000,000)
Noncash transactions - accrued property additions at end of period	32,000,000	26,000,000
Georgia Power [Member]
Operating Activities:
Consolidated Net Income	171,000,000	210,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	229,000,000	210,000,000
Deferred income taxes	38,000,000	56,000,000
Allowance for equity funds used during construction	(13,000,000)	(25,000,000)
Other, net	33,000,000	(14,000,000)
Changes in certain current assets and liabilities --
-Receivables	258,000,000	122,000,000
-Fossil fuel stock	(122,000,000)	(30,000,000)
-Prepaid income taxes	10,000,000	80,000,000
-Other current assets	(4,000,000)	(14,000,000)
-Accounts payable	(62,000,000)	(50,000,000)
-Accrued taxes	(206,000,000)	(194,000,000)
-Accrued compensation	(80,000,000)	(65,000,000)
-Other current liabilities	60,000,000	64,000,000
Net cash provided from operating activities	312,000,000	350,000,000
Investing Activities:
Property additions	(476,000,000)	(513,000,000)
Nuclear decommissioning trust fund purchases	(287,000,000)	(830,000,000)
Nuclear decommissioning trust fund sales	285,000,000	827,000,000
Cost of removal, net of salvage	(15,000,000)	1,000,000
Change in construction payables, net of joint owner portion	(203,000,000)	93,000,000
Other investing activities	15,000,000	(6,000,000)
Net cash used for investing activities	(681,000,000)	(428,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	99,000,000	(62,000,000)
Proceeds --
Capital contributions from parent company	9,000,000	171,000,000
Pollution control revenue bonds issuances		137,000,000
Senior note issuances	750,000,000	300,000,000
Other long-term debt issuances		250,000,000
Redemptions --
Pollution control revenue bonds		(84,000,000)
Senior notes		(101,000,000)
Other long-term debt	(250,000,000)	(300,000,000)
Payment of preferred and preference stock dividends	(4,000,000)	(4,000,000)
Payment of common stock dividends	(227,000,000)	(224,000,000)
Other financing activities	(8,000,000)	(2,000,000)
Net cash provided from (used for) financing activities	369,000,000	81,000,000
Net Change in Cash and Cash Equivalents		3,000,000
Cash and Cash Equivalents at Beginning of Period	13,000,000	8,000,000
Cash and Cash Equivalents at End of Period	13,000,000	11,000,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2012 and 2011, respectively)	58,000,000	65,000,000
Income taxes (net of refunds)	28,000,000	(77,000,000)
Noncash transactions - accrued property additions at end of period	178,000,000	350,000,000
Gulf Power [Member]
Operating Activities:
Consolidated Net Income	22,217,000	13,242,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	34,844,000	33,294,000
Deferred income taxes	32,505,000	6,249,000
Allowance for equity funds used during construction	(1,237,000)	(2,135,000)
Pension, postretirement, and other employee benefits	1,315,000	(1,256,000)
Stock based compensation expense	685,000	518,000
Other, net	5,478,000	(3,793,000)
Changes in certain current assets and liabilities --
-Receivables	14,754,000	35,336,000
-Prepayments	1,559,000	1,156,000
-Fossil fuel stock	1,543,000	(14,941,000)
-Materials and supplies	(1,476,000)	(726,000)
-Prepaid income taxes	17,324,000	28,889,000
-Other current assets		7,000
-Accounts payable	(21,516,000)	(8,863,000)
-Accrued taxes	(1,453,000)	4,053,000
-Accrued compensation	(9,190,000)	(10,000,000)
-Over recovered regulatory clause revenues	14,516,000	687,000
-Other current liabilities	5,637,000	5,440,000
Net cash provided from operating activities	117,505,000	87,157,000
Investing Activities:
Property additions	(94,879,000)	(94,239,000)
Cost of removal, net of salvage	(9,342,000)	(5,314,000)
Change in construction payables	7,773,000	3,171,000
Payments pursuant to long-term service agreements	(2,274,000)	(2,198,000)
Other investing activities	(76,000)	68,000
Net cash used for investing activities	(98,798,000)	(98,512,000)
Financing Activities:
Increase (decrease) in notes payable, net	(27,338,000)	(6,620,000)
Proceeds --
Capital contributions from parent company	732,000	809,000
Common stock issuances	40,000,000	50,000,000
Redemptions --
Senior notes	(16,000)	(125,000)
Payment of preferred and preference stock dividends	(1,551,000)	(1,551,000)
Payment of common stock dividends	(28,950,000)	(27,500,000)
Other financing activities	198,000	110,000
Net cash provided from (used for) financing activities	(16,925,000)	15,123,000
Net Change in Cash and Cash Equivalents	1,782,000	3,768,000
Cash and Cash Equivalents at Beginning of Period	17,328,000	16,434,000
Cash and Cash Equivalents at End of Period	19,110,000	20,202,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2012 and 2011, respectively)	9,352,000	8,284,000
Income taxes (net of refunds)	(35,742,000)	(29,557,000)
Noncash transactions - accrued property additions at end of period	28,788,000	17,882,000
Mississippi Power [Member]
Operating Activities:
Consolidated Net Income	25,688,000	15,050,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	21,931,000	21,442,000
Deferred income taxes	(1,210,000)	10,015,000
Convertible investment tax credits	13,974,000	9,750,000
Allowance for equity funds used during construction	(11,827,000)	(3,131,000)
Pension, postretirement, and other employee benefits	2,268,000	1,037,000
Stock based compensation expense	957,000	813,000
Hedge Settlements	(15,983,000)
Other, net	(1,127,000)	(1,363,000)
Changes in certain current assets and liabilities --
-Receivables	14,536,000	11,592,000
-Fossil fuel stock	(16,188,000)	(538,000)
-Materials and supplies	(538,000)	(317,000)
-Prepaid income taxes	4,168,000	15,976,000
-Other current assets	(4,357,000)	1,649,000
-Accounts payable	(11,558,000)	17,538,000
-Accrued taxes	(31,434,000)	(31,213,000)
-Accrued compensation	(10,803,000)	(9,556,000)
-Over recovered regulatory clause revenues	12,627,000	7,756,000
-Other current liabilities	9,480,000	(149,000)
Net cash provided from operating activities	604,000	66,351,000
Investing Activities:
Property additions	(370,923,000)	(148,917,000)
Distribution of restricted cash		50,000,000
Cost of removal, net of salvage	(1,149,000)	(2,830,000)
Change in construction payables	30,080,000	33,291,000
Capital grant proceeds	1,816,000	16,912,000
Other investing activities	(4,207,000)	(834,000)
Net cash used for investing activities	(344,383,000)	(52,378,000)
Proceeds --
Capital contributions from parent company	150,735,000	50,610,000
Interest-bearing refundable deposit related to asset sale	150,000,000
Senior note issuances	400,000,000
Redemptions --
Capital leases	(377,000)	(349,000)
Other long-term debt	(75,000,000)	(130,000,000)
Payment of preferred and preference stock dividends	(433,000)	(433,000)
Payment of common stock dividends	(26,700,000)	(18,875,000)
Other financing activities	715,000	(312,000)
Net cash provided from (used for) financing activities	598,940,000	(99,359,000)
Net Change in Cash and Cash Equivalents	255,161,000	(85,386,000)
Cash and Cash Equivalents at Beginning of Period	211,585,000	160,779,000
Cash and Cash Equivalents at End of Period	466,746,000	75,393,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2012 and 2011, respectively)		6,135,000
Income taxes (net of refunds)	(11,994,000)	(32,294,000)
Noncash transactions - accrued property additions at end of period	165,982,000	72,114,000
Southern Power [Member]
Operating Activities:
Consolidated Net Income	29,316,000	37,743,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	34,887,000	33,580,000
Deferred income taxes	9,917,000	8,601,000
Convertible investment tax credits	(3,900,000)	38,068,000
Deferred revenues	(16,686,000)	(21,476,000)
Mark-to-market adjustments	6,467,000	(63,000)
Other, net	1,326,000	1,752,000
Changes in certain current assets and liabilities --
-Receivables	12,400,000	20,759,000
-Fossil fuel stock	(755,000)	625,000
-Materials and supplies	(1,167,000)	253,000
-Prepaid income taxes	(5,105,000)	15,744,000
-Other current assets	(2,083,000)	(137,000)
-Accounts payable	(14,590,000)	(21,645,000)
-Accrued taxes	4,375,000	4,888,000
Accrued interest	(10,172,000)	(12,281,000)
-Other current liabilities	(2,000)	(519,000)
Net cash provided from operating activities	44,228,000	105,892,000
Investing Activities:
Property additions	(32,450,000)	(113,518,000)
Change in construction payables	(999,000)	43,259,000
Payments pursuant to long-term service agreements	(11,415,000)	(11,320,000)
Other investing activities	(2,848,000)	(3,165,000)
Net cash used for investing activities	(47,712,000)	(84,744,000)
Financing Activities:
Increase (decrease) in notes payable, net	20,165,000	(20,360,000)
Proceeds --
Capital contributions from parent company	1,219,000	17,179,000
Redemptions --
Other long-term debt	(150,000)	(3,066,000)
Payment of common stock dividends	(31,750,000)	(22,800,000)
Other financing activities	25,000	38,000
Net cash provided from (used for) financing activities	(10,491,000)	(29,009,000)
Net Change in Cash and Cash Equivalents	(13,975,000)	(7,861,000)
Cash and Cash Equivalents at Beginning of Period	16,943,000	14,204,000
Cash and Cash Equivalents at End of Period	2,968,000	6,343,000
Supplemental Cash Flow Information:
Interest (net capitalized for 2012 and 2011, respectively)	20,966,000	26,993,000
Income taxes (net of refunds)	10,820,000	(44,721,000)
Noncash transactions - accrued property additions at end of period	$ 31,591,000	$ 78,567,000

XML

Segment and Related Information

3 Months Ended

Mar. 31, 2012

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 in the Southeast by the four traditional operating companies and Southern Power. Southern Power’s revenues from sales to the traditional operating companies were $112 million and $83 million for the three months ended March 31, 2012 and March 31, 2011, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:

	Electric Utilities
	Traditional         Operating         Companies	Southern         Power	Eliminations	Total	All   Other	Eliminations	Consolidated
	(in millions)
Three Months Ended March 31, 2012:
Operating revenues	$  3,449	$   254	$            (114)	$  3,589	$     38	$  (23)	$  3,604
Segment net income *	339	29	1	369	2	(3)	368
Total assets at March 31, 2012	$55,698	$3,596	$              (81)	$59,213	$1,086	$(425)	$59,874
Three Months Ended March 31, 2011:
Operating revenues	$  3,810	$   282	$              (98)	$  3,994	$     38	$  (20)	$  4,012
Segment net income (loss)*	385	38	—	423	1	(2)	422
Total assets at December 31, 2011	$54,622	$3,581	$            (127)	$58,076	$1,592	$(401)	$59,267

* 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 March 31, 2012	$3,092	$349	$148	$3,589
Three Months Ended March 31, 2011	$3,396	$449	$149	$3,994

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	868,690,126

XML

Fair Value Measurements (Policies)

3 Months Ended

Mar. 31, 2012

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 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 traditional operating companies and Southern Power 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 traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for 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 and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions, are reflected in earnings.

• Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At March 31, 2012, the net volume of energy-related derivative contracts for power and natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

	Power			Gas
	Net (Sold) MWHs	Longest Hedge Date	Longest Non-Hedge Date	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)			(in millions)
Southern Company	(0.1)	—	2012	221	2017	2017
Alabama Power	—	—	—	37	2017	—
Georgia Power	—	—	—	85	2017	—
Gulf Power	—	—	—	43	2017	—
Mississippi Power	—	—	—	28	2017	—
Southern Power	(0.1)	—	2012	28	2012	2017

In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 9 million mmBtu for Southern Company, 4 million mmBtu for Georgia Power, 2 million mmBtu for Southern Power, and is 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 March 31, 2013 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 March 31, 2012, the following interest rate derivatives were outstanding:

	Notional Amount	Interest Rate   Received	Interest Rate   Paid	Hedge Maturity Date	Fair Value Gain (Loss)   March 31, 2012
	(in millions)				(in millions)
Cash flow hedges of forecasted transactions
Alabama Power	$300	3-month LIBOR	2.90%*	December 2022	$(10)
Fair value hedges of existing debt
Southern Company	350	4.15%	3-month LIBOR + 1.96%*	May 2014	14
Total	$650				$  4

* 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 March 31, 2013, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.

Registrant	Estimated Gain (Loss) to be Reclassified for the 12 Months Ending March 31, 2013	Total Deferred Gains (Losses) Amortized Through
	(in millions)
Southern Company	$(16)	2037
Alabama Power	1	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 typically recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

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Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net cash paid for capitalized interest	$ 21,000	$ 17,000
Alabama Power [Member]
Net cash paid for capitalized interest	2,000	2,000
Georgia Power [Member]
Net cash paid for capitalized interest	6,000	9,000
Gulf Power [Member]
Net cash paid for capitalized interest	493	851
Mississippi Power [Member]
Interest paid	5,965	7,129
Net cash paid for capitalized interest	6,565	994
Southern Power [Member]
Net cash paid for capitalized interest	$ 6,556	$ 4,240

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Stockholder's Equity

3 Months Ended

Mar. 31, 2012

Stockholders' Equity [Abstract]

STOCKHOLDER'S 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 information on the stock option and performance share plans. The effects of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended March 31, 2012	Three Months Ended March 31, 2011
	(in millions)
As reported shares	868	848
Effect of options and performance share award units	9	6
Diluted shares	877	854

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 1 million and 7 million for the three months ended March 31, 2012 and 2011, respectively.

Changes in Stockholders’ Equity

The following table presents year-to-date changes in stockholders’ equity of Southern Company:

	Number of Common Shares		Common Stockholders’	Preferred and Preference Stock of	Total     Stockholders’
	Issued	Treasury	Equity	Subsidiaries	Equity
	(in thousands)			(in millions)
Balance at December 31, 2011	865,664	(539)	$17,578	$707	$18,285
Net income after dividends on preferred and preference stock	—	—	368	—	368
Other comprehensive income (loss)	—	—	6	—	6
Stock issued	3,571	—	157	—	157
Cash dividends on common stock	—	—	(410)	—	(410)
Other	—	(6)	—	—	—
Balance at March 31, 2012	869,235	(545)	$17,699	$707	$18,406
Balance at December 31, 2010	843,814	(474)	$16,202	$707	$16,909
Net income after dividends on preferred and preference stock	—	—	422	—	422
Other comprehensive income (loss)	—	—	4	—	4
Stock issued	5,784	—	222	—	222
Cash dividends on common stock	—	—	(385)	—	(385)
Other	—	(1)	—	—	—
Balance at March 31, 2011	849,598	(475)	$16,465	$707	$17,172

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

(C) FAIR VALUE MEASUREMENTS

As of March 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
As of March 31, 2012:	Quoted Prices   in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$     —	$  24	$—		$     24
Interest rate derivatives	—	14	—		14
Foreign currency derivatives	—	1	—		1
Nuclear decommissioning trusts (a)	490	788	—		1,278
Cash equivalents and restricted cash	862	—	—		862
Other investments	4	50	15		69
Total	$1,356	$877	$15		$2,248
Liabilities:
Energy-related derivatives	$     —	$289	$—		$   289
Interest rate derivatives	—	10	—		10
Foreign currency derivatives	—	1	—		1
Total	$     —	$300	$—		$   300
Alabama Power
Assets:
Energy-related derivatives	$     —	$    1	$—		$       1
Nuclear decommissioning trusts: (b)
Domestic equity	283	63	—		346
Foreign equity (d)	27	56	—		83
U.S. Treasury and government agency securities	15	8	—		23
Corporate bonds	—	99	—		99
Mortgage and asset backed securities	—	26	—		26
Other	—	10	—		10
Cash equivalents and restricted cash	234	—	—		234
Total	$   559	$263	$—		$   822
Liabilities:
Energy-related derivatives	$     —	$  54	$—		$     54
Interest rate derivatives	—	10	—		10
Total	$     —	$  64	$—		$     64

	Fair Value Measurements Using
As of March 31, 2012:	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$  —	$  22	$  —	$  22
Nuclear decommissioning trusts: (c)
Domestic equity	165	1	—	166
Foreign equity (d)	—	109	—	109
U.S. Treasury and government agency securities	—	52	—	52
Municipal bonds	—	83	—	83
Corporate bonds	—	123	—	123
Mortgage and asset backed securities	—	127	—	127
Other	—	31	—	31
Total	$165	$548	$  —	$713
Liabilities:
Energy-related derivatives	$  —	$108	$  —	$108
Gulf Power
Assets:
Cash equivalents	$  15	$  —	$  —	$  15
Liabilities:
Energy-related derivatives	$  —	$  54	$  —	$  54
Mississippi Power
Assets:
Foreign currency derivatives	$  —	$    1	$  —	$    1
Cash equivalents	439	—	—	439
Total	$439	$    1	$  —	$440
Liabilities:
Energy-related derivatives	$  —	$  56	$  —	$  56
Foreign currency derivatives	—	1	—	1
Total	$  —	$  57	$  —	$  57
Southern Power
Assets:
Energy-related derivatives	$  —	$    1	$  —	$    1
Liabilities:
Energy-related derivatives	$  —	$  17	$  —	$  17

(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 March 31, 2012, approximately $41 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.

(d) Level 1 securities consist of actively traded stocks, while Level 2 securities consist of pooled funds.

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 March 31, 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

As of March 31, 2012:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	12	None	Daily	1 to 3 days
Other — commingled funds		87	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		93	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		862	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Other — commingled funds		56	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		93	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		234	None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds		12	None	Daily	1 to 3 days
Other — commingled funds		31	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds		15	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds		439	None	Daily	Not applicable

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC’s regulations. The 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 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 may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months ended March 31, 2012, the increase in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $86 million for Southern Company, $49 million for Alabama Power, and $37 million for Georgia Power.

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.

At March 31, 2012, 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	$20,843	$25,499
Alabama Power	$  6,380	$  7,789
Georgia Power	$  8,918	$11,837
Gulf Power	$  1,236	$  1,349
Mississippi Power	$  1,668	$  1,740
Southern Power	$  1,303	$  1,393

The fair values were Level 2 and are based on quoted market prices for the same or similar issues or on the current rates offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.

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Effective Tax Rate and Unrecognized Tax Benefits (Tables)

3 Months Ended

Mar. 31, 2012

Effective Tax Rate and Unrecognized Tax Benefits [Abstract]

Changes for unrecognized tax benefits

	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern Power
	(in millions)
Unrecognized tax benefits as of December 31, 2011	$ 120	$ 32	$ 47	$   3	$   5	$   3
Tax positions from current periods	3	1	1	—	—	—
Tax positions from prior periods	(6)	(3)	(1)	—	(1)	(2)
Reductions due to settlements	(5)	(2)	(3)	(1)	—	1
Reductions due to expired statute of limitations	—	—	—	—	—	—
Balance as of March 31, 2012	$ 112	$ 28	$ 44	$   2	$   4	$   2

Impact on effective tax rate

	As of March 31, 2012			As of   December 31,   2011
	Georgia Power	Other Registrants	Southern Company	Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$24	$  5	$  59	$  69
Tax positions not impacting the effective tax rate	20	32	53	51
Balance of unrecognized tax benefits	$44	$37	$112	$120

Accrued interest for unrecognized tax benefits

	Georgia Power	Other Registrants	Southern Company
	(in millions)
Interest accrued as of December 31, 2011	$ 6	$   3	$ 10
Interest reclassified due to settlements	(2)	(3)	(5)
Interest accrued during the period	1	—	1
Balance as of March 31, 2012	$ 5	$ —	$   6

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Measurements [Abstract]

Assets and liabilities measured at fair value on a recurring basis

	Fair Value Measurements Using
As of March 31, 2012:	Quoted Prices   in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$     —	$  24	$—		$     24
Interest rate derivatives	—	14	—		14
Foreign currency derivatives	—	1	—		1
Nuclear decommissioning trusts (a)	490	788	—		1,278
Cash equivalents and restricted cash	862	—	—		862
Other investments	4	50	15		69
Total	$1,356	$877	$15		$2,248
Liabilities:
Energy-related derivatives	$     —	$289	$—		$   289
Interest rate derivatives	—	10	—		10
Foreign currency derivatives	—	1	—		1
Total	$     —	$300	$—		$   300
Alabama Power
Assets:
Energy-related derivatives	$     —	$    1	$—		$       1
Nuclear decommissioning trusts: (b)
Domestic equity	283	63	—		346
Foreign equity (d)	27	56	—		83
U.S. Treasury and government agency securities	15	8	—		23
Corporate bonds	—	99	—		99
Mortgage and asset backed securities	—	26	—		26
Other	—	10	—		10
Cash equivalents and restricted cash	234	—	—		234
Total	$   559	$263	$—		$   822
Liabilities:
Energy-related derivatives	$     —	$  54	$—		$     54
Interest rate derivatives	—	10	—		10
Total	$     —	$  64	$—		$     64

	Fair Value Measurements Using
As of March 31, 2012:	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)	Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$  —	$  22	$  —	$  22
Nuclear decommissioning trusts: (c)
Domestic equity	165	1	—	166
Foreign equity (d)	—	109	—	109
U.S. Treasury and government agency securities	—	52	—	52
Municipal bonds	—	83	—	83
Corporate bonds	—	123	—	123
Mortgage and asset backed securities	—	127	—	127
Other	—	31	—	31
Total	$165	$548	$  —	$713
Liabilities:
Energy-related derivatives	$  —	$108	$  —	$108
Gulf Power
Assets:
Cash equivalents	$  15	$  —	$  —	$  15
Liabilities:
Energy-related derivatives	$  —	$  54	$  —	$  54
Mississippi Power
Assets:
Foreign currency derivatives	$  —	$    1	$  —	$    1
Cash equivalents	439	—	—	439
Total	$439	$    1	$  —	$440
Liabilities:
Energy-related derivatives	$  —	$  56	$  —	$  56
Foreign currency derivatives	—	1	—	1
Total	$  —	$  57	$  —	$  57
Southern Power
Assets:
Energy-related derivatives	$  —	$    1	$  —	$    1
Liabilities:
Energy-related derivatives	$  —	$  17	$  —	$  17

(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 March 31, 2012, approximately $41 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.

(d) Level 1 securities consist of actively traded stocks, while Level 2 securities consist of pooled funds.

Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments

As of March 31, 2012:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	12	None	Daily	1 to 3 days
Other — commingled funds		87	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		93	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		862	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Other — commingled funds		56	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		93	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		234	None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds		12	None	Daily	1 to 3 days
Other — commingled funds		31	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds		15	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds		439	None	Daily	Not applicable

Financial instruments not having carrying amount equal to fair value

	Carrying Amount	Fair Value
	(in millions)
Long-term debt:
Southern Company	$20,843	$25,499
Alabama Power	$  6,380	$  7,789
Georgia Power	$  8,918	$11,837
Gulf Power	$  1,236	$  1,349
Mississippi Power	$  1,668	$  1,740
Southern Power	$  1,303	$  1,393

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Effective Tax Rate and Unrecognized Tax Benefits

3 Months Ended

Mar. 31, 2012

Effective Tax Rate and Unrecognized Tax Benefits [Abstract]

EFFECTIVE TAX RATE AND UNRECOGNIZED 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 34.2% for the three months ended March 31, 2012 compared to 34.6% for the corresponding period in 2011. Southern Company’s effective tax rate is lower than the statutory rate primarily due to its employee stock plans’ dividend deduction and non-taxable AFUDC equity.

Alabama Power

Alabama Power’s effective tax rate was 38.3% for the three months ended March 31, 2012 compared to 37.1 % for the corresponding period in 2011. 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 34.9% for the three months ended March 31, 2012 compared to 34.6% for the corresponding period in 2011. The increase was primarily due to a decrease in AFUDC equity, which is non-taxable.

Gulf Power

Gulf Power’s effective tax rate was 34.6% for the three months ended March 31, 2012 compared to 33.8% for the corresponding period in 2011. The increase was primarily due to a decrease in AFUDC equity, which is non-taxable.

Mississippi Power

Mississippi Power’s effective tax rate was 24.7% for the three months ended March 31, 2012 compared to 32.2% for the corresponding period in 2011. The decrease was primarily due to an increase in AFUDC equity, which is non-taxable, related to the Kemper IGCC.

Southern Power

Southern Power’s effective tax rate was 31.3% for the three months ended March 31, 2012 compared to 35.6% for the corresponding period in 2011. The decrease was primarily due to lower earnings before income taxes and a settlement with the IRS related to the production activities deduction. See “Unrecognized Tax Benefits” herein for additional information.

Unrecognized Tax Benefits

Changes during 2012 for unrecognized tax benefits were as follows:

	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern Power
	(in millions)
Unrecognized tax benefits as of December 31, 2011	$ 120	$ 32	$ 47	$   3	$   5	$   3
Tax positions from current periods	3	1	1	—	—	—
Tax positions from prior periods	(6)	(3)	(1)	—	(1)	(2)
Reductions due to settlements	(5)	(2)	(3)	(1)	—	1
Reductions due to expired statute of limitations	—	—	—	—	—	—
Balance as of March 31, 2012	$ 112	$ 28	$ 44	$   2	$   4	$   2

The tax positions from current periods relate primarily to state investment tax credits and the tax accounting method change for repairs-generation assets. See “Tax Method of Accounting for Repairs” herein for additional information. The decreases in tax positions from prior periods and reductions due to settlements relate to a settlement with the IRS of the calculation methodology for the production activities deduction.

The impact on the effective tax rate, if recognized, was as follows:

	As of March 31, 2012			As of   December 31,   2011
	Georgia Power	Other Registrants	Southern Company	Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$24	$  5	$  59	$  69
Tax positions not impacting the effective tax rate	20	32	53	51
Balance of unrecognized tax benefits	$44	$37	$112	$120

The tax positions impacting the effective tax rate primarily relate to state investment tax credits and a litigation settlement refund claim for Southern Company. See Note 5 to the financial statements of Southern Company under “Effective Tax Rate” in Item 8 of the Form 10-K 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. See “Tax Method of Accounting for Repairs” herein for additional information. 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 Power	Other Registrants	Southern Company
	(in millions)
Interest accrued as of December 31, 2011	$ 6	$   3	$ 10
Interest reclassified due to settlements	(2)	(3)	(5)
Interest accrued during the period	1	—	1
Balance as of March 31, 2012	$ 5	$ —	$   6

All of the registrants classify interest on tax uncertainties as interest expense. The interest reclassified due to settlements is primarily associated with a settlement with the IRS related to the calculation methodology for the production activities deduction.

None of the registrants accrued any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of the registrants’ unrecognized tax positions will significantly increase or decrease within 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. On August 19, 2011, the IRS issued a revenue procedure, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. 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. On December 23, 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2012. The utility industry anticipates more detailed guidance concerning these regulations. 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.

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Financing

3 Months Ended

Mar. 31, 2012

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 March 31, 2012:

	Expires										Executable Term Loans				Due Within One Year (a)
Company	2012		2013		2014     and     Beyond		Total		Unused		One     Year		Two     Years		Term     Out		No     Term     Out
	(in millions)						(in millions)				(in millions)				(in millions)
Southern Company		$  —		$  —		$1,000		$1,000		$1,000		$  —		$—		$  —		$  —
Alabama Power		121		35		1,150		1,306		1,306		51		—		51		71
Georgia Power		—		—		1,750		1,750		1,745		—		—		—		—
Gulf Power		75		35		165		275		275		75		—		75		35
Mississippi Power		106		25		165		296		296		25		41		66		65
Southern Power		—		—		500		500		500		—		—		—		—
Other		25		25		—		50		50		25		—		25		—
Total		$327		$120		$4,730		$5,177		$5,172		$176		$41		$217		$171

(a) Reflects facilities expiring on or before March 31, 2013.

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Retirement Benefits

3 Months Ended

Mar. 31, 2012

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. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2012. 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 months ended March 31, 2012 and 2011 were as follows:

	000000	000000	000000	000000	000000
Pension Plans	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended March 31, 2012
Service cost	$   50	$ 11	$ 15	$   2	$ 2
Interest cost	98	23	35	4	5
Expected return on plan assets	(145)	(40)	(55)	(6)	(6)
Net amortization	31	8	11	1	1
Net cost (income)	$   34	$   2	$   6	$   1	$ 2
Three Months Ended March 31, 2011
Service cost	$   46	$ 11	$ 14	$   2	$ 2
Interest cost	98	24	36	4	4
Expected return on plan assets	(152)	(43)	(59)	(7)	(6)
Net amortization	13	3	5	1	1
Net cost (income)	$     5	$  (5)	$   (4)	$—	$ 1
Postretirement Benefits	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended March 31, 2012
Service cost	$   5	$ 1	$   1	$—	$—
Interest cost	21	5	9	1	1
Expected return on plan assets	(15)	(6)	(7)	—	—
Net amortization	5	2	3	—	—
Net cost (income)	$ 16	$ 2	$   6	$  1	$  1
Three Months Ended March 31, 2011
Service cost	$   5	$ 1	$   2	$—	$—
Interest cost	23	6	10	1	1
Expected return on plan assets	(16)	(6)	(8)	—	—
Net amortization	5	2	3	—	—
Net cost (income)	$ 17	$ 3	$   7	$1	$  1

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Derivatives

3 Months Ended

Mar. 31, 2012

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 traditional operating companies and Southern Power 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 traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Energy-related derivative contracts are accounted for 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 and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions, are reflected in earnings.

• Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At March 31, 2012, the net volume of energy-related derivative contracts for power and natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

	Power			Gas
	Net (Sold) MWHs	Longest Hedge Date	Longest Non-Hedge Date	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)			(in millions)
Southern Company	(0.1)	—	2012	221	2017	2017
Alabama Power	—	—	—	37	2017	—
Georgia Power	—	—	—	85	2017	—
Gulf Power	—	—	—	43	2017	—
Mississippi Power	—	—	—	28	2017	—
Southern Power	(0.1)	—	2012	28	2012	2017

In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 9 million mmBtu for Southern Company, 4 million mmBtu for Georgia Power, 2 million mmBtu for Southern Power, and is 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 March 31, 2013 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 March 31, 2012, the following interest rate derivatives were outstanding:

	Notional Amount	Interest Rate   Received	Interest Rate   Paid	Hedge Maturity Date	Fair Value Gain (Loss)   March 31, 2012
	(in millions)				(in millions)
Cash flow hedges of forecasted transactions
Alabama Power	$300	3-month LIBOR	2.90%*	December 2022	$(10)
Fair value hedges of existing debt
Southern Company	350	4.15%	3-month LIBOR + 1.96%*	May 2014	14
Total	$650				$  4

* 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 March 31, 2013, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.

Registrant	Estimated Gain (Loss) to be Reclassified for the 12 Months Ending March 31, 2013	Total Deferred Gains (Losses) Amortized Through
	(in millions)
Southern Company	$(16)	2037
Alabama Power	1	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 typically recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At March 31, 2012, the following foreign currency derivatives were outstanding:

	Notional Amount	Forward Rate	Hedge Maturity Date	Fair Value Gain (Loss) March 31, 2012
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR6.8	1.3805 Dollars per Euro*	Various through March 2014	$—
Derivatives not designated as hedges
Mississippi Power	EUR18.1	1.3209 Dollars per Euro*	N/A	—
Total	EUR24.9			$—

* Weighted Average

Derivative Financial Statement Presentation and Amounts

At March 31, 2012, 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 March 31, 2012
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern   Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$17	$—	$17	$—	$—
Other deferred charges and assets	6	1	5	—	—
Total derivatives designated as hedging instruments for regulatory purposes	$23	$  1	$22	$—	$—	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	8	—	—	—	—	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$14	$—	$—	$—	$—	$—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	$  1	$—	$—	$—	$—	$  1
Foreign currency derivatives
Other current assets	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$  2	$—	$—	$—	$  1	$  1
Total asset derivatives	$39	$  1	$22	$—	$  1	$  1

Liability Derivatives at March 31, 2012
	Fair Value
Derivative Category and Balance Sheet Location	Southern   Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern   Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$191	$41	$  80	$31	$39
Other deferred credits and liabilities	81	13	28	23	17
Total derivatives designated as hedging instruments for regulatory purposes	$272	$54	$108	$54	$56	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities	$    2	$—	$  —	$—	$—	$    2
Interest rate derivatives:
Liabilities from risk management activities	10	10	—	—	—	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$  12	$10	$  —	$—	$—	$    2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$  15	$—	$  —	$—	$—	$  15
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$  16	$—	$  —	$—	$  1	$  15
Total liability derivatives	$300	$64	$108	$54	$57	$  17

All derivative instruments are measured at fair value. See Note (C) herein for additional information.

At March 31, 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$(191)	$(41)	$(80)	$(31)	$(39)
Other regulatory assets, deferred	(81)	(13)	(28)	(23)	(17)
Other regulatory liabilities, current	17	—	17	—	—
Other regulatory liabilities, deferred	6	1	—	—	—
Other deferred credits and liabilities*	—	—	5	—	—
Total energy-related derivative gains (losses)	$(249)	$(53)	$(86)	$(54)	$(56)

* Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

For the three months ended March 31, 2012 and March 31, 2011, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were immaterial.

For the three months ended March 31, 2012, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were immaterial. For the three months ended March 31, 2011, 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 $3 million. This amount was offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there was no impact on Southern Company’s or Mississippi Power’s statements of income.

For the three months ended March 31, 2012 and March 31, 2011, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

Derivatives in Cash Flow	Gain (Loss) Recognized in OCI on Derivative		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Hedging Relationships	(Effective Portion)		Statements of Income Location	Amount
	2012	2011		2012	2011
	(in millions)			(in millions)
Southern Company
Energy-related derivatives	$     (1)	$       1	Fuel	$            —	$            —
Interest rate derivatives	6	4	Interest expense, net of amounts capitalized	(3)	(5)
Total	$      5	$       5		$            (3)	$            (5)
Alabama Power
Interest rate derivatives	$      7	$       4	Interest expense, net of amounts capitalized	$            —	$            —
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (1)	$            (1)
Gulf Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Mississippi Power
Interest rate derivatives	$    (1)	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Southern Power
Energy-related derivatives	$    (1)	$       1	Fuel	$            —	$            —
Interest rate derivatives	—	—	Interest expense, net of amounts capitalized	(2)	(3)
Total	$    (1)	$       1		$            (2)	$            (3)

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three months ended March 31, 2012, the pre-tax losses from energy-related derivatives not designated as hedging instruments on the statements of income were $6 million for Southern Company and Southern Power. For the three months ended March 31, 2011, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for Southern Company and Southern Power.

For the three months ended March 31, 2012, the pre-tax effects of foreign currency derivatives not designated as hedging instruments were recorded as regulatory assets and liabilities and were immaterial for Southern Company and Mississippi Power.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At March 31, 2012, the fair value of derivative liabilities with contingent features, by registrant, was as follows:

	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern Power
			(in millions)
Derivative liabilities	$36	$9	$10	$7	$6	$4

At March 31, 2012, the registrants had no collateral posted with their derivative counterparties. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $36 million for each registrant. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participant has a credit rating change to below investment grade.

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Stockholder's Equity (Details Textual) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Stockholders' Equity (Textual) [Abstract]
Anti dilutive stock options	1	7

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Financing (Tables)

3 Months Ended

Mar. 31, 2012

Financing [Abstract]

Credit arrangements by company

	Expires										Executable Term Loans				Due Within One Year (a)
Company	2012		2013		2014     and     Beyond		Total		Unused		One     Year		Two     Years		Term     Out		No     Term     Out
	(in millions)						(in millions)				(in millions)				(in millions)
Southern Company		$  —		$  —		$1,000		$1,000		$1,000		$  —		$—		$  —		$  —
Alabama Power		121		35		1,150		1,306		1,306		51		—		51		71
Georgia Power		—		—		1,750		1,750		1,745		—		—		—		—
Gulf Power		75		35		165		275		275		75		—		75		35
Mississippi Power		106		25		165		296		296		25		41		66		65
Southern Power		—		—		500		500		500		—		—		—		—
Other		25		25		—		50		50		25		—		25		—
Total		$327		$120		$4,730		$5,177		$5,172		$176		$41		$217		$171

(a) Reflects facilities expiring on or before March 31, 2013.

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Introduction (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Introduction [Abstract]
Expected potential impairment loss on abandonment of the project	$ 90

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Derivatives (Details 1) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	$ 39
Liability Derivatives	300
Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(249)
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	(191)
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	(81)
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	17
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	6
Alabama Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	64
Alabama Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(53)
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	(41)
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	(13)
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	1
Georgia Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	22
Liability Derivatives	108
Georgia Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(86)
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	5
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	(80)
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	(28)
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	17
Gulf Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	54
Gulf Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(54)
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	(31)
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	(23)
Mississippi Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	57
Mississippi Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(56)
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	(39)
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	(17)
Southern Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	17
Cash Flow and Fair Value Hedging [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	14
Liability Derivatives	12
Cash Flow and Fair Value Hedging [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	2
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	8
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	10
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	10
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	10
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	2
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	2
Hedging Instruments for Regulatory Purposes [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	23
Liability Derivatives	272
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	17
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	6
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	191
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	81
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	54
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [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] | Alabama Power [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	41
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	13
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	22
Liability Derivatives	108
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives [Member] | Other current assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	17
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	5
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	80
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	28
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	54
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	31
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	23
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	56
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	39
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy-related derivatives [Member] | Other deferred credits and liabilities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	17
Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	2
Liability Derivatives	16
Not Designated as Hedging Instrument [Member] | Energy-related derivatives [Member] | Other deferred charges and 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] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	15
Not Designated as Hedging Instrument [Member] | Foreign currency 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] | Foreign currency derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	1
Not Designated as Hedging Instrument [Member] | Mississippi Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	1
Not Designated as Hedging Instrument [Member] | Mississippi Power [Member] | Foreign currency 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] | Mississippi Power [Member] | Foreign currency derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	1
Not Designated as Hedging Instrument [Member] | Southern Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	15
Not Designated as Hedging Instrument [Member] | Southern Power [Member] | Energy-related derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Not Designated as Hedging Instrument [Member] | Southern Power [Member] | Energy-related derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	$ 15

XML

Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Current Assets:
Cash and cash equivalents	$ 1,044,000,000	$ 1,315,000,000
Restricted cash and cash equivalents	7,000,000	8,000,000
Receivables --
Customer accounts receivable	936,000,000	1,074,000,000
Unbilled revenues	358,000,000	376,000,000
Under recovered regulatory clause revenues	5,000,000	143,000,000
Other accounts and notes receivable	226,000,000	282,000,000
Accumulated provision for uncollectible accounts	(24,000,000)	(26,000,000)
Fossil fuel stock, at average cost	1,585,000,000	1,367,000,000
Materials and supplies, at average cost	898,000,000	903,000,000
Vacation pay	161,000,000	160,000,000
Prepaid expenses	519,000,000	385,000,000
Other regulatory assets, current	267,000,000	239,000,000
Other current assets	59,000,000	46,000,000
Total current assets	6,041,000,000	6,272,000,000
Property, Plant, and Equipment:
In service	60,073,000,000	59,744,000,000
Less accumulated provision for depreciation	21,327,000,000	21,154,000,000
Plant in service, net of depreciation	38,746,000,000	38,590,000,000
Other utility plant, net	54,000,000	55,000,000
Nuclear fuel, at amortized cost	830,000,000	774,000,000
Construction work in progress	6,225,000,000	5,591,000,000
Total property, plant, and equipment	45,855,000,000	45,010,000,000
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,280,000,000	1,207,000,000
Leveraged leases	654,000,000	649,000,000
Miscellaneous property and investments	260,000,000	262,000,000
Total other property and investments	2,194,000,000	2,118,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,381,000,000	1,365,000,000
Unamortized debt issuance expense	163,000,000	156,000,000
Unamortized loss on reacquired debt	279,000,000	285,000,000
Deferred under recovered regulatory clause revenues	24,000,000	48,000,000
Other regulatory assets, deferred	3,486,000,000	3,532,000,000
Other deferred charges and assets	451,000,000	481,000,000
Total deferred charges and other assets	5,784,000,000	5,867,000,000
Total Assets	59,874,000,000	59,267,000,000
Current Liabilities:
Securities due within one year	1,881,000,000	1,717,000,000
Interest-bearing refundable deposit related to asset sale	150,000,000
Notes payable	1,029,000,000	859,000,000
Accounts payable	1,262,000,000	1,553,000,000
Customer deposits	358,000,000	347,000,000
Accrued taxes --
Accrued income taxes	51,000,000	13,000,000
Unrecognized tax benefits	12,000,000	22,000,000
Other accrued taxes	198,000,000	425,000,000
Accrued interest	249,000,000	226,000,000
Accrued vacation pay	204,000,000	205,000,000
Accrued compensation	158,000,000	450,000,000
Liabilities from risk management activities	219,000,000	209,000,000
Other regulatory liabilities, current	153,000,000	125,000,000
Other current liabilities	393,000,000	426,000,000
Total current liabilities	6,317,000,000	6,577,000,000
Long-term Debt	19,051,000,000	18,647,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	9,001,000,000	8,809,000,000
Deferred credits related to income taxes	220,000,000	224,000,000
Accumulated deferred investment tax credits	651,000,000	611,000,000
Employee benefit obligations	2,432,000,000	2,442,000,000
Asset retirement obligations	1,341,000,000	1,321,000,000
Other cost of removal obligations	1,178,000,000	1,165,000,000
Other regulatory liabilities, deferred	324,000,000	297,000,000
Other deferred credits and liabilities	578,000,000	514,000,000
Total deferred credits and other liabilities	15,725,000,000	15,383,000,000
Total Liabilities	41,093,000,000	40,607,000,000
Redeemable Preferred Stock of Subsidiaries	375,000,000	375,000,000
Common Stockholders' Equity:
Common stock	4,346,000,000	4,328,000,000
Paid-in capital	4,550,000,000	4,410,000,000
Treasury, at cost	(18,000,000)	(17,000,000)
Retained earnings	8,926,000,000	8,968,000,000
Accumulated other comprehensive loss	(105,000,000)	(111,000,000)
Total common stockholders' equity	17,699,000,000	17,578,000,000
Preferred and Preference Stock of Subsidiaries	707,000,000	707,000,000
Total Stockholders' Equity	18,406,000,000	18,285,000,000
Total Liabilities and Stockholders' Equity	59,874,000,000	59,267,000,000
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	355,000,000	344,000,000
Restricted cash and cash equivalents		1,000,000
Receivables --
Customer accounts receivable	300,000,000	332,000,000
Unbilled revenues	116,000,000	126,000,000
Other accounts and notes receivable	35,000,000	35,000,000
Affiliated companies	50,000,000	79,000,000
Accumulated provision for uncollectible accounts	(10,000,000)	(10,000,000)
Fossil fuel stock, at average cost	425,000,000	344,000,000
Materials and supplies, at average cost	372,000,000	375,000,000
Vacation pay	59,000,000	59,000,000
Prepaid expenses	146,000,000	74,000,000
Other regulatory assets, current	48,000,000	44,000,000
Other current assets	12,000,000	11,000,000
Total current assets	1,908,000,000	1,814,000,000
Property, Plant, and Equipment:
In service	20,999,000,000	20,809,000,000
Less accumulated provision for depreciation	7,446,000,000	7,344,000,000
Plant in service, net of depreciation	13,553,000,000	13,465,000,000
Nuclear fuel, at amortized cost	363,000,000	330,000,000
Construction work in progress	339,000,000	374,000,000
Total property, plant, and equipment	14,255,000,000	14,169,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	62,000,000	62,000,000
Nuclear decommissioning trusts, at fair value	588,000,000	540,000,000
Miscellaneous property and investments	74,000,000	73,000,000
Total other property and investments	724,000,000	675,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	530,000,000	532,000,000
Prepaid pension costs	67,000,000	59,000,000
Deferred under recovered regulatory clause revenues	24,000,000	48,000,000
Other regulatory assets, deferred	995,000,000	994,000,000
Other deferred charges and assets	161,000,000	186,000,000
Total deferred charges and other assets	1,777,000,000	1,819,000,000
Total Assets	18,664,000,000	18,477,000,000
Current Liabilities:
Securities due within one year	750,000,000	500,000,000
Affiliated	163,000,000	203,000,000
Accounts payable	225,000,000	322,000,000
Customer deposits	86,000,000	85,000,000
Accrued taxes --
Accrued income taxes	44,000,000	32,000,000
Other accrued taxes	54,000,000	34,000,000
Accrued interest	67,000,000	63,000,000
Accrued vacation pay	48,000,000	48,000,000
Accrued compensation	33,000,000	95,000,000
Liabilities from risk management activities	51,000,000	54,000,000
Other regulatory liabilities, current	19,000,000	18,000,000
Other current liabilities	40,000,000	38,000,000
Total current liabilities	1,580,000,000	1,492,000,000
Long-term Debt	5,630,000,000	5,632,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,287,000,000	3,257,000,000
Deferred credits related to income taxes	82,000,000	83,000,000
Accumulated deferred investment tax credits	147,000,000	149,000,000
Employee benefit obligations	343,000,000	343,000,000
Asset retirement obligations	561,000,000	553,000,000
Other cost of removal obligations	719,000,000	703,000,000
Other regulatory liabilities, deferred	193,000,000	156,000,000
Other deferred credits and liabilities	87,000,000	82,000,000
Total deferred credits and other liabilities	5,419,000,000	5,326,000,000
Total Liabilities	12,629,000,000	12,450,000,000
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	2,194,000,000	2,182,000,000
Retained earnings	1,948,000,000	1,956,000,000
Accumulated other comprehensive loss	(14,000,000)	(18,000,000)
Total common stockholders' equity	5,350,000,000	5,342,000,000
Total Liabilities and Stockholders' Equity	18,664,000,000	18,477,000,000
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	13,000,000	13,000,000
Receivables --
Customer accounts receivable	490,000,000	571,000,000
Unbilled revenues	166,000,000	172,000,000
Under recovered regulatory clause revenues		137,000,000
Joint owner accounts receivable	59,000,000	87,000,000
Other accounts and notes receivable	45,000,000	61,000,000
Affiliated companies	35,000,000	26,000,000
Accumulated provision for uncollectible accounts	(12,000,000)	(13,000,000)
Fossil fuel stock, at average cost	844,000,000	723,000,000
Materials and supplies, at average cost	400,000,000	406,000,000
Vacation pay	84,000,000	82,000,000
Prepaid income taxes	122,000,000	71,000,000
Other regulatory assets, current	118,000,000	108,000,000
Other current assets	84,000,000	106,000,000
Total current assets	2,448,000,000	2,550,000,000
Property, Plant, and Equipment:
In service	27,884,000,000	27,804,000,000
Less accumulated provision for depreciation	10,294,000,000	10,296,000,000
Plant in service, net of depreciation	17,590,000,000	17,508,000,000
Other utility plant, net	54,000,000	55,000,000
Nuclear fuel, at amortized cost	468,000,000	443,000,000
Construction work in progress	3,456,000,000	3,274,000,000
Total property, plant, and equipment	21,568,000,000	21,280,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	62,000,000	63,000,000
Nuclear decommissioning trusts, at fair value	692,000,000	667,000,000
Miscellaneous property and investments	45,000,000	44,000,000
Total other property and investments	799,000,000	774,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	757,000,000	756,000,000
Other regulatory assets, deferred	1,562,000,000	1,604,000,000
Other deferred charges and assets	203,000,000	187,000,000
Total deferred charges and other assets	2,522,000,000	2,547,000,000
Total Assets	27,337,000,000	27,151,000,000
Current Liabilities:
Securities due within one year	855,000,000	455,000,000
Notes payable	614,000,000	515,000,000
Affiliated	287,000,000	337,000,000
Accounts payable	470,000,000	686,000,000
Customer deposits	222,000,000	213,000,000
Accrued taxes --
Accrued income taxes	47,000,000	36,000,000
Unrecognized tax benefits	9,000,000	14,000,000
Other accrued taxes	89,000,000	304,000,000
Accrued interest	119,000,000	92,000,000
Accrued vacation pay	60,000,000	60,000,000
Accrued compensation	47,000,000	125,000,000
Liabilities from risk management activities	80,000,000	68,000,000
Other regulatory liabilities, current	84,000,000	65,000,000
Nuclear decommissioning trust securities lending collateral	12,000,000	32,000,000
Other current liabilities	144,000,000	139,000,000
Total current liabilities	3,139,000,000	3,141,000,000
Long-term Debt	8,117,000,000	8,018,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,491,000,000	4,388,000,000
Deferred credits related to income taxes	120,000,000	122,000,000
Accumulated deferred investment tax credits	217,000,000	220,000,000
Employee benefit obligations	901,000,000	905,000,000
Asset retirement obligations	745,000,000	734,000,000
Other cost of removal obligations	105,000,000	110,000,000
Other deferred credits and liabilities	254,000,000	224,000,000
Total deferred credits and other liabilities	6,833,000,000	6,703,000,000
Total Liabilities	18,089,000,000	17,862,000,000
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	5,540,000,000	5,522,000,000
Retained earnings	3,052,000,000	3,112,000,000
Accumulated other comprehensive loss	(8,000,000)	(9,000,000)
Total common stockholders' equity	8,982,000,000	9,023,000,000
Total Liabilities and Stockholders' Equity	27,337,000,000	27,151,000,000
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	19,110,000	17,328,000
Receivables --
Customer accounts receivable	54,868,000	72,754,000
Unbilled revenues	48,705,000	49,921,000
Under recovered regulatory clause revenues	4,536,000	5,530,000
Other accounts and notes receivable	11,546,000	13,350,000
Affiliated companies	19,986,000	14,844,000
Accumulated provision for uncollectible accounts	(1,433,000)	(1,962,000)
Fossil fuel stock, at average cost	146,023,000	147,567,000
Materials and supplies, at average cost	51,257,000	49,781,000
Prepaid expenses	44,153,000	28,327,000
Other regulatory assets, current	44,521,000	35,849,000
Other current assets	469,000	2,051,000
Total current assets	443,741,000	435,340,000
Property, Plant, and Equipment:
In service	3,898,726,000	3,846,446,000
Less accumulated provision for depreciation	1,140,589,000	1,124,291,000
Plant in service, net of depreciation	2,758,137,000	2,722,155,000
Construction work in progress	333,631,000	287,173,000
Total property, plant, and equipment	3,091,768,000	3,009,328,000
Other Property and Investments:
Total other property and investments	16,469,000	16,394,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	49,453,000	48,210,000
Other regulatory assets, deferred	316,519,000	323,116,000
Other deferred charges and assets	29,433,000	39,493,000
Total deferred charges and other assets	395,405,000	410,819,000
Total Assets	3,947,383,000	3,871,881,000
Current Liabilities:
Notes payable	83,589,000	114,507,000
Affiliated	45,716,000	54,874,000
Accounts payable	61,034,000	63,265,000
Customer deposits	36,010,000	35,779,000
Accrued taxes --
Accrued income taxes	104,000	1,362,000
Other accrued taxes	11,712,000	12,114,000
Accrued interest	19,312,000	14,018,000
Accrued compensation	5,294,000	14,485,000
Liabilities from risk management activities	30,811,000	22,786,000
Other regulatory liabilities, current	45,436,000	35,639,000
Other current liabilities	23,104,000	22,916,000
Total current liabilities	362,122,000	391,745,000
Long-term Debt	1,235,586,000	1,235,447,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	515,663,000	458,978,000
Accumulated deferred investment tax credits	6,422,000	6,760,000
Employee benefit obligations	109,589,000	109,740,000
Other cost of removal obligations	211,649,000	214,598,000
Other regulatory liabilities, deferred	45,300,000	44,843,000
Other deferred credits and liabilities	204,446,000	186,824,000
Total deferred credits and other liabilities	1,093,069,000	1,021,743,000
Total Liabilities	2,690,777,000	2,648,935,000
Preference Stock	97,998,000	97,998,000
Common Stockholders' Equity:
Common stock	393,060,000	353,060,000
Paid-in capital	544,510,000	542,709,000
Retained earnings	223,049,000	231,333,000
Accumulated other comprehensive loss	(2,011,000)	(2,154,000)
Total common stockholders' equity	1,158,608,000	1,124,948,000
Total Liabilities and Stockholders' Equity	3,947,383,000	3,871,881,000
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	466,746,000	211,585,000
Receivables --
Customer accounts receivable	27,836,000	32,551,000
Unbilled revenues	27,231,000	27,239,000
Other accounts and notes receivable	3,716,000	7,080,000
Affiliated companies	19,463,000	23,078,000
Accumulated provision for uncollectible accounts	(415,000)	(547,000)
Fossil fuel stock, at average cost	156,360,000	140,173,000
Materials and supplies, at average cost	31,325,000	30,787,000
Prepaid income taxes	37,408,000	37,793,000
Other regulatory assets, current	75,249,000	69,201,000
Other current assets	10,000,000	8,881,000
Total current assets	854,919,000	587,821,000
Property, Plant, and Equipment:
In service	2,912,571,000	2,902,240,000
Less accumulated provision for depreciation	1,035,946,000	1,019,251,000
Plant in service, net of depreciation	1,876,625,000	1,882,989,000
Construction work in progress	1,323,400,000	955,135,000
Total property, plant, and equipment	3,200,025,000	2,838,124,000
Other Property and Investments:
Total other property and investments	6,288,000	6,520,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	39,703,000	25,009,000
Other regulatory assets, deferred	190,894,000	185,694,000
Other deferred charges and assets	30,422,000	28,674,000
Total deferred charges and other assets	261,019,000	239,377,000
Total Assets	4,322,251,000	3,671,842,000
Current Liabilities:
Securities due within one year	255,255,000	240,633,000
Interest-bearing refundable deposit related to asset sale	150,000,000
Affiliated	50,786,000	62,650,000
Accounts payable	198,396,000	168,309,000
Customer deposits	13,993,000	13,658,000
Accrued taxes --
Accrued income taxes	5,922,000	3,813,000
Other accrued taxes	20,364,000	53,825,000
Accrued interest	22,264,000	12,750,000
Accrued compensation	5,086,000	15,889,000
Liabilities from risk management activities	39,649,000	54,127,000
Other regulatory liabilities, current	5,535,000	5,779,000
Over recovered regulatory clause liabilities	73,129,000	60,502,000
Other current liabilities	20,797,000	17,533,000
Total current liabilities	861,176,000	709,468,000
Long-term Debt	1,412,662,000	1,103,596,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	259,903,000	270,397,000
Deferred credits related to income taxes	10,800,000	11,058,000
Accumulated deferred investment tax credits	150,983,000	109,761,000
Employee benefit obligations	162,007,000	161,065,000
Other cost of removal obligations	130,909,000	126,424,000
Other regulatory liabilities, deferred	61,831,000	60,848,000
Other deferred credits and liabilities	39,700,000	37,228,000
Total deferred credits and other liabilities	816,133,000	776,781,000
Total Liabilities	3,089,971,000	2,589,845,000
Redeemable Preferred Stock	32,780,000	32,780,000
Common Stockholders' Equity:
Common stock	37,691,000	37,691,000
Paid-in capital	847,035,000	694,855,000
Retained earnings	324,123,000	325,568,000
Accumulated other comprehensive loss	(9,349,000)	(8,897,000)
Total common stockholders' equity	1,199,500,000	1,049,217,000
Total Liabilities and Stockholders' Equity	4,322,251,000	3,671,842,000
Southern Power [Member]
Current Assets:
Cash and cash equivalents	2,968,000	16,943,000
Receivables --
Customer accounts receivable	58,192,000	59,360,000
Other accounts and notes receivable	1,779,000	2,122,000
Affiliated companies	25,609,000	36,508,000
Fossil fuel stock, at average cost	13,793,000	13,038,000
Materials and supplies, at average cost	38,769,000	37,603,000
Prepaid service agreements - current	27,234,000	28,621,000
Prepaid income taxes	19,050,000	5,192,000
Prepaid expenses	6,095,000	4,645,000
Assets from risk management activities	89,000	177,000
Total current assets	193,578,000	204,209,000
Property, Plant, and Equipment:
In service	3,158,331,000	3,167,840,000
Less accumulated provision for depreciation	680,297,000	652,087,000
Plant in service, net of depreciation	2,478,034,000	2,515,753,000
Construction work in progress	737,751,000	666,280,000
Total property, plant, and equipment	3,215,785,000	3,182,033,000
Other Property and Investments:
Goodwill	1,839,000	1,839,000
Other intangible assets, net of amortization of $1,671 and $1,476 at March 31, 2012 and December 31, 2011, respectively	47,448,000	47,644,000
Total other property and investments	49,287,000	49,483,000
Deferred Charges and Other Assets:
Prepaid long-term service agreements	104,959,000	115,838,000
Other deferred charges and assets -- affiliated	2,969,000	3,029,000
Other deferred charges and assets	29,451,000	26,385,000
Total deferred charges and other assets	137,379,000	145,252,000
Total Assets	3,596,029,000	3,580,977,000
Current Liabilities:
Securities due within one year	550,000	555,000
Notes payable	199,685,000	179,520,000
Affiliated	42,838,000	63,609,000
Accounts payable	49,762,000	44,321,000
Accrued taxes --
Accrued income taxes	1,260,000	2,548,000
Other accrued taxes	5,812,000	2,158,000
Accrued interest	11,702,000	21,874,000
Liabilities from risk management activities	16,447,000	9,651,000
Other current liabilities	17,470,000	7,401,000
Total current liabilities	345,526,000	331,637,000
Long-term Debt	1,302,620,000	1,302,758,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	333,698,000	319,790,000
Deferred convertible investment tax credits	128,411,000	125,065,000
Deferred capacity revenues -- affiliated	4,658,000	20,637,000
Other deferred credits and liabilities -- affiliated	3,359,000	3,618,000
Other deferred credits and liabilities	5,130,000	4,965,000
Total deferred credits and other liabilities	475,256,000	474,075,000
Total Liabilities	2,123,402,000	2,108,470,000
Redeemable Noncontrolling Interest	3,923,000	3,825,000
Common Stockholders' Equity:
Common stock
Paid-in capital	1,029,430,000	1,028,210,000
Retained earnings	444,867,000	447,301,000
Accumulated other comprehensive loss	(5,593,000)	(6,829,000)
Total common stockholders' equity	1,468,704,000	1,468,682,000
Total Liabilities and Stockholders' Equity	$ 3,596,029,000	$ 3,580,977,000

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Contingencies and Regulatory Matters

3 Months Ended

Mar. 31, 2012

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, business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury 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 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 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. The EPA alleged NSR violations at five coal-fired generating facilities operated by Alabama Power, including a unit co-owned by Mississippi Power, and three coal-fired generating facilities operated by Georgia Power, including a unit co-owned by Gulf Power. The civil action sought penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The case against Georgia Power (including claims related to the unit co-owned by Gulf Power) was administratively closed in 2001 and has not been reopened. After Alabama Power was dismissed from the original action, the EPA filed a separate action in 2001 against Alabama Power (including claims related to the unit co-owned by Mississippi Power) in the U.S. District Court for the Northern District of Alabama.

In 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree, resolving claims relating to the alleged NSR violations at Plant Miller. In September 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims, including one relating to the unit co-owned by Mississippi Power. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power summary judgment on all remaining claims and dismissed the case with prejudice. That judgment is on appeal to the U.S. Court of Appeals for the Eleventh Circuit. On February 23, 2012, the EPA filed a motion in the U.S. District Court for the Northern District of Alabama seeking vacatur of the judgment and recusal of the judge in the case involving Alabama Power (including claims related to a unit co-owned by Mississippi Power). At the same time, the EPA asked the U.S. Court of Appeals for the Eleventh Circuit to stay its appeal of the judgment in favor of Alabama Power. Alabama Power filed oppositions to the EPA’s motion and its request for a stay. On March 29, 2012, the U.S. Court of Appeals for the Eleventh Circuit denied the EPA’s request to stay its appeal. The U.S. District Court for the Northern District of Alabama has not ruled on the EPA’s motion seeking vacatur of the judgment.

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

Climate Change Litigation

Kivalina Case

In 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs allege that the village is being destroyed by erosion allegedly 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 (including Southern Company) 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. In 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case. The plaintiffs appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. Southern Company believes that these claims are without merit. While Southern Company believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether Southern Company will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.

Hurricane Katrina Case

In 2005, immediately following Hurricane Katrina, a lawsuit was filed in the U.S. District Court for the Southern District of Mississippi by Ned Comer on behalf of Mississippi residents seeking recovery for property damage and personal injuries caused by Hurricane Katrina. In 2006, the plaintiffs amended the complaint to include Southern Company and many other electric utilities, oil companies, chemical companies, and coal producers. The plaintiffs allege that the defendants contributed to climate change, which contributed to the intensity of Hurricane Katrina. In 2007, the U.S. District Court for the Southern District of Mississippi dismissed the case. On appeal to the U.S. Court of Appeals for the Fifth Circuit, a three-judge panel reversed the U.S. District Court for the Southern District of Mississippi, holding that the case could proceed, but, on rehearing, the full U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal, resulting in reinstatement of the decision of the U.S. District Court for the Southern District of Mississippi in favor of the defendants. On May 27, 2011, the plaintiffs filed an amended version of their class action complaint, arguing that the earlier dismissal was on procedural grounds and under Mississippi law the plaintiffs have a right to re-file. The amended complaint was also filed against numerous chemical, coal, oil, and utility companies, including Alabama Power, Georgia Power, Gulf Power, and Southern Power. On March 20, 2012, the U.S. District Court for the Southern District of Mississippi dismissed the plaintiffs’ amended complaint. On April 16, 2012, the plaintiffs appealed the case to the U.S. Court of Appeals for the Fifth Circuit. Each Southern Company entity named in the lawsuit believes that these claims are without merit. While each Southern Company entity named in the lawsuit believes the likelihood of loss is remote based on existing case law, it is not possible to predict with certainty whether any Southern Company entity named in the lawsuit will incur any liability in connection with this matter. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

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

Georgia Power’s environmental remediation liability as of March 31, 2012 was $20 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and the CERCLA NPL are anticipated.

In 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.

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. On November 22, 2011, the EPA sent Georgia Power a letter stating that the EPA does not consider Georgia Power to be in compliance with the UAO. The EPA also stated that it is considering enforcement options against Georgia Power and other UAO recipients who are not complying with the UAO.

The EPA may seek to enforce the UAO in court pursuant to its enforcement authority under CERCLA and may seek recovery of its costs in undertaking the UAO work. 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.

In addition to the EPA’s action at the Ward Transformer Superfund site, in 2009, Georgia Power, along with many other parties, was sued by several existing PRPs for cost recovery for a removal action that is currently taking place. Georgia Power and numerous other defendants moved for a dismissal of these lawsuits. The court denied the dismissal of the lawsuits in March 2010 but granted Georgia Power’s motion regarding the dismissal of the claim pertaining to the plaintiffs’ joint and several liability.

The ultimate outcome of the Brunswick CERCLA NPL and Ward Transformer Superfund site matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the regulatory treatment, it is not expected to have a material impact on Southern Company’s or Georgia Power’s financial statements.

Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $60 million as of March 31, 2012. 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 potentially responsible party at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. The feasibility study/presumptive remedy document was originally filed with TCEQ in June 2011 and remains under consideration by the agency. Amounts expensed and accrued related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan.

The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

Nuclear Fuel Disposal Cost Litigation

Alabama Power and Georgia Power have contracts with the U.S., acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent nuclear fuel in 1998 as required by the contracts, and Alabama Power and Georgia Power are pursuing legal remedies against the government for breach of contract.

In 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 Southern Company system’s direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004.

In 2008, the government filed an appeal and, 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. On July 12, 2011, the court entered final judgment in favor of Alabama Power and awarded Alabama Power approximately $17 million. In April 2012, the award was credited to cost of service for the benefit of Alabama Power customers.

On April 5, 2012, Georgia Power and the government entered into a stipulation to conclude this litigation, which provided for judgment in favor of Georgia Power and awarded Georgia Power approximately $27 million in damages, based on its ownership interests. On April 5, 2012, the stipulation was approved by the U.S. Court of Federal Claims. The proceeds will be credited to the Georgia Power accounts where the original costs were charged and will be used to reduce rate base, fuel, and cost of service for the benefit of Georgia Power customers.

In 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 March 31, 2012 for the second claim. The final outcome of this matter cannot be determined at this time.

Sufficient pool storage capacity for spent fuel is available at Plant Vogtle Units 1 and 2 to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle Units 1 and 2 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.

FERC Matters

See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s request for revised rates related to the wholesale Municipal and Rural Associations (MRA) cost-based electric tariff. See Note 3 to the financial statements of Southern Company 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.

On January 20, 2012, Mississippi Power reached a settlement agreement with its wholesale customers, which was executed by all parties on March 9, 2012. The settlement agreement provides that base rates under the cost-based electric tariff will increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. In 2012, the amount of base rate revenues to be received from the agreed upon increase will be approximately $17.0 million. On March 12, 2012, Mississippi Power filed an unopposed motion to place wholesale MRA interim rates into effect pending approval of the settlement agreement between the parties by the FERC. On March 28, 2012, the FERC approved the motion to place interim rates into effect beginning in May 2012. Approval of the settlement agreement by the FERC has been delayed until later in the year.

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

Retail Regulatory Matters

Georgia Power

Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

As of March 31, 2012, Georgia Power had a total over recovered fuel cost balance of approximately $22 million compared to an under recovered balance of $137 million at December 31, 2011. The over recovered fuel costs at March 31, 2012 are included in other deferred credits and liabilities on Southern Company’s and Georgia Power’s Condensed Balance Sheets herein. The under recovered fuel costs at December 31, 2011 are included in current assets on Southern Company’s and Georgia Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Southern Company’s or Georgia Power’s revenues or net income, but will affect cash flow.

On March 30, 2012, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 19%, which is expected to reduce annual billings by $567 million. The decrease in fuel costs is driven primarily by lower natural gas prices as a result of increased natural gas supplies. The Georgia PSC is scheduled to vote on this matter on June 21, 2012. As proposed, the rate decrease would become effective July 1, 2012; however, Georgia Power is currently working with the Georgia PSC to potentially implement the proposed decrease effective June 1, 2012. 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 — 2011 Integrated Resource Plan Update” and “Retail Regulatory Matters — 2011 Integrated Resource Plan Update,” respectively, in Item 8 of the Form 10-K for additional information.

On March 20, 2012, the Georgia PSC approved Georgia Power’s request to decertify and retire two coal-fired generation units at Plant Branch as of October 31, 2013 and December 31, 2013 and an oil-fired unit at Plant Mitchell as of March 26, 2012, which was included in Georgia Power’s 2011 IRP Update. The Georgia PSC also approved three PPAs totaling 998 MWs with Southern Power for capacity and energy that will commence in 2015 and end in 2030. The PPAs remain subject to FERC approval. The ultimate outcome of this matter cannot be determined at this time.

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.

On February 16, 2012, a group of petitioners who had intervened in the NRC’s combined construction and operating licenses (COLs) proceedings for Plant Vogtle Units 3 and 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the NRC’s issuance of the COLs. In addition, on February 16, 2012, another group of petitioners filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the NRC’s certification of the Westinghouse Design Certification Document, as amended (DCD). On April 3, 2012, the U.S. Court of Appeals for the District of Columbia Circuit granted a motion filed by these two groups of petitioners to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the COLs for Plant Vogtle Units 3 and 4 with the U.S. District Court for the District of Columbia. Georgia Power has filed a motion to intervene in these proceedings and intends to vigorously contest these petitions.

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. In addition, the Georgia PSC voted to approve inclusion of the related CWIP accounts in rate base. Also in 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that allows Georgia Power to recover financing costs for nuclear construction projects by including the related CWIP accounts in rate base during the construction period. 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. The Georgia PSC has ordered Georgia Power to report against this total certified cost of approximately $6.1 billion. In addition, in December 2010, the Georgia PSC approved Georgia Power’s NCCR tariff. The NCCR tariff became effective January 1, 2011 and adjustments are filed with the Georgia PSC on November 1 of each year to become effective on January 1 of the following year. 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 March 31, 2012, approximately $68 million of these 2009 and 2010 costs remained in CWIP.

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 Westinghouse and Stone & Webster, Inc. (collectively, Consortium) have established both informal and formal dispute resolution procedures in accordance with the engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 MWs each and related facilities, structures, and improvements at Plant Vogtle entered into by the parties (Vogtle 3 and 4 Agreement) in order to resolve issues arising during the course of constructing a project of this magnitude. The Consortium and Georgia Power (on behalf of the Owners) have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

During the course of construction activities, issues have arisen that may impact the project budget and schedule, including costs associated with design changes to the DCD, and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the COLs. The Owners and the Consortium have begun negotiations regarding these issues, including the assertion by the Consortium that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. In preliminary discussions, the Consortium has provided its initial estimate of its proposed adjustment to the contract price. The Consortium’s estimated adjustment attributable to Georgia Power (based on Georgia Power’s ownership interest) is approximately $400 million (in 2008 dollars) with respect to these issues, which include an initial estimate of costs for efforts to maintain the projected in-service dates of 2016 and 2017 for Plant Vogtle Units 3 and 4, respectively. Georgia Power has not agreed with the amount of these proposed adjustments or that the Owners have responsibility for any costs related to these issues. Georgia Power expects negotiations with the Consortium to continue over the next several months during which time the parties will attempt to reach a mutually acceptable compromise of their positions. If a compromise cannot be reached, formal dispute resolution, including litigation, may follow. Georgia Power intends to vigorously defend its positions. If these costs are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. Additional claims by the Consortium or Georgia Power (on behalf of the Owners) are expected to arise throughout the construction of Plant Vogtle Units 3 and 4.

In addition, there are processes in place to assure compliance with the design requirements specified in the DCD and the COLs, including rigorous inspection by Southern Nuclear and the NRC that occurs throughout construction. A recent routine NRC inspection identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. Georgia Power expects to receive official notice of these findings from the NRC. Georgia Power, on behalf of the Owners, is currently engaged in constructive discussions with the Consortium to identify appropriate corrective actions. Various inspection issues are expected as construction proceeds.

There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including legal challenges to the NRC issuance of the COLs and certification of the DCD. 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

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters — Georgia Power — Other Construction” and “Construction — Other Construction,” respectively, in Item 8 of the Form 10-K for additional information.

Georgia Power placed Plant McDonough Unit 5 into service on April 26, 2012. Plant McDonough Unit 6 is expected to be placed into service in November 2012. Plant McDonough Unit 1 was retired on February 29, 2012.

Gulf Power

Retail Base Rate Case

See Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Retail Base Rate Case” in Item 8 of the Form 10-K for additional information.

On March 12, 2012, the Florida PSC approved a permanent increase in retail base rates and charges of $64 million effective April 11, 2012. The amount of the permanent increase includes the previously approved $38.5 million interim retail rate increase implemented in September 2011. The Florida PSC’s decision on the amount of the permanent increase also included a determination that none of the base rate revenues collected on an interim basis would be refunded. Gulf Power’s authorized retail ROE is a range of 9.25% to 11.25% with new retail base rates set at the midpoint retail ROE of 10.25%. In addition, the Florida PSC also approved a step increase to Gulf Power’s retail base rates and charges of $4 million to be effective in January 2013. On April 18, 2012, Gulf Power filed a motion to reconsider one aspect of the decision dealing with property acquired as a potential site for a future generating plant. If the motion is granted, the previously approved rates would be increased by an additional $2 million. The ultimate outcome of this matter cannot be determined at this time.

Cost Recovery Clauses

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

Fuel Cost Recovery

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

Over recovered fuel costs at March 31, 2012 totaled $28.8 million compared to $9.9 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

Purchased Power Capacity Recovery

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.

Over recovered purchased power capacity costs at March 31, 2012 totaled $9.6 million compared to $8.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

Environmental Cost Recovery

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

Over recovered environmental costs at March 31, 2012 totaled $4.0 million compared to $10.0 million at December 31, 2011. These amounts are included in other regulatory liabilities, current on Gulf Power’s Condensed Balance Sheets herein.

On April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015.

Energy Conservation Cost Recovery

See Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Energy Conservation Cost Recovery” in Item 8 of the Form 10-K for additional information.

Under recovered energy conservation costs at March 31, 2012 totaled $2.0 million compared to $3.1 million at December 31, 2011. These amounts are included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein.

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.

On April 2, 2012, Mississippi Power filed a motion to suspend the 2011 PEP lookback filing. Unresolved matters related to certain costs included in the 2010 PEP lookback filing also impact the 2011 PEP lookback filing, making it impractical to determine Mississippi Power’s actual retail return on investment for 2011 for purposes of the 2011 PEP lookback filing. The ultimate outcome of these matters cannot be determined at this time.

System Restoration Rider

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

On February 2, 2012, Mississippi Power submitted its 2012 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2012 SRR rate level remain at zero and Mississippi Power be allowed to accrue approximately $3.7 million to the property damage reserve in 2012. On April 3, 2012, 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 April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power’s portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power’s portion of the cost is expected to be recovered through the ECO Plan. As of March 31, 2012, total project expenditures were $55.6 million, with Mississippi Power’s portion being $27.8 million.

On February 14, 2012, Mississippi Power submitted its 2012 ECO Plan notice, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct scrubbers on Plant Daniel Units 1 and 2, Mississippi Power will revise the 2012 ECO Plan notice excluding scrubber expenditures from rate base, which is expected to result in little or no rate change.

The ultimate outcome of these matters 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.

At March 31, 2012, the amount of over recovered retail fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $50.9 million compared to $42.4 million at December 31, 2011. Mississippi Power also has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At March 31, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $18.1 million and $2.4 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at March 31, 2012 and December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Power’s Condensed Balance Sheets herein was $1.7 million. 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.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for information regarding Mississippi Power’s construction of the Kemper IGCC.

In May 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the Mississippi PSC order confirming Mississippi Power’s application for a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. In June 2010, the Mississippi PSC issued the CPCN (2010 MPSC Order).

In June 2010, the Sierra Club filed an appeal of the Mississippi PSC’s June 2010 decision to grant the CPCN 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 2010 MPSC Order and, on March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court. On March 15, 2012, the Mississippi Supreme Court reversed the Chancery Court’s decision and the 2010 MPSC Order and remanded the matter to the Mississippi PSC to correct the 2010 MPSC Order. The Mississippi Supreme Court concluded that the 2010 MPSC Order did not cite in sufficient detail substantial evidence upon which the Mississippi Supreme Court could determine the basis for the findings of the Mississippi PSC granting the CPCN.

On March 30, 2012, the Mississippi PSC issued temporary authorization for the continuation of construction of the Kemper IGCC until the earlier of the conclusion of the Mississippi PSC’s May 2012 open meeting or immediately upon the issuance of any final order issued by the Mississippi PSC on remand that conclusively addresses the mandate. On April 24, 2012, the Mississippi PSC issued a detailed order on remand (2012 MPSC Order) confirming the CPCN for the Kemper IGCC subject to the same conditions set forth in the 2010 MPSC Order. On April 26, 2012, the Sierra Club filed a motion for stay and a notice of appeal of the 2012 MPSC Order with the Chancery Court. On May 2, 2012, Mississippi Power filed a petition to join the appeal.

The certificated cost estimate of the Kemper IGCC is $2.4 billion, net of $245.3 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (CCPI2) and excluding the cost of the lignite mine and equipment and the carbon dioxide (CO₂ ) pipeline facilities. The 2012 MPSC Order, like the 2010 MPSC Order, (1) approved a construction cost cap of up to $2.88 billion (exemptions from the cost cap include the cost of the lignite mine and equipment and the CO₂ pipeline facilities), (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal, and (3) approved financing cost recovery on CWIP balances not to exceed the certificated cost estimate, which provided for the accrual of AFUDC in 2010 and 2011 and provides for the current recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014, (provided that the amount of CWIP allowed is (i) reduced by the amount of state and federal government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). As of March 31, 2012, Mississippi Power had utilized substantially all of its contingency contained in the certificated cost estimate. Mississippi Power anticipates that the costs to complete construction of the portion of the Kemper IGCC subject to the construction cost cap will be less than the cost cap but will likely exceed the certificated cost estimate.

The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. Of the total costs incurred through March 2009, $46 million has been reviewed and approved by the Mississippi PSC. A decision regarding the remaining $5 million has been deferred to a later date. The timing of the review of the remaining Kemper IGCC costs has not been determined.

The Kemper IGCC plant, expected to begin commercial operation in May 2014, will use locally mined lignite (an abundant, lower heating value coal) from a mine adjacent to the plant as fuel. The mine is scheduled to be placed into service in June 2013. In conjunction with the Kemper IGCC, Mississippi Power will own the 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 million, of which $79.7 million has been incurred through March 31, 2012. The asset retirement obligation associated with the reclamation and restoration of the mine currently under construction was immaterial at March 31, 2012. In May 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage the mining operations. The contract with Liberty Fuels is effective June 2010 through the end of the mine reclamation. On December 13, 2011, the Mississippi Department of Environmental Quality (MDEQ) approved the surface coal mining and the water pollution control permits for the mining operations operated by Liberty Fuels. On January 12, 2012, two individuals each filed a notice of appeal and a request for evidentiary hearing with the MDEQ regarding the surface coal mining and water pollution control permits. On March 8, 2012, the MDEQ permit board affirmed its issuance of the surface coal mining and water pollution control permits.

In 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 credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the recapture rules for Section 48A investment tax credits. Through March 31, 2012, Mississippi Power received or accrued tax benefits totaling $141.1 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. As a result of 100% bonus tax depreciation on certain assets placed, or to be placed, in service in 2011 and 2012, and the subsequent reduction in federal taxable income, Mississippi Power estimates that it will not be able to utilize $105.0 million of these tax credits until after 2012. IRS guidelines allow the resulting unused credits to be carried forward for 20 years.

In July 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In December 2010, Mississippi Power and SMEPA filed a joint petition with the Mississippi PSC requesting regulatory approval of SMEPA’s 17.5% undivided interest in the Kemper IGCC. On February 28, 2012, the Mississippi PSC approved the joint petition for the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA to be applied to the purchase. While the expectation is that the amount will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposit upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power’s senior unsecured credit rating falls below a BBB+ and/or Baa1. Given the interest-bearing nature of the deposit and SMEPA’s ability to request a refund, the deposit has been presented as a current liability in Mississippi Power’s Condensed Balance Sheet herein and as financing proceeds in the statement of cash flows.

As of March 31, 2012, Mississippi Power had spent a total of $1.30 billion on the Kemper IGCC including the cost of the lignite mine and equipment, the CO₂ pipeline facilities, and regulatory filing costs. Of this total, $1.28 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $22.9 million was recorded in other regulatory assets, $2.3 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Certificated New Plant” in Item 8 of the Form 10-K for information on the proposed rate schedules related to the Kemper IGCC.

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

XML

Contingencies and Regulatory Matters (Details) (USD $)	3 Months Ended		3 Months Ended	1 Months Ended	3 Months Ended		1 Months Ended		3 Months Ended		3 Months Ended						3 Months Ended	12 Months Ended	13 Months Ended										3 Months Ended
	Mar. 31, 2012 Entity	Dec. 31, 2011	Mar. 31, 2012 Kivalina Case [Member]	Jul. 31, 2007 Alabama Power [Member]	Mar. 31, 2012 Alabama Power [Member] Coal_Fired_Generating_Facilities Claims	Dec. 31, 2011 Alabama Power [Member]	Apr. 30, 2012 Georgia Power [Member]	Jul. 31, 2007 Georgia Power [Member]	Mar. 31, 2012 Georgia Power [Member] MW Coal_Fired_Generating_Facilities Claims	Dec. 31, 2011 Georgia Power [Member]	Mar. 31, 2012 Gulf Power [Member]	Apr. 18, 2012 Gulf Power [Member]	Mar. 12, 2012 Gulf Power [Member]	Dec. 31, 2011 Gulf Power [Member]	Mar. 12, 2012 Gulf Power [Member] Minimum [Member]	Mar. 12, 2012 Gulf Power [Member] Maximum [Member]	Mar. 31, 2012 Mississippi Power [Member]	Dec. 31, 2009 Mississippi Power [Member]	Apr. 30, 2012 Mississippi Power [Member]	Feb. 14, 2012 Mississippi Power [Member]	Feb. 02, 2012 Mississippi Power [Member]	Dec. 31, 2011 Mississippi Power [Member]	May 26, 2010 Mississippi Power [Member]	Mar. 31, 2012 Mississippi Power [Member] MRA Revenue [Member]	Dec. 31, 2011 Mississippi Power [Member] MRA Revenue [Member]	Mar. 31, 2012 Mississippi Power [Member] MB Revenue [Member]	Dec. 31, 2011 Mississippi Power [Member] MB Revenue [Member]	Mar. 31, 2012 Gulf Power and Mississippi Power [Member]	Mar. 31, 2012 Electricity Generation Plant, Non-Nuclear [Member] Mississippi Power [Member]	Mar. 31, 2012 Mine [Member] Mississippi Power [Member]
Contingencies and Regulatory Matters (Textual) [Abstract]
Number of coal fired generating facilities at which new source review violations occurred					5				3
Number of dismissed claims against Subsidiary					5
Total Number of Claims					8
Claims left for summary disposition or trial against Alabama Power					3
Environmental remediation liability									$ 20,000,000		$ 60,000,000
Damages from lost property values and relocating village cost, lower range			95,000,000
Civil penalties per violation rate									37,500
Number of times of punitive damages in comparison to cost incurred by Environmental Protection Agency									3
Other deferred credits and liabilities	15,725,000,000	15,383,000,000			5,419,000,000	5,326,000,000			6,833,000,000	6,703,000,000	1,093,069,000			1,021,743,000			816,133,000					776,781,000
Claims awarded to companies related to nuclear fuel disposal litigation				17,000,000				30,000,000
Damages awarded							27,000,000
Increase in base rate under cost based electric tariff due to settlement																	22,600,000
Revised rate period																	12 months
Revenue to be received from increase in base rate																	17,000,000
Percentage of increase in annual revenue																				0.30%
Amount approved for property damage reserve																					3,700,000
Amount of over recovered retail fuel costs included in the balance sheets																	50,900,000					42,400,000
Amount of over recovered fuel costs																								18,100,000	14,300,000	2,400,000	2,200,000
Amount of over recovered MRA emissions allowance cost included in the balance sheets																	1,700,000					1,700,000
Deferred cost related to construction																	5,000,000
Grant funds receivable during construction																	245,300,000
Portion of deferred construction cost under review																	46,000,000
Reduction in projected in-service cost due to recovered cost									4,400,000,000
Percentage decrease in fuel rates requested with Georgia Public Service Commission									19.00%
Under recovered energy conservation costs											2,000,000			3,100,000
Electric generating capacity in Mega Watts under consortium agreement									1,100
Recovery of project financing cost as per Legislation									1,700,000,000
Total certified cost									6,100,000,000
Over recovered fuel cost balance									22,000,000
Under recovered regulatory clause revenues	5,000,000	143,000,000								137,000,000	4,536,000			5,530,000
Over recovered purchased power capacity costs											9,600,000			8,000,000
Over recovered environmental cost.											4,000,000			10,000,000
Amount of government construction cost incentive received																							296,000,000
Maximum cap construction cost																	2,880,000,000
Cost incurred for use of mine																	79,700,000
Term of management fee contract with liberty fuels company																														40 years
Tax credits (Phase I)																		133,000,000
Tax credit (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%
Received or accrued tax benefits related to Tax credit																	141,100,000
Percentage of bonus tax																	100.00%
Amount of credit not available till future period																	105,000,000
Carry forward period of tax credit																	20 years
Percentage interest acquired under asset purchase agreement																	17.50%
Percentage interest transferred under asset purchase agreement																	17.50%
Deposit received																	150,000,000
Maximum period to refund deposit upon termination of asset purchase agreement																	60 days
Estimated cost																													2,400,000,000
Percentage of financing costs of construction work in progress																							100.00%
Cost deferred in other regulatory assets	3,486,000,000	3,532,000,000			995,000,000	994,000,000			1,562,000,000	1,604,000,000	316,519,000			323,116,000			190,894,000					185,694,000
Other deferred charges and assets	451,000,000	481,000,000			161,000,000	186,000,000			203,000,000	187,000,000	29,433,000			39,493,000			30,422,000					28,674,000
Capacity of units include application request by Georgia Power that country PSC certify purchase from four PPAs selected through 2015 request for proposal process									998
Retail rate of return on common equity															9.25%	11.25%
Estimated cost of scrubber project																	330,000,000											660,000,000
Ownership percentage in Scrubber project											50.00%						50.00%
Expected decrease in annual billings for fuel costs									567,000,000
Scrubber project expenditures amount																	27,800,000											55,600,000
Cost deferred in other regulatory assets																	22,900,000
Previously expensed																	1,000,000
Amortization to earnings of financing costs capitalized over the five year period									91,000,000
Costs included in CWIP									68,000,000								1,280,000,000
Consortium provided initial estimate of proposed adjustment to contract price									400,000,000
Damages from lost property values and relocating village cost, upper range			400,000,000
Increase in retail rates and charges													64,000,000
Previously approved interim retail rate increase													38,500,000
Average retail rate of return on common equity											10.25%
Increase in retail rates and charges in next fiscal year											4,000,000
Increase in rates due to motion grant												2,000,000
Over Recovered Fuel Cost											28,800,000			9,900,000
Estimated capital cost of mine																	245,000,000
Cost incurred by Mississippi Power associated with plant including regulatory filing costs																	1,300,000,000
Costs associated with CCP12 grant funds																	245,300,000
Other deferred charges and assets																	2,300,000
Contingencies and Regulatory Matters (Additional Textual) [Abstract]
Civil penalties under Clean Air Act per day, lower range	25,000
Civil penalties under Clean Air Act per day, upper range	37,500
Number of entities received notice from TCEQ requesting their participation in anticipated site redemption	100
Damages from lost property values and relocating village cost, lower range			$ 95,000,000

XML

Effective Tax Rate and Unrecognized Tax Benefits (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Impact on effective tax rate
Tax positions impacting the effective tax rate	$ 59	$ 69
Tax positions not impacting the effective tax rate	53	51
Balance of unrecognized tax benefits	112	120
Accrued interest for unrecognized tax benefits
Interest accrued as of December 31, 2011	10
Interest reclassified due to settlements	(5)
Interest accrued during the period	1
Balance as of March 31, 2012	6
Georgia Power [Member]
Impact on effective tax rate
Tax positions impacting the effective tax rate	24
Tax positions not impacting the effective tax rate	20
Balance of unrecognized tax benefits	44	47
Accrued interest for unrecognized tax benefits
Interest accrued as of December 31, 2011	6
Interest reclassified due to settlements	(2)
Interest accrued during the period	1
Balance as of March 31, 2012	5
Other Registrants [Member]
Impact on effective tax rate
Tax positions impacting the effective tax rate	5
Tax positions not impacting the effective tax rate	32
Balance of unrecognized tax benefits	37
Accrued interest for unrecognized tax benefits
Interest accrued as of December 31, 2011	3
Interest reclassified due to settlements	$ (3)

XML

Stockholder's Equity (Tables)

3 Months Ended

Mar. 31, 2012

Stockholders' Equity [Abstract]

Earnings per Share

	Three Months Ended March 31, 2012	Three Months Ended March 31, 2011
	(in millions)
As reported shares	868	848
Effect of options and performance share award units	9	6
Diluted shares	877	854

Changes in Stockholders' Equity

	Number of Common Shares		Common Stockholders’	Preferred and Preference Stock of	Total     Stockholders’
	Issued	Treasury	Equity	Subsidiaries	Equity
	(in thousands)			(in millions)
Balance at December 31, 2011	865,664	(539)	$17,578	$707	$18,285
Net income after dividends on preferred and preference stock	—	—	368	—	368
Other comprehensive income (loss)	—	—	6	—	6
Stock issued	3,571	—	157	—	157
Cash dividends on common stock	—	—	(410)	—	(410)
Other	—	(6)	—	—	—
Balance at March 31, 2012	869,235	(545)	$17,699	$707	$18,406
Balance at December 31, 2010	843,814	(474)	$16,202	$707	$16,909
Net income after dividends on preferred and preference stock	—	—	422	—	422
Other comprehensive income (loss)	—	—	4	—	4
Stock issued	5,784	—	222	—	222
Cash dividends on common stock	—	—	(385)	—	(385)
Other	—	(1)	—	—	—
Balance at March 31, 2011	849,598	(475)	$16,465	$707	$17,172