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 June 30, 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 June 30, 2012
The Southern Company	Par Value $5 Per Share	874,796,883
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

June 30, 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		38
	Condensed Statements of Comprehensive Income		38
	Condensed Statements of Cash Flows		39
	Condensed Balance Sheets		40
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		42
	Georgia Power Company
	Condensed Statements of Income		59
	Condensed Statements of Comprehensive Income		59
	Condensed Statements of Cash Flows		60
	Condensed Balance Sheets		61
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		63
	Gulf Power Company
	Condensed Statements of Income		83
	Condensed Statements of Comprehensive Income		83
	Condensed Statements of Cash Flows		84
	Condensed Balance Sheets		85
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		87
	Mississippi Power Company
	Condensed Statements of Income		106
	Condensed Statements of Comprehensive Income		106
	Condensed Statements of Cash Flows		107
	Condensed Balance Sheets		108
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		110
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		133
	Condensed Consolidated Statements of Comprehensive Income		133
	Condensed Consolidated Statements of Cash Flows		134
	Condensed Consolidated Balance Sheets		135
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		137
	Notes to the Condensed Financial Statements		150
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		36
Item 4.	Controls and Procedures		36

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2012

		Page                      Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings		185
Item 1A.	Risk Factors		185
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		Inapplicable
Item 3.	Defaults Upon Senior Securities		Inapplicable
Item 4.	Mine Safety Disclosures		Inapplicable
Item 5.	Other Information		Inapplicable
Item 6.	Exhibits		186
	Signatures		190

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
ARO	Asset retirement obligation
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
Fitch	Fitch, Inc.
Form 10-K	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2011
GAAP	Generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IIC	Intercompany Interchange Contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
Kemper IGCC	Integrated coal gasification combined cycle facility under construction in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatt
MWH	Megawatt-hour
NCCR	Georgia Power’s Nuclear Construction Cost Recovery
NDR	Alabama Power’s natural disaster reserve
NRC	Nuclear Regulatory Commission
NSR	New Source Review
OCI	Other Comprehensive Income
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

5

ROE	Return on equity
SEC	Securities and Exchange Commission
SEGCO	Southern Electric Generating Company
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 Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company
S&P	Standard and Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Westinghouse	Westinghouse Electric Company LLC
wholesale revenues	revenues generated from sales for resale

6

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related estimated expenditures, access to sources of capital, projections for the qualified pension plan 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 June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	3,597		$	3,842		$	6,689		$	7,238
Wholesale revenues		415			507			764			956
Other electric revenues		154			154			302			303
Other revenues		15			18			30			36
Total operating revenues		4,181			4,521			7,785			8,533
Operating Expenses:
Fuel		1,290			1,673			2,354			3,149
Purchased power		150			145			291			245
Other operations and maintenance		944			910			1,911			1,854
MC Asset Recovery insurance settlement		(19	)		—			(19	)		—
Depreciation and amortization		445			430			886			848
Taxes other than income taxes		228			227			453			447
Total operating expenses		3,038			3,385			5,876			6,543
Operating Income		1,143			1,136			1,909			1,990
Other Income and (Expense):
Allowance for equity funds used during construction		32			36			63			71
Interest expense, net of amounts capitalized		(220	)		(199	)		(431	)		(421	)
Other income (expense), net		13			(4	)		11			(2	)
Total other income and (expense)		(175	)		(167	)		(357	)		(352	)
Earnings Before Income Taxes		968			969			1,552			1,638
Income taxes		329			349			529			580
Consolidated Net Income		639			620			1,023			1,058
Dividends on Preferred and Preference Stock of Subsidiaries		16			16			32			32
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	623		$	604		$	991		$	1,026
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.71		$	0.71		$	1.14		$	1.20
Diluted EPS	$	0.71		$	0.70		$	1.13		$	1.20
Average number of shares of common stock outstanding (in millions)
Basic		872			855			870			851
Diluted		880			862			879			858
Cash dividends paid per share of common stock	$	0.4900		$	0.4725		$	0.9625		$	0.9275

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 June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)						(in millions)
Consolidated Net Income	$	639		$	620		$	1,023		$	1,058
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(8), $-, $(5) and $2, respectively		(10	)		—			(7	)		3
Reclassification adjustment for amounts included in net income, net of tax of $2, $1, $3 and $3, respectively		2			—			4			3
Marketable securities:
Change in fair value, net of tax of $-, $2, $- and $1, respectively		—			3			—			2
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $(1), $1 and $1, respectively		1			1			2			—
Total other comprehensive income (loss)		(7	)		4			(1	)		8
Dividends on preferred and preference stock of subsidiaries		(16	)		(16	)		(32	)		(32	)
Comprehensive Income	$	616		$	608		$	990		$	1,034

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 Six Months Ended June 30,
	2012			2011
	(in millions)
Operating Activities:
Consolidated net income	$	1,023		$	1,058
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		1,064			1,011
Deferred income taxes		327			427
Allowance for equity funds used during construction		(63	)		(71	)
Pension, postretirement, and other employee benefits		13			(38	)
Stock based compensation expense		35			27
Retail fuel cost over recovery—long-term		44			—
Other, net		(17	)		(6	)
Changes in certain current assets and liabilities —
-Receivables		(55	)		(156	)
-Fossil fuel stock		(305	)		81
-Other current assets		(53	)		(106	)
-Accounts payable		(167	)		58
-Accrued taxes		45			300
-Accrued compensation		(216	)		(193	)
-Retail fuel cost over recovery—short-term		101			(6	)
-Other current liabilities		(19	)		3
Net cash provided from operating activities		1,757			2,389
Investing Activities:
Property additions		(2,356	)		(2,126	)
Investment in restricted cash		(230	)		(3	)
Distribution of restricted cash		49			61
Nuclear decommissioning trust fund purchases		(576	)		(1,405	)
Nuclear decommissioning trust fund sales		574			1,401
Proceeds from property sales		2			17
Cost of removal, net of salvage		(58	)		(68	)
Change in construction payables		(134	)		37
Other investing activities		(62	)		22
Net cash used for investing activities		(2,791	)		(2,064	)
Financing Activities:
Decrease in notes payable, net		(406	)		(440	)
Proceeds —
Long-term debt issuances		2,487			1,950
Interest-bearing refundable deposit related to asset sale		150			—
Common stock issuances		316			482
Redemptions —
Long-term debt		(1,319	)		(1,504	)
Payment of common stock dividends		(837	)		(787	)
Payment of dividends on preferred and preference stock of subsidiaries		(32	)		(32	)
Other financing activities		19			(4	)
Net cash provided from (used for) financing activities		378			(335	)
Net Change in Cash and Cash Equivalents		(656	)		(10	)
Cash and Cash Equivalents at Beginning of Period		1,315			447
Cash and Cash Equivalents at End of Period	$	659		$	437
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $41 and $35 capitalized for 2012 and 2011, respectively)	$	391		$	419
Income taxes, net		(34	)		(355	)
Noncash transactions — accrued property additions at end of period		488			407

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 June 30, 2012			At December 31, 2011
	(in millions)
Current Assets:
Cash and cash equivalents	$	659		$	1,315
Restricted cash and cash equivalents		192			8
Receivables —
Customer accounts receivable		1,164			1,074
Unbilled revenues		497			376
Under recovered regulatory clause revenues		20			143
Other accounts and notes receivable		261			282
Accumulated provision for uncollectible accounts		(23	)		(26	)
Fossil fuel stock, at average cost		1,672			1,367
Materials and supplies, at average cost		919			903
Vacation pay		161			160
Prepaid expenses		577			385
Other regulatory assets, current		208			239
Other current assets		66			46
Total current assets		6,373			6,272
Property, Plant, and Equipment:
In service		61,577			59,744
Less accumulated depreciation		21,616			21,154
Plant in service, net of depreciation		39,961			38,590
Other utility plant, net		53			55
Nuclear fuel, at amortized cost		807			774
Construction work in progress		5,745			5,591
Total property, plant, and equipment		46,566			45,010
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,235			1,207
Leveraged leases		660			649
Miscellaneous property and investments		260			262
Total other property and investments		2,155			2,118
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,390			1,365
Unamortized debt issuance expense		157			156
Unamortized loss on reacquired debt		288			285
Deferred under recovered regulatory clause revenues		29			48
Other regulatory assets, deferred		3,484			3,532
Other deferred charges and assets		455			481
Total deferred charges and other assets		5,803			5,867
Total Assets	$	60,897		$	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 June 30, 2012			At December 31, 2011
	(in millions)
Current Liabilities:
Securities due within one year	$	2,075		$	1,717
Interest-bearing refundable deposit related to asset sale		150			—
Notes payable		453			859
Accounts payable		1,253			1,553
Customer deposits		363			347
Accrued taxes —
Accrued income taxes		17			13
Unrecognized tax benefits		6			22
Other accrued taxes		337			425
Accrued interest		237			226
Accrued vacation pay		204			205
Accrued compensation		246			450
Liabilities from risk management activities		160			209
Other regulatory liabilities, current		144			125
Other current liabilities		443			426
Total current liabilities		6,088			6,577
Long-term Debt		19,459			18,647
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		9,352			8,809
Deferred credits related to income taxes		216			224
Accumulated deferred investment tax credits		704			611
Employee benefit obligations		2,409			2,442
Asset retirement obligations		1,385			1,321
Other cost of removal obligations		1,195			1,165
Other regulatory liabilities, deferred		295			297
Other deferred credits and liabilities		588			514
Total deferred credits and other liabilities		16,144			15,383
Total Liabilities		41,691			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 — June 30, 2012: 875 million shares
— December 31, 2011: 866 million shares
Treasury — June 30, 2012: 0.6 million shares
— December 31, 2011: 0.5 million shares
Par value		4,377			4,328
Paid-in capital		4,755			4,410
Treasury, at cost		(18	)		(17	)
Retained earnings		9,122			8,968
Accumulated other comprehensive loss		(112	)		(111	)
Total Common Stockholders’ Equity		18,124			17,578
Preferred and Preference Stock of Subsidiaries		707			707
Total Stockholders’ Equity		18,831			18,285
Total Liabilities and Stockholders’ Equity	$	60,897		$	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

SECOND QUARTER 2012 vs. SECOND QUARTER 2011

AND

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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$19	3.1	$(35)	(3.4)

Southern Company’s second quarter 2012 net income after dividends on preferred and preference stock of subsidiaries was $623 million ($0.71 per share) compared to $604 million ($0.71 per share) for the second quarter 2011. The increase for the second quarter 2012 when compared to the corresponding period in 2011 was primarily the result of 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 retail base revenues at Gulf Power, increases in usage and customer growth, an insurance recovery received related to the litigation settlement with MC Asset Recovery, LLC, and lower income taxes. The net income increase for the second quarter 2012 was partially offset by a decrease in revenues due to milder weather, an increase in operations and maintenance expenses, an increase in depreciation on additional plant in service related to new generation, transmission, distribution, and environmental projects, an increase in interest expense, and lower energy revenues at Southern Power.

Southern Company’s year-to-date 2012 net income after dividends on preferred and preference stock of subsidiaries was $991 million ($1.14 per share) compared to $1.03 billion ($1.20 per share) for year-to-date 2011. The net income decrease for year-to-date 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 operations and maintenance expenses, an increase in depreciation on additional plant in service related to new generation, transmission, distribution, and environmental projects, an increase in interest expense, and lower energy revenues at Southern Power. The net income decrease for year-to-date 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 retail base and retail interim revenues at Gulf Power, increases in usage and customer growth, and an insurance recovery received related to the litigation settlement with MC Asset Recovery, LLC.

15

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(245)	(6.4)	$(549)	(7.6)

In the second quarter 2012, retail revenues were $3.60 billion compared to $3.84 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $6.69 billion compared to $7.24 billion for the corresponding period in 2011.

Details of the change to retail revenues were as follows:

	Second Quarter 2012			Year-to-Date 2012
		(in millions)	(% change)		(in millions)	(% change)
Retail – prior year		$3,842			$7,238
Estimated change in –
Rates and pricing		75	2.0		134	1.9
Sales growth (decline)		23	0.6		40	0.5
Weather		(84)	(2.2)		(197)	(2.7)
Fuel and other cost recovery		(259)	(6.8)		(526)	(7.3)
Retail – current year		$3,597	(6.4)%		$  6,689	(7.6)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to the elimination of a tax-related adjustment under Alabama Power’s rate structure and an increase related to retail base and retail interim revenues at Gulf Power. Also contributing to the increase were increases in retail revenues at Georgia Power due to base tariff increases effective April 1, 2012 related to placing Plant McDonough-Atkinson Units 4 and 5 in service, the NCCR and demand-side management tariff increases effective January 1, 2012, as approved by the Georgia PSC, and the rate pricing effect of decreased customer usage, partially offset by lower contributions from market-driven rates from commercial and industrial customers.

Revenues attributable to changes in sales increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011. For second quarter 2012, the increase was due to a 2.1% increase in weather-adjusted residential KWH sales and a 1.2% increase in weather-adjusted commercial KWH sales, partially offset by a 0.1% decrease in industrial KWH sales. The increases in weather-adjusted residential and commercial KWH sales for the second quarter 2012 are due to increases in usage and customer growth. The decrease in industrial KWH sales for the second quarter 2012 is primarily due to decreases in the textiles and paper sectors, largely offset by increases in the pipeline and transportation sectors. For year-to-date 2012, the increase was due to a 1.3% increase in weather-adjusted residential KWH sales and a 0.9% increase in industrial KWH sales, while weather-adjusted commercial KWH sales remained flat. The increase in weather-adjusted residential KWH sales for year-to-date 2012 is due to increases in usage and customer growth. The increase in industrial KWH sales year-to-date 2012 is primarily due to increases in the pipeline, lumber, and transportation sectors, partially offset by decreases in the textiles sector.

Revenues resulting from changes in weather decreased $84 million in the second quarter 2012 and $197 million year-to-date 2012 when compared to the corresponding periods in 2011 as a result of milder weather.

16

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and other cost recovery revenues decreased $259 million in the second quarter 2012 and decreased $526 million for year-to-date 2012 when compared to the corresponding periods 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 energy component of purchased power costs, and do not affect net income.

Wholesale Revenues

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(92)	(18.1)	$(192)	(20.1)

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

In the second quarter 2012, wholesale revenues were $415 million compared to $507 million for the corresponding period in 2011, reflecting a $106 million decrease in energy revenues, partially offset by a $14 million increase in capacity revenues. The decrease in energy revenues was primarily related to a reduction in the average price of energy and lower energy sales mainly due to lower customer demand.

For year-to-date 2012, wholesale revenues were $764 million compared to $956 million for the corresponding period in 2011, reflecting a $213 million decrease in energy revenues, partially offset by a $21 million increase in capacity revenues. The decrease in energy revenues was primarily related to a reduction in the average price of energy and lower energy sales mainly due to lower customer demand.

Fuel and Purchased Power Expenses

	Second Quarter 2012 vs. Second Quarter 2011			Year-to-Date 2012 vs. Year-to-Date 2011
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel		$(383)	(22.9)		$(795)	(25.2)
Purchased power		5	3.4		46	18.8
Total fuel and purchased power expenses		$(378)			$(749)

In the second quarter 2012, total fuel and purchased power expenses were $1.44 billion compared to $1.82 billion for the corresponding period in 2011. The decrease was primarily the result of a $415 million decrease in the average cost of fuel and purchased power and a $133 million decrease in the volume of KWHs generated, partially offset by a $170 million increase in the volume of KWHs purchased.

For year-to-date 2012, total fuel and purchased power expenses were $2.64 billion compared to $3.39 billion for the corresponding period in 2011. The decrease was primarily the result of a $777 million decrease in the average cost of fuel and purchased power and a $430 million decrease in the volume of KWHs generated, partially offset by a $458 million increase in the volume of KWHs purchased.

17

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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:

	Second Quarter 2012	Second Quarter 2011	Year-to-Date 2012	Year-to-Date 2011
Total generation (billions of KWHs)	44	48	83	94
Total purchased power (billions of KWHs)	5	2	9	4
Sources of generation (percent) —
Coal	41	56	38	54
Nuclear	17	15	18	16
Gas	41	26	41	27
Hydro	1	3	3	3
Cost of fuel, generated (cents per net KWH) —
Coal	4.18	4.06	4.14	4.01
Nuclear	0.83	0.72	0.81	0.70
Gas	2.56	4.23	2.66	4.08
Average cost of fuel, generated (cents per net KWH)	2.94	3.56	2.90	3.48
Average cost of purchased power (cents per net KWH)(a)	4.09	7.51	3.98	8.07

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

Fuel

In the second quarter 2012, fuel expense was $1.29 billion compared to $1.67 billion for the corresponding period in 2011. The decrease was primarily due to a 39.5% 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.

For year-to-date 2012, fuel expense was $2.35 billion compared to $3.15 billion for the corresponding period in 2011. The decrease was primarily due to a 34.8% 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.

Purchased Power

In the second quarter 2012, purchased power expense was $150 million compared to $145 million for the corresponding period in 2011. The increase was primarily due to a 93.3% 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 45.5% decrease in the average cost per KWH purchased.

For year-to-date 2012, purchased power expense was $291 million compared to $245 million for the corresponding period in 2011. The increase was primarily due to a 158.9% 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 50.7% decrease in the average cost per KWH purchased.

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

18

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$34	3.7	$57	3.1

In the second quarter 2012, other operations and maintenance expenses were $944 million compared to $910 million for the corresponding period in 2011. The increase was primarily the result of a $28 million increase in administrative and general costs primarily due to increases in pension costs and other employee benefits and a $16 million increase in transmission and distribution costs. The increase was partially offset by a $10 million decrease at Mississippi Power related to the expiration of an operating lease for Plant Daniel Units 3 and 4, as well as a $4 million decrease primarily related to scheduled outage and maintenance costs and commodity and labor costs.

For year-to-date 2012, other operations and maintenance expenses were $1.91 billion compared to $1.85 billion for the corresponding period in 2011. The increase was primarily the result of a $71 million increase in administrative and general costs primarily due to increases in pension costs, outside services, and other employee benefits. Also contributing to the increase was a $15 million increase in transmission and distribution costs and a $6 million net increase in customer accounts and customer service related costs. The increase was partially offset by a $21 million decrease at Mississippi Power related to the expiration of an operating lease for Plant Daniel Units 3 and 4, as well as an $18 million decrease primarily related to scheduled outage and maintenance costs and commodity and labor costs.

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.

MC Asset Recovery Insurance Settlement

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(19)	N/M	$(19)	N/M

N/M – Not meaningful

In the second quarter 2012, Southern Company received an insurance recovery related to the litigation settlement with MC Asset Recovery, LLC, which resulted in income of $19 million. See Note (B) to the Condensed Financial Statements under “Insurance Recovery” herein for additional information.

Depreciation and Amortization

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$15	3.5	$38	4.5

In the second quarter 2012, depreciation and amortization was $445 million compared to $430 million for the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $886 million compared to $848 million for the corresponding period in 2011. The increases were primarily the result of an increase in depreciation due to additional plant in service related to new generation at Georgia Power’s Plant McDonough-Atkinson Units 4 and 5, as well as transmission, distribution, and environmental projects.

19

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(11.1)	$(8)	(11.3)

In the second quarter 2012, AFUDC equity was $32 million compared to $36 million for the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $63 million compared to $71 million for the corresponding period in 2011. The decreases were primarily due to the completion of Georgia Power’s Plant McDonough-Atkinson Units 4 and 5 in December 2011 and April 2012, respectively, partially offset by increases in CWIP related to Mississippi Power’s Kemper IGCC.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$21	10.6	$10	2.4

In the second quarter 2012, interest expense, net of amounts capitalized was $220 million compared to $199 million for the corresponding period in 2011. For year-to-date 2012, interest expense, net of amounts capitalized was $431 million compared to $421 million for the corresponding period in 2011. The increases were primarily due to a $23 million reduction in interest expense in 2011 at Georgia Power resulting from the settlement of litigation with the Georgia Department of Revenue and a net increase in interest expense related to senior notes. The increases were partially offset by a decrease related to the conclusion of certain state and federal income tax audits, a decrease in interest expense on existing variable rate pollution control revenue bonds, and an increase in capitalized interest associated with construction projects at Mississippi Power and Southern Power.

Other Income (Expense), Net

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$17	N/M	$13	N/M

N/M – Not meaningful

In the second quarter 2012, other income (expense), net was $13 million compared to $(4) million for the corresponding period in 2011. For year-to-date 2012, other income (expense), net was $11 million compared to $(2) million for the corresponding period in 2011. The increases were primarily due to the conclusion of certain federal income tax audits.

Income Taxes

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(20)	(5.7)	$(51)	(8.8)

In the second quarter 2012, income taxes were $329 million compared to $349 million for the corresponding period in 2011. For year-to-date 2012, income taxes were $529 million compared to $580 million for the corresponding period in 2011. The decreases were primarily due to lower pre-tax earnings and state income tax credits. See Note (G) to the Condensed Financial Statements herein under “Unrecognized Tax Benefits” for additional information.

20

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern 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). 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

21

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern District of Mississippi dismissed the amended class action complaint filed in May 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. As part of the development of its compliance strategy for the MATS rule, the Southern Company system has entered into agreements for the construction of baghouses to control the emissions of mercury and particulates from certain generating units. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed the Southern Company system to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $2.7 billion to approximately $1.8 billion as follows:

	2012		2013	2014
			(in millions)
MATS rule	$	150	$440	$	1,215

In addition, the Southern Company system has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $1.5 billion to approximately $500 million over the 2012 through 2014 period based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:

	2012		2013	2014
			(in millions)
Proposed water and coal combustion byproducts rules	$	10	$85	$	405

While the Southern Company system’s ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, the Southern Company system estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $13 billion to $18 billion range provided in the Form 10-K. Included in this amount is approximately $750 million that is also included in the 2012 through 2014 base level capital investment of the traditional operating companies described in the Form 10-K in anticipation of these rules.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The Southern Company system’s ultimate compliance strategy and actual 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; 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. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, 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 SEGCO’s 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 the 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.

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 and fine particulate matter 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. The potential impact of the revised standard and nonattainment designation will depend on further evaluation and implementation by the Georgia Environmental Protection Division and cannot be determined at this time.

On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within the Southern Company system’s service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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 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.

23

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS—FUTURE EARNINGS POTENTIAL—“Environmental Matters—Environmental Statutes and Regulations – Water Quality” of Southern Company in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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. Environmental groups and other parties have filed lawsuits 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. The ultimate outcome of these matters 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.

On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA’s actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.

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 Sheet herein of approximately $196 million at June 30, 2012. At June 30, 2012, Alabama Power had under recovered fuel costs included in Southern Company’s Condensed Balance Sheet herein of approximately $16 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

24

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 21, 2012, the Georgia PSC approved a decrease in Georgia Power’s fuel cost recovery rates of 19%, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.

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

Alabama Power

Rate CNP

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL—“PSC Matters—Alabama Power —Rate CNP” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters—Alabama Power—Rate CNP” in Item 8 of the Form 10-K for additional information regarding Alabama Power’s recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power’s under recovered Rate CNP balance as of June 30, 2012 was $2 million as compared to $6 million at December 31, 2011. Alabama Power’s under recovered Rate CNP Environmental balance as of June 30, 2012 was $26 million as compared to $11 million at December 31, 2011. These under recovered balances at June 30, 2012 are included in deferred under recovered regulatory clause revenues on Southern Company’s Condensed Balance Sheet herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.

Natural Disaster Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS—FUTURE EARNINGS POTENTIAL—“PSC Matters—Alabama Power —Natural Disaster Reserve” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters—Alabama Power—Natural Disaster Reserve” in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2012, the NDR had an accumulated balance of $105 million, which is included in Southern Company’s Condensed Balance Sheet herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Southern Company’s Condensed Statement of Income herein.

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,

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 $535 million and $725 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 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. Current projections indicate significant uncertainty as to whether the lessee will be able to pay the

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

December 2012 semi-annual rent payment in full. 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 believes there is a reasonable possibility that it will be able to reach an agreement with the lessee and the debtholders to restructure the project. However, due to continued poor performance of the generation assets and the uncertainties surrounding the receipt of the December 2012 semi-annual rent payment and its ability to successfully restructure the project, Southern Company has placed the lease on nonaccrual status whereby income associated with this investment will not be recognized in the financial statements beginning in July 2012. 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 in Note (B) 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 the end of 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 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 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 $1.8 billion for the first six months of 2012, a decrease of $632 million from the corresponding period in 2011. Significant changes in operating cash flow for the first six months of 2012 compared to the corresponding period in 2011 include an increase in fossil fuel stock as a result of milder weather in the first six months of 2012 and lower natural gas prices and a decrease in accrued taxes due to the timing of tax payments. Net cash used for investing activities totaled $2.8 billion for the first six months of 2012, an increase of $727 million from the corresponding period in 2011. The increase was primarily due to property additions to utility plant. Net cash provided from financing activities totaled $378 million for the first six months of 2012 compared to $335 million net cash used for financing activities in the corresponding period in 2011. The change was primarily due to 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 six months of 2012 include an increase of $1.6 billion 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 $812 million due to senior note issuances.

The market price of Southern Company’s common stock at the end of the second quarter 2012 was $46.30 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $20.72 per share, representing a market-to-book ratio of 223%, compared to $40.38, $19.80, and 204%, respectively, at the end of 2011. The dividend for the second quarter 2012 was $0.49 per share compared to $0.4725 per share in the second quarter 2011.

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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 Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures to comply with existing environmental regulations, and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $2.1 billion will be required through June 30, 2013 to fund maturities of long-term debt.

See FUTURE EARNINGS POTENTIAL—“Environmental Statutes and Regulations—General” herein for a description of the Southern Company system’s estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.

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 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. In the event that the DOE does not issue a loan guarantee or Georgia Power determines that the final terms and conditions of the loan guarantee by the DOE are not in the best interest of its customers, Georgia Power expects to finance the construction of Plant Vogtle Units 3 and 4 through traditional capital markets financings. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. In the event that the DOE does not issue a conditional commitment or a final definitive loan guarantee, Mississippi Power intends to finance the construction of the Kemper IGCC through traditional capital markets financings. 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.

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

At June 30, 2012, Southern Company and its subsidiaries had approximately $659 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:

	Expires										Executable Term Loans				Due Within One Year(a)
Company	2012		2013		2014 and Beyond(b)		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		37		101		1,150		1,288		1,288		51		—		51		52
Georgia Power		—		—		1,750		1,750		1,745		—		—		—		—
Gulf Power		20		60		195		275		275		45		—		45		35
Mississippi Power		41		95		165		301		301		25		41		66		70
Southern Power		—		—		500		500		500		—		—		—		—
Other		—		50		—		50		50		25		—		25		—
Total		$98		$306		$4,760		$5,164		$5,159		$146		$41		$187		$157

(a) Reflects facilities expiring on or before June 30, 2013.

(b) All remaining Gulf Power and Mississippi Power credit agreements in this column expire in 2014.

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 June 30, 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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)
June 30, 2012:
Commercial paper	$445	0.4%	$477	0.4%	$735
Short-term bank debt	—	—%	175	1.1%	300
Total	$445	0.4%	$652	0.5%

(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 June 30, 2012 were as follows:

Credit Ratings	Maximum Potential   Collateral Requirements
	(in millions)
At BBB and Baa2	$       9
At BBB- and/or Baa3	613
Below BBB- and/or Baa3	2,668

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 an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power’s AFUDC rate, which was 9.967% per annum as of June 30, 2012, and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody’s or ceases to be rated by either of these rating agencies.

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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Market Price Risk

Southern Company is exposed to market risks, primarily commodity price risk and interest rate risk. Southern Company may also occasionally have limited exposure to foreign currency exchange rates. To manage the volatility attributable to these exposures, Southern Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Company’s policies in areas such as counterparty exposure and risk management practices. Southern Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

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

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes		Year-to-Date 2012 Changes
		Fair Value
		(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net		$(265)		$(231)
Contracts realized or settled		77		126
Current period changes(a)		18		(65)
Contracts outstanding at the end of the period, assets (liabilities), net		$(170)		$(170)

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

The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes		Year-to-Date 2012 Changes
		Fair Value
		(in millions)
Natural gas swaps		$  78		$  59
Natural gas options		17		3
Other energy-related derivatives		—		(1)
Total changes		$  95		$61

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	June 30, 2012	March 31, 2012	December 31, 2011
	mmBtu Volume
	(in millions)
Commodity—Natural gas swaps	141	123	123
Commodity—Natural gas options	101	98	66
Total hedge volume	242	221	189

The weighted average swap contract cost above market prices was approximately $0.95 per mmBtu as of June 30, 2012, $1.71 per mmBtu as of March 31, 2012, and $1.51 per mmBtu as of December 31, 2011. 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	June 30, 2012	December 31, 2011
	(in millions)
Regulatory hedges	$(164)	$(221)
Cash flow hedges	(1)	(1)
Not designated	(5)	(9)
Total fair value	$(170)	$(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 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 and six months ended June 30, 2012 were $10 million and $4 million, respectively, and were not material for the corresponding periods in 2011.

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 June 30, 2012 were as follows:

	June 30, 2012 Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3	Years 4&5
	(in millions)
Level 1	$   —	$   —	$ —	$—
Level 2	(170)	(116)	(52)	(2)
Level 3	—	—	—	—
Fair value of contracts outstanding at end of period	$(170)	$(116)	$(52)	$ (2)

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Company. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Southern Company and its subsidiaries and their derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Southern Company does not expect the impact of these rules to be material.

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

Financing Activities

During the first six months of 2012, Southern Company issued approximately 9.7 million shares of common stock for $317 million through employee and director stock plans. Since mid-2011, Southern Company has issued additional equity only through its employee and director stock plans. Southern Company plans to use the proceeds received from stock option exercises during 2012 (including the $317 million received through June 30, 2012) and 2013 to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. Pursuant to board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, in accordance with applicable securities laws.

In addition, Southern Company is not currently issuing shares of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by the independent plan administrators.

The following table outlines the debt financing activities during the first six months of 2012:

Company	Senior Note Issuances	Senior Note Redemptions and Maturities	Pollution Control Bond Issuances	Pollution Control Bond Redemptions	Other Long-Term Debt Issuances	Other Long- Term Debt Redemptions and Maturities
			(in millions)
Southern Company	$    —	$500	$ —	$ —	$ —	$ —
Alabama Power	250	250	—	1	—	—
Georgia Power	1,500	—	234	49	—	250
Gulf Power	100	91	—	—	—	—
Mississippi Power	400	90	—	—	—	75
Southern Power	—	—	—	—	4	—
Total	$2,250	$931	$234	$  50	$   4	$325

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.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power’s AFUDC rate, which was 9.967% per annum at June 30, 2012 and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody’s or ceases to be rated by either of these rating agencies.

Subsequent to June 30, 2012, Georgia Power redeemed $300 million aggregate principal amount of its Series 2007D 6.375% Senior Notes due July 15, 2047.

Subsequent to June 30, 2012, $85 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2005 and $100 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2005 were redeemed.

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.

35

PART I

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

See MANAGEMENT’S DISCUSSION AND ANALYSIS—FINANCIAL CONDITION AND LIQUIDITY—“Market Price Risk” herein for each registrant and Note 1 to the financial statements of each registrant under “Financial Instruments,” Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power and Mississippi Power, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures.

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

(b) Changes in internal controls.

There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the second quarter 2012 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

36

ALABAMA POWER COMPANY

37

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,254		$	1,244		$	2,346		$	2,370
Wholesale revenues, non-affiliates		70			70			131			138
Wholesale revenues, affiliates		6			75			20			150
Other revenues		47			51			96			102
Total operating revenues		1,377			1,440			2,593			2,760
Operating Expenses:
Fuel		343			428			649			823
Purchased power, non-affiliates		17			17			32			28
Purchased power, affiliates		66			57			106			103
Other operations and maintenance		316			290			637			587
Depreciation and amortization		160			159			317			316
Taxes other than income taxes		85			85			171			170
Total operating expenses		987			1,036			1,912			2,027
Operating Income		390			404			681			733
Other Income and (Expense):
Allowance for equity funds used during construction		4			6			9			11
Interest income		4			5			8			9
Interest expense, net of amounts capitalized		(73	)		(77	)		(146	)		(151	)
Other income (expense), net		(4	)		(7	)		(11	)		(13	)
Total other income and (expense)		(69	)		(73	)		(140	)		(144	)
Earnings Before Income Taxes		321			331			541			589
Income taxes		126			131			210			227
Net Income		195			200			331			362
Dividends on Preferred and Preference Stock		10			10			20			20
Net Income After Dividends on Preferred and Preference Stock	$	185		$	190		$	311		$	342

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
	(in millions)						(in millions)
Net Income After Dividends on Preferred and Preference Stock	$	185		$	190		$	311		$	342
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(7), $(1), $(4) and $1, respectively		(11	)		1			(7	)		3
Reclassification adjustment for amounts included in net income, net of tax of $-, $(1), $- and $(1), respectively		—			(2	)		—			(2	)
Total other comprehensive income (loss)		(11	)		(1	)		(7	)		1
Comprehensive Income	$	174		$	189		$	304		$	343

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

38

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2012			2011
	(in millions)
Operating Activities:
Net income	$	331		$	362
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		380			373
Deferred income taxes		85			174
Allowance for equity funds used during construction		(9	)		(11	)
Pension, postretirement, and other employee benefits		(8	)		(24	)
Stock based compensation expense		6			4
Other, net		(24	)		(3	)
Changes in certain current assets and liabilities —
-Receivables		(46	)		(57	)
-Fossil fuel stock		(125	)		13
-Materials and supplies		(6	)		(5	)
-Other current assets		(31	)		(66	)
-Accounts payable		(145	)		(77	)
-Accrued taxes		128			193
-Accrued compensation		(45	)		(52	)
-Other current liabilities		(10	)		(5	)
Net cash provided from operating activities		481			819
Investing Activities:
Property additions		(436	)		(485	)
Distribution of restricted cash from pollution control revenue bonds		—			11
Nuclear decommissioning trust fund purchases		(88	)		(252	)
Nuclear decommissioning trust fund sales		88			252
Cost of removal, net of salvage		(7	)		(47	)
Change in construction payables		(12	)		(14	)
Other investing activities		(9	)		(22	)
Net cash used for investing activities		(464	)		(557	)
Financing Activities:
Proceeds —
Capital contributions from parent company		11			5
Senior notes issuances		250			700
Redemptions —
Pollution control revenue bonds		(1	)		—
Senior notes		(250	)		(650	)
Payment of preferred and preference stock dividends		(20	)		(20	)
Payment of common stock dividends		(270	)		(277	)
Other financing activities		(3	)		(12	)
Net cash used for financing activities		(283	)		(254	)
Net Change in Cash and Cash Equivalents		(266	)		8
Cash and Cash Equivalents at Beginning of Period		344			154
Cash and Cash Equivalents at End of Period	$	78		$	162
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3 and $5 capitalized for 2012 and 2011, respectively)	$	136		$	141
Income taxes, net		31			(100	)
Noncash transactions—accrued property additions at end of period		7			14

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

39

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2012			At December 31, 2011
		(in millions)
Current Assets:
Cash and cash equivalents	$	78		$	344
Restricted cash and cash equivalents		—			1
Receivables —
Customer accounts receivable		368			332
Unbilled revenues		160			126
Under recovered regulatory clause revenues		16			—
Other accounts and notes receivable		34			35
Affiliated companies		57			79
Accumulated provision for uncollectible accounts		(9	)		(10	)
Fossil fuel stock, at average cost		469			344
Materials and supplies, at average cost		380			375
Vacation pay		59			59
Prepaid expenses		135			74
Other regulatory assets, current		32			44
Other current assets		8			11
Total current assets		1,787			1,814
Property, Plant, and Equipment:
In service		21,110			20,809
Less accumulated provision for depreciation		7,562			7,344
Plant in service, net of depreciation		13,548			13,465
Nuclear fuel, at amortized cost		347			330
Construction work in progress		390			374
Total property, plant, and equipment		14,285			14,169
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		61			62
Nuclear decommissioning trusts, at fair value		571			540
Miscellaneous property and investments		73			73
Total other property and investments		705			675
Deferred Charges and Other Assets:
Deferred charges related to income taxes		529			532
Prepaid pension costs		74			59
Deferred under recovered regulatory clause revenues		29			48
Other regulatory assets, deferred		1,001			994
Other deferred charges and assets		144			186
Total deferred charges and other assets		1,777			1,819
Total Assets	$	18,554		$	18,477

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

40

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At June  30, 2012			At December 31, 2011
	(in millions)
Current Liabilities:
Securities due within one year	$	500		$	500
Accounts payable —
Affiliated		176			203
Other		196			322
Customer deposits		86			85
Accrued taxes —
Accrued income taxes		99			32
Other accrued taxes		80			34
Accrued interest		65			63
Accrued vacation pay		48			48
Accrued compensation		51			95
Liabilities from risk management activities		54			54
Other regulatory liabilities, current		3			18
Other current liabilities		40			38
Total current liabilities		1,398			1,492
Long-term Debt		5,630			5,632
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,319			3,257
Deferred credits related to income taxes		81			83
Accumulated deferred investment tax credits		145			149
Employee benefit obligations		339			343
Asset retirement obligations		571			553
Other cost of removal obligations		736			703
Other regulatory liabilities, deferred		165			156
Other deferred credits and liabilities		84			82
Total deferred credits and other liabilities		5,440			5,326
Total Liabilities		12,468			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		2,207			2,182
Retained earnings		1,997			1,956
Accumulated other comprehensive loss		(25	)		(18	)
Total common stockholder’s equity		5,401			5,342
Total Liabilities and Stockholder’s Equity	$	18,554		$	18,477

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

41

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2012 vs. SECOND QUARTER 2011

AND

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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(2.6)	$(31)	(9.1)

Alabama Power’s net income after dividends on preferred and preference stock for the second quarter 2012 was $185 million compared to $190 million for the corresponding period in 2011. Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2012 was $311 million compared to $342 million for the corresponding period in 2011. The decreases for the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 were related to decreases in weather-related revenues due to milder weather and increases in operations and maintenance expenses in 2012. These decreases were partially offset by increases in revenues associated with the elimination of a tax-related adjustment under Alabama Power’s rate structure and increases in energy sales due to increases in usage and customer growth. 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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$10	0.8	$(24)	(1.0)

In the second quarter 2012, retail revenues were $1.25 billion compared to $1.24 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $2.35 billion compared to $2.37 billion for the corresponding period in 2011.

42

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:

	Second Quarter 2012		Year-to-Date 2012
	(in millions)	(% change)	(in millions)	(% change)
Retail – prior year	$1,244		$2,370
Estimated change in –
Rates and pricing	31	2.5	56	2.4
Sales growth (decline)	25	2.0	45	1.9
Weather	(38)	(3.0)	(88)	(3.7)
Fuel and other cost recovery	(8)	(0.7)	(37)	(1.6)
Retail – current year	$1,254	0.8%	$2,346	(1.0)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2012 when compared to the corresponding periods 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 (Rate CNP Environmental).

Revenues attributable to changes in sales increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011. Weather-adjusted residential KWH energy sales increased 5.6% in the second quarter and 3.5% for year-to-date 2012 as a result of increases in usage and customer growth. Weather-adjusted commercial KWH energy sales increased 3.6% in the second quarter 2012 and 1.7% for year-to-date 2012 as a result of increases in usage. Industrial KWH energy sales increased 2.3% in the second quarter 2012 and 2.8% for year-to-date 2012 due to an increase in usage resulting from changes in production levels primarily in the primary metals, chemicals, automotive and plastics, and forest products sectors, partially offset by decreases in the stone, clay, and glass and textiles sectors.

Revenues resulting from changes in weather decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011. Alabama Power’s service territory experienced milder weather conditions in the second quarter and year-to-date 2012 when compared to the corresponding periods in the prior year. The resulting decreases for the second quarter 2012 were 5.4% and 2.5% for residential and commercial sales revenue, respectively. The resulting decreases for year-to-date 2012 were 7.1% and 2.1% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods 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.

43

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(7)	(5.1)

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

In the second quarter 2012 and the second quarter 2011, wholesale revenues from non-affiliates were $70 million. For year-to-date 2012, wholesale revenues from non-affiliates were $131 million compared to $138 million for the corresponding period in 2011. The decrease was primarily due to a 4.1% decrease in KWH sales and a 1.2% decrease in the price of energy.

Wholesale Revenues – Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(69)	(92.0)	$(130)	(86.7)

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 this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power’s energy cost recovery clauses.

In the second quarter 2012, wholesale revenues from affiliates were $6 million compared to $75 million for the corresponding period in 2011. The decrease was primarily due to a 90.2% decrease in KWH sales.

For year-to-date 2012, wholesale revenues from affiliates were $20 million compared to $150 million for the corresponding period in 2011. The decrease was due to an 82.6% decrease in KWH sales and a 23.5% decrease in the price of energy.

Fuel and Purchased Power Expenses

	Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
	(change in millions)	(% change)	(change in millions)	(% change)
Fuel	$(85)	(19.9)	$(174)	(21.1)
Purchased power – non-affiliates	—	—	4	14.3
Purchased power – affiliates	9	15.8	3	2.9
Total fuel and purchased power expenses	$(76)		$(167)

44

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the second quarter 2012, total fuel and purchased power expenses were $426 million compared to $502 million for the corresponding period in 2011. The decrease was primarily due to a $64 million decrease related to a reduction in total KWHs generated as a result of milder weather in the second quarter 2012, a $22 million decrease in the cost of fuel, and a $46 million decrease in the average cost of purchased power, partially offset by a $55 million increase in KWHs purchased.

For year-to-date 2012, total fuel and purchased power expenses were $787 million compared to $954 million for the corresponding period in 2011. The decrease was primarily due to a $149 million decrease related to a reduction in total KWHs generated as a result of milder weather for year-to-date 2012, a $25 million decrease in the cost of fuel, and a $51 million decrease in the average cost of purchased power, partially offset by a $58 million increase in KWHs purchased.

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

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

	Second Quarter 2012	Second Quarter 2011	Year-to-Date 2012	Year-to-Date 2011
Total generation (billions of KWHs)	13	17	27	33
Total purchased power (billions of KWHs)	2	1	3	2
Sources of generation (percent) –
Coal	53	56	48	56
Nuclear	24	23	26	23
Gas	21	16	20	15
Hydro	2	5	6	6
Cost of fuel, generated (cents per net KWH) –
Coal	3.29	3.13	3.35	3.06
Nuclear	0.82	0.64	0.78	0.65
Gas	2.76	4.19	2.88	4.18
Average cost of fuel, generated (cents per net KWH)(a)	2.57	2.71	2.54	2.67
Average cost of purchased power (cents per net KWH)(b)	3.89	6.02	4.14	5.66

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

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

Fuel

In the second quarter 2012, fuel expense was $343 million compared to $428 million for the corresponding period in 2011. The $85 million decrease was due to a 34.1% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements, and a 23.5% decrease in KWHs generated by coal, slightly offset by a 6.9% increase in KWHs generated by natural gas.

For year-to-date 2012, fuel expense was $649 million compared to $823 million for the corresponding period in 2011. The $174 million decrease was due to a 31.0% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements, and a 29.4% decrease in KWHs generated by coal, slightly offset by an 8.4% increase in KWHs generated by natural gas.

45

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Non-Affiliates

In the second quarter 2012 and the second quarter 2011, purchased power expense from non-affiliates was $17 million. For year-to-date 2012, purchased power expense from non-affiliates was $32 million compared to $28 million for the corresponding period in 2011. The increase was related to a 388.0% increase in the amount of energy purchased, partially offset by a 76.6% decrease in the average cost per KWH.

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

Purchased Power – Affiliates

In the second quarter 2012, purchased power expense from affiliates was $66 million compared to $57 million for the corresponding period in 2011. The increase was related to a 54.4% increase in the amount of energy purchased, partially offset by a 26.2% decrease in the average cost per KWH.

For year-to-date 2012, purchased power expense from affiliates was $106 million compared to $103 million for the corresponding period in 2011. The increase was related to a 23.2% increase in the amount of energy purchased, partially offset by a 17.0% decrease in the average cost per KWH.

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

Other Operations and Maintenance Expenses

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$26	9.0	$50	8.5

In the second quarter 2012, other operations and maintenance expenses were $316 million compared to $290 million for the corresponding period in 2011. Administrative and general expenses increased $15 million primarily due to pension and other benefit-related expenses. Distribution expenses increased $7 million primarily due to increases in vegetation management and overhead line maintenance costs. Steam production expenses increased $3 million due to environmental mandates which were partially offset by revenues associated with Rate CNP Environmental.

For year-to-date 2012, other operations and maintenance expenses were $637 million compared to $587 million for the corresponding period in 2011. Administrative and general expenses increased $33 million primarily due to pension and other benefit-related expenses, affiliated service company expenses, labor expenses, and property insurance expenses. Nuclear production expenses increased $5 million primarily due to the amortization of nuclear outage expenses of $13 million, partially offset by a decrease in operation costs related to decreases in labor. 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. Additionally, distribution and transmission expenses increased $4 million due to increases in labor expenses and vegetation management.

46

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(3.8)	$(17)	(7.5)

In the second quarter 2012, income taxes were $126 million compared to $131 million for the corresponding period in 2011. For year-to-date 2012, income taxes were $210 million compared to $227 million for the corresponding period in 2011. The decreases for the second quarter and year-to-date 2012 were primarily due to lower pre-tax earnings as a result of lower revenues due to milder weather and an increase in operations and maintenance expense.

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.

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. 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.

47

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 in May 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 the development of its compliance strategy for the MATS rule, Alabama Power has entered into agreements for the construction of baghouses to control the emissions of mercury and particulates from generating units with an aggregate capacity of 1,901 MWs. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed Alabama Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $1.2 billion to approximately $660 million as follows:

	2012		2013		2014
	(in millions)
MATS rule	$	65	$	155	$	440

48

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In addition, Alabama Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $630 million to approximately $175 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:

	2012		2013		2014
	(in millions)
Proposed water and coal combustion byproducts rules		$5		$10		$160

While Alabama Power’s ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Alabama Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $5 billion to $7 billion range provided in the Form 10-K.

Alabama Power’s ultimate compliance strategy and actual 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; 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. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, 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 SEGCO’s 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 the 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 and fine particulate matter 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.

On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Alabama Power’s service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

49

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Alabama Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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. Environmental groups and other parties have filed lawsuits 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. The ultimate outcome of these matters 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.

On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA’s actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.

50

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

PSC Matters

Rate CNP

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments – Rate CNP” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Rate CNP” in Item 8 of the Form 10-K for additional information regarding Alabama Power’s recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate CNP Environmental. Alabama Power’s under recovered Rate CNP balance as of June 30, 2012 was $2 million as compared to $6 million at December 31, 2011. Alabama Power’s under recovered Rate CNP Environmental balance as of June 30, 2012 was $26 million as compared to $11 million at December 31, 2011. These under recovered balances at June 30, 2012 are included in deferred under recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheet herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.

Retail 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 June 30, 2012 totaled $16 million as compared to $31 million at December 31, 2011. These under recovered fuel costs at June 30, 2012 are included in under recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheet 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.

Natural Disaster Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Reserve” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2012, the NDR had an accumulated balance of $105 million, which is included in Alabama Power’s Condensed Balance Sheet herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Alabama Power’s Condensed Statement of Income 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 Alabama Power through 2013. Consequently, Alabama Power’s positive cash flow benefit is estimated to be between $85 million and $110 million in 2012.

51

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

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

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.

52

ALABAMA 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 Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power’s financial condition remained stable at June 30, 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 $481 million for the first six months of 2012, a decrease of $338 million as compared to the first six months of 2011. The decrease in cash provided from operating activities was primarily due to an increase in fossil fuel stock, a decrease in deferred income taxes, and the timing of income tax payments and refunds associated with bonus depreciation. Net cash used for investing activities totaled $464 million for the first six months of 2012 primarily due to gross property additions related to nuclear fuel and transmission, distribution, and steam generating equipment. Net cash used for financing activities totaled $283 million for the first six months of 2012. This was primarily due to 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 six months of 2012 include increases of $125 million in fossil fuel stock, at average cost, $116 million in property, plant, and equipment associated with routine property additions and nuclear fuel, $67 million in accrued income taxes, and $61 million in prepaid expenses and decreases of $266 million in cash and cash equivalents and $126 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, including estimated capital expenditures to comply with existing environmental regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $500 million will be required through June 30, 2013 to fund maturities of long-term debt.

See FUTURE EARNINGS POTENTIAL – “Environmental Statutes and Regulations – General” herein for a description of the Alabama Power’s estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.

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.

53

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2012, Alabama Power had approximately $78 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:

Expires					Executable Term Loans		Due Within One Year(a)
2012	2013	2014 and     Beyond	Total	Unused	One     Year	Two   Years	Term     Out	No Term Out
(in millions)			(in millions)		(in millions)		(in millions)
$37	$101	$1,150	$1,288	$1,288	$51	$—	$51	$52

(a) Reflects facilities expiring on or before June 30, 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 June 30, 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.

54

ALABAMA 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)
June 30, 2012:
Commercial paper		$—		—  %		$22		0.2%		$57

(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

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At June 30, 2012, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $311 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool 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 second 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 for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power had no material change in market risk exposure for the second quarter 2012 when compared with the December 31, 2011 reporting period.

55

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 and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes		Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net		$(53)		$(48)
Contracts realized or settled		16		30
Current period changes(a)		5		(14)
Contracts outstanding at the end of the period, assets (liabilities), net		$(32)		$(32)

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

The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes		Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Natural gas swaps		$16		$14
Natural gas options		5		2
Other energy-related derivatives		—		—
Total changes		$21		$16

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

	June 30, 2012		March 31, 2012		December 31, 2011
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps		32		27		30
Commodity – Natural gas options		11		10		9
Total hedge volume		43		37		39

The weighted average swap contract cost above market prices was approximately $0.93 per mmBtu as of June 30, 2012, $1.72 per mmBtu as of March 31, 2012, and $1.45 per mmBtu as of December 31, 2011. The change in option premiums is primarily attributable to the volatility of the market and the underlying change in the natural gas price. A majority of the natural gas hedge gains and losses is recovered through Alabama Power’s retail fuel cost recovery clause.

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

Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.

56

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2012 were as follows:

	June 30, 2012 Fair Value Measurements
	Total Fair Value		Maturity
			Year 1		Years 2&3		Years 4&5
		(in millions)
Level 1		$—		$—		$—		$—
Level 2		(32)		(25)		(7)		—
Level 3		—		—		—		—
Fair value of contracts outstanding at end of period		$(32)		$(25)		$(7)		$—

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 will impose additional requirements on the use of over-the-counter derivatives for both Alabama Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Alabama Power does not expect the impact of these rules to be material.

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.

In April 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.

57

GEORGIA POWER COMPANY

58

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,857		$	2,070		$	3,451		$	3,885
Wholesale revenues, non-affiliates		75			97			141			180
Wholesale revenues, affiliates		6			16			9			27
Other revenues		82			82			164			162
Total operating revenues		2,020			2,265			3,765			4,254
Operating Expenses:
Fuel		572			784			1,012			1,461
Purchased power, non-affiliates		94			96			187			170
Purchased power, affiliates		129			157			288			320
Other operations and maintenance		411			419			845			841
Depreciation and amortization		185			178			373			351
Taxes other than income taxes		94			94			181			181
Total operating expenses		1,485			1,728			2,886			3,324
Operating Income		535			537			879			930
Other Income and (Expense):
Allowance for equity funds used during construction		13			22			26			47
Interest expense, net of amounts capitalized		(90	)		(71	)		(181	)		(167	)
Other income (expense), net		(6	)		(5	)		(9	)		(6	)
Total other income and (expense)		(83	)		(54	)		(164	)		(126	)
Earnings Before Income Taxes		452			483			715			804
Income taxes		152			169			244			280
Net Income		300			314			471			524
Dividends on Preferred and Preference Stock		5			5			9			9
Net Income After Dividends on Preferred and Preference Stock	$	295		$	309		$	462		$	515

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)				(in millions)
Net Income After Dividends on Preferred and Preference Stock	$	295	$	309	$	462	$	515
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $1 and $1, respectively		—		—		1		1
Total other comprehensive income (loss)		—		—		1		1
Comprehensive Income	$	295	$	309	$	463	$	516

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2012			2011
	(in millions)
Operating Activities:
Net income	$	471		$	524
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		458			426
Deferred income taxes		128			189
Allowance for equity funds used during construction		(26	)		(47	)
Retail fuel cost over recovery—long-term		44			—
Deferred expenses		26			33
Other, net		(3	)		(73	)
Changes in certain current assets and liabilities —
-Receivables		19			(100	)
-Fossil fuel stock		(147	)		55
-Prepaid income taxes		13			77
-Other current assets		8			(14	)
-Accounts payable		(37	)		60
-Accrued taxes		(77	)		(123	)
-Accrued compensation		(60	)		(42	)
-Retail fuel cost over recovery—short-term		55			—
-Other current liabilities		43			46
Net cash provided from operating activities		915			1,011
Investing Activities:
Property additions		(812	)		(931	)
Investment of restricted cash		(234	)		—
Distribution of restricted cash		49			—
Nuclear decommissioning trust fund purchases		(488	)		(1,152	)
Nuclear decommissioning trust fund sales		486			1,149
Cost of removal, net of salvage		(34	)		(9	)
Change in construction payables, net of joint owner portion		(161	)		34
Other investing activities		(14	)		(12	)
Net cash used for investing activities		(1,208	)		(921	)
Financing Activities:
Decrease in notes payable, net		(513	)		(253	)
Proceeds —
Capital contributions from parent company		18			183
Pollution control revenue bonds issuances		234			250
Senior notes issuances		1,500			550
Other long-term debt issuances		—			250
Redemptions —
Pollution control revenue bonds		(49	)		(197	)
Senior notes		—			(101	)
Other long-term debt		(250	)		(300	)
Payment of preferred and preference stock dividends		(9	)		(9	)
Payment of common stock dividends		(454	)		(448	)
Other financing activities		(9	)		(2	)
Net cash provided from (used for) financing activities		468			(77	)
Net Change in Cash and Cash Equivalents		175			13
Cash and Cash Equivalents at Beginning of Period		13			8
Cash and Cash Equivalents at End of Period	$	188		$	21
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $11 and $17 capitalized for 2012 and 2011, respectively)	$	156		$	177
Income taxes, net		44			(15	)
Noncash transactions—accrued property additions at end of period		234			299

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

60

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2012			At December 31, 2011
	(in millions)
Current Assets:
Cash and cash equivalents	$	188		$	13
Restricted cash and cash equivalents		185			—
Receivables —
Customer accounts receivable		596			571
Unbilled revenues		244			172
Under recovered regulatory clause revenues		—			137
Joint owner accounts receivable		45			87
Other accounts and notes receivable		98			61
Affiliated companies		55			26
Accumulated provision for uncollectible accounts		(12	)		(13	)
Fossil fuel stock, at average cost		870			723
Materials and supplies, at average cost		391			406
Vacation pay		84			82
Prepaid income taxes		140			71
Other regulatory assets, current		93			108
Other current assets		81			106
Total current assets		3,058			2,550
Property, Plant, and Equipment:
In service		28,549			27,804
Less accumulated provision for depreciation		10,395			10,296
Plant in service, net of depreciation		18,154			17,508
Other utility plant, net		53			55
Nuclear fuel, at amortized cost		460			443
Construction work in progress		3,055			3,274
Total property, plant, and equipment		21,722			21,280
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		61			63
Nuclear decommissioning trusts, at fair value		665			667
Miscellaneous property and investments		44			44
Total other property and investments		770			774
Deferred Charges and Other Assets:
Deferred charges related to income taxes		757			756
Other regulatory assets, deferred		1,550			1,604
Other deferred charges and assets		221			187
Total deferred charges and other assets		2,528			2,547
Total Assets	$	28,078		$	27,151

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

61

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At June 30, 2012			At December 31, 2011
	(in millions)
Current Liabilities:
Securities due within one year	$	1,340		$	455
Notes payable		2			515
Accounts payable —
Affiliated		357			337
Other		451			686
Customer deposits		227			213
Accrued taxes —
Accrued income taxes		110			36
Other accrued taxes		175			304
Accrued interest		108			92
Accrued vacation pay		60			60
Accrued compensation		67			125
Liabilities from risk management activities		52			68
Other regulatory liabilities, current		79			65
Nuclear decommissioning trust securities lending collateral		8			32
Other current liabilities		197			153
Total current liabilities		3,233			3,141
Long-term Debt		8,570			8,018
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		4,608			4,388
Deferred credits related to income taxes		118			122
Accumulated deferred investment tax credits		214			220
Employee benefit obligations		892			905
Asset retirement obligations		759			734
Other cost of removal obligations		97			110
Other deferred credits and liabilities		255			224
Total deferred credits and other liabilities		6,943			6,703
Total Liabilities		18,746			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		5,557			5,522
Retained earnings		3,119			3,112
Accumulated other comprehensive loss		(8	)		(9	)
Total common stockholder’s equity		9,066			9,023
Total Liabilities and Stockholder’s Equity	$	28,078		$	27,151

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

62

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2012 vs. SECOND QUARTER 2011

AND

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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(14)	(4.5)	$(53)	(10.3)

Georgia Power’s net income after dividends on preferred and preference stock for the second quarter 2012 was $295 million compared to $309 million for the corresponding period in 2011. Georgia Power’s net income after dividends on preferred and preference stock for year-to-date 2012 was $462 million compared to $515 million for the corresponding period in 2011. The decreases were primarily due to decreases in operating revenues primarily as a result of milder weather, higher depreciation, and lower AFUDC, partially offset by lower income taxes and an increase related to retail revenue rate effects. The decreases were also due to lower interest expense in 2011 resulting from the settlement of litigation with the Georgia Department of Revenue (DOR), partially offset by a reduction in 2012 related to the conclusion of certain state and federal income tax audits.

Retail Revenues

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(213)	(10.3)	$(434)	(11.2)

In the second quarter 2012, retail revenues were $1.86 billion compared to $2.07 billion for the corresponding period in 2011. For year-to-date 2012, retail revenues were $3.45 billion compared to $3.89 billion for the corresponding period in 2011.

63

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:

	Second Quarter 2012				Year-to-Date 2012
	(in millions)		(% change)		(in millions)		(% change)
Retail — prior year		$    2,070				$3,885
Estimated change in —
Rates and pricing		25		1.2		48		1.2
Sales growth (decline)		3		0.1		(5)		(0.1)
Weather		(43)		(2.1)		(93)		(2.4)
Fuel cost recovery		(198)		(9.5)		(384)		(9.9)
Retail — current year		$    1,857		(10.3)%		$    3,451		(11.2)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to base tariff increases effective April 1, 2012 related to placing Plant McDonough-Atkinson Units 4 and 5 in service, the NCCR and demand-side management tariff increases effective January 1, 2012, as approved by the Georgia PSC, and the rate pricing effect of decreased customer usage. These increases were partially offset by lower contributions from market-driven rates from commercial and industrial customers.

Revenues attributable to changes in sales remained flat in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011. Weather-adjusted residential KWH sales increased 0.8%, weather-adjusted commercial KWH sales increased 1.0%, and weather-adjusted industrial KWH sales decreased 1.1% in the second quarter 2012 when compared to the corresponding period in 2011. Weather-adjusted residential KWH sales increased 0.4%, weather-adjusted commercial KWH sales decreased 0.6%, and weather-adjusted industrial KWH sales decreased 0.6% year-to-date 2012 when compared to the corresponding period in 2011. The increase in residential sales is primarily due to customer growth. The economy continues to impact commercial and industrial sales.

Revenues resulting from changes in weather decreased in the second quarter 2012 when compared to the corresponding period in 2011 due to milder weather. Revenues resulting from changes in weather decreased year-to-date 2012 when compared to the corresponding period in 2011 as a result of milder weather in 2012 and cold weather in January 2011.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $198 million and $384 million in the second quarter and year-to-date 2012, respectively, when compared to the corresponding periods in 2011 due to decreased KWH energy sales and lower costs primarily due to lower natural gas prices.

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 energy component of purchased power costs, and do not affect net income. Georgia Power implemented reduced fuel rates effective June 1, 2012. See FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” herein for additional information.

64

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(22)	(22.7)	$(39)	(21.7)

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.

In the second quarter 2012, wholesale revenues from non-affiliates were $75 million compared to $97 million in the corresponding period in 2011. For year-to-date 2012, wholesale revenues from non-affiliates were $141 million compared to $180 million in the corresponding period in 2011. The decreases were primarily due to 32.5% and 36.7% decreases in KWH sales in the second quarter and year-to-date 2012, respectively, due to lower demand resulting from milder weather.

Wholesale Revenues – Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(62.5)	$(18)	(66.7)

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 second quarter 2012, wholesale revenues from affiliates were $6 million compared to $16 million in the corresponding period in 2011. For year-to-date 2012, wholesale revenues from affiliates were $9 million compared to $27 million in the corresponding period in 2011. The decreases were primarily due to 43.6% and 48.9% decreases in KWH sales in the second quarter and year-to-date 2012, respectively, 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

	Second Quarter 2012 vs. Second Quarter 2011				Year-to-Date 2012 vs. Year-to-Date 2011
	(change in millions)		(% change)		(change in millions)		(% change)
Fuel	$	(212)		(27.0)	$	(449)		(30.7)
Purchased power — non-affiliates		(2)		(2.1)		17		10.0
Purchased power — affiliates		(28)		(17.8)		(32)		(10.0)
Total fuel and purchased power expenses	$	(242)			$	(464)

65

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the second quarter 2012, total fuel and purchased power expenses were $795 million compared to $1.04 billion in the corresponding period in 2011. For year-to-date 2012, total fuel and purchased power expenses were $1.49 billion compared to $1.95 billion for the corresponding period in 2011. The decreases were primarily due to the lower cost of natural gas used for generation and lower demand related to milder weather in 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 Georgia Power’s fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL – “PSC Matters — Fuel Cost Recovery” herein for additional information.

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

	Second Quarter 2012		Second Quarter 2011		Year-to-Date 2012		Year-to-Date 2011
Total generation (billions of KWHs)		16		18		29		34
Total purchased power (billions of KWHs)		7		6		15		12
Sources of generation (percent) —
Coal		44		67		43		65
Nuclear		26		20		28		22
Gas		29		11		28		11
Hydro		1		2		1		2
Cost of fuel, generated (cents per net KWH) —
Coal		5.00		4.70		4.86		4.72
Nuclear		0.84		0.80		0.85		0.74
Gas		2.71		5.39		2.90		4.88
Average cost of fuel, generated (cents per net KWH)		3.25		3.97		3.18		3.85
Average cost of purchased power (cents per net KWH)(a)		4.24		5.79		4.03		5.68

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

Fuel

In the second quarter 2012, fuel expense was $572 million compared to $784 million in the corresponding period in 2011. The decrease was due to a 9.6% decrease of KWHs generated as a result of lower KWH demand and an 18.1% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.

For year-to-date 2012, fuel expense was $1.01 billion compared to $1.46 billion in the corresponding period in 2011. The decrease was primarily due to a 15.6% decrease of KWHs generated as a result of lower KWH demand and a 17.4% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.

Purchased Power – Non-Affiliates

In the second quarter 2012, purchased power expense from non-affiliates was $94 million compared to $96 million in the corresponding period in 2011. The decrease was immaterial.

For year-to-date 2012, purchased power expense from non-affiliates was $187 million compared to $170 million in the corresponding period in 2011. The increase was due to an 84.4% 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 40.8% in the average cost per KWH purchased primarily due to lower natural gas prices.

66

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Purchased Power – Affiliates

In the second quarter 2012, purchased power expense from affiliates was $129 million compared to $157 million in the corresponding period in 2011. The decrease was due to a 25.3% decrease in the average cost per KWH purchased, reflecting lower natural gas prices.

For year-to-date 2012, purchased power expense from affiliates was $288 million compared to $320 million in the corresponding period in 2011. The decrease was due to a 28.3% decrease in the average cost per KWH purchased, reflecting lower natural gas prices, partially offset by a 12.6% increase in the volume of KWHs purchased as the cost of the available energy was lower than the Georgia Power-owned generation.

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

Other Operations and Maintenance Expenses

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(1.9)	$4	0.5

In the second quarter 2012, other operations and maintenance expenses were $411 million compared to $419 million in the corresponding period in 2011. The decrease was primarily due to a $9 million decrease in fossil generation expense due to a decrease in KWHs generated as a result of lower demand due to milder weather, a $5 million decrease in nuclear generation expense related to a nuclear fuel disposal settlement, and a $7 million decrease in uncollectible accounts expense, partially offset by a $10 million increase in employee pension expense and a $6 million increase in demand-side management program costs. See Note (B) under “Nuclear Fuel Disposal Cost Litigation” and Note (F) to the Condensed Financial Statements herein for additional information.

For year-to-date 2012, other operations and maintenance expenses were $845 million compared to $841 million in the corresponding period in 2011. The increase was primarily due to a $20 million increase in employee pension expense and an $11 million increase in demand-side management program costs, partially offset by a $19 million decrease in fossil generation expense due to a decrease in KWHs generated as a result of lower demand due to milder weather and a $10 million decrease in uncollectible accounts expense. The decrease in fossil generation was also due to outage timing and scope of outage work performed in the first quarter 2012. See Note (F) to the Condensed Financial Statements herein for additional information.

Depreciation and Amortization

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$7	3.9	$22	6.3

In the second quarter 2012, depreciation and amortization was $185 million compared to $178 million in the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $373 million compared to $351 million in the corresponding period in 2011. The increases were primarily due to increases of $14 million and $27 million in depreciation in the second quarter and year-to-date 2012, respectively, on additional plant in service related to

67

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

new generation at Plant McDonough-Atkinson Units 4 and 5, partially offset by $9 million in amortization of the regulatory liability for state income tax credits beginning April 1, 2012, as authorized by the Georgia PSC. See Note 3 to the financial statements of Georgia Power under “Construction — Other Construction” in Item 8 of the Form 10-K for additional information.

Allowance for Equity Funds Used During Construction

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(9)	(40.9)	$(21)	(44.7)

In the second quarter 2012, AFUDC equity was $13 million compared to $22 million in the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $26 million compared to $47 million in the corresponding period in 2011. The decreases were primarily due to the completion of Plant McDonough-Atkinson Units 4 and 5 in December 2011 and April 2012, respectively.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$19	26.8	$14	8.4

In the second quarter 2012, interest expense, net of amounts capitalized was $90 million compared to $71 million in the corresponding period in 2011. For year-to-date 2012, interest expense, net of amounts capitalized was $181 million compared to $167 million in the corresponding period in 2011. The increases were primarily due to a $23 million reduction in interest expense in 2011 resulting from the settlement of litigation with the Georgia DOR, partially offset by a $9 million reduction in 2012 related to the conclusion of certain state and federal income tax audits.

Income Taxes

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	(10.1)	$(36)	(12.9)

In the second quarter 2012, income taxes were $152 million compared to $169 million in the corresponding period in 2011. For year-to-date 2012, income taxes were $244 million compared to $280 million in the corresponding period in 2011. The decreases were primarily due to lower pre-tax earnings and state income tax credits, partially offset by decreases in non-taxable AFUDC equity. See Note (G) to the Condensed Financial Statements under “Unrecognized Tax Benefits” herein for additional information.

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

68

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

Environmental Matters

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

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 and Note (B) to the Condensed Financial Statements under “Environmental Matters — New Source Review Actions” herein for additional information. The case against Georgia Power was administratively closed in 2001 and has not been reopened. 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 in May 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.

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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. As part of the development of its compliance strategy for the MATS rule, Georgia Power has entered into agreements for the construction of baghouses to control the emissions of mercury and particulates from certain generating units. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed Georgia Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period (in addition to $237 million included in base environmental capital disclosed in the Form 10-K) have been revised from up to $320 million to approximately $440 million as follows:

	2012		2013	2014
			(in millions)
MATS rule	$	—	$—	$	440

In addition, Georgia Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $640 million to approximately $250 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:

	2012		2013	2014
			(in millions)
Proposed water and coal combustion byproducts rules		$5	$55	$	190

While Georgia Power’s ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Georgia Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $5 billion to $7 billion range provided in the Form 10-K.

Georgia Power’s ultimate compliance strategy and actual 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; 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. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, 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 SEGCO’s 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 the 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.

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GEORGIA POWER COMPANY

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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 and fine particulate matter 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. The potential impact of the revised standard and nonattainment designation will depend on further evaluation and implementation by the Georgia Environmental Protection Division and cannot be determined at this time.

On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Georgia Power’s service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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 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.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Georgia Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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. Environmental groups and other parties have filed lawsuits 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. The ultimate outcome of these matters cannot be determined at this time.

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GEORGIA POWER COMPANY

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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.

On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA’s actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.

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.

On June 21, 2012, the Georgia PSC approved a decrease in Georgia Power’s fuel cost recovery rates of 19%, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow. See Note (B) to the Condensed Financial Statements under “Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery” herein for additional information.

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.

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GEORGIA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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. On July 11, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitioners’ motion to stay the effectiveness of the COLs. Georgia Power has intervened in 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

31, 2015, in addition to the ongoing financing costs. At June 30, 2012, approximately $64 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, Contractor) 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 Contractor 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. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and Georgia Power (on behalf of the Owners) are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate to 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 by the NRC. The Owners and the Contractor have begun negotiations regarding these issues, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Through correspondence sent to the Owners, the Contractor has provided its proposed adjustment to the contract price and has initiated the formal dispute resolution process. The Contractor’s estimated adjustment attributable to Georgia Power (based on Georgia Power’s ownership interest regarding these issues) is approximately $425 million (in 2008 dollars) with respect to these issues. 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. While the formal dispute resolution process has been initiated, Georgia Power expects negotiations with the Contractor to continue over the next several months with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Georgia Power intends to vigorously defend its positions. If these costs ultimately are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. In connection with these negotiations, the Owners are evaluating whether maintaining the currently scheduled commercial operation dates of 2016 and 2017 remains in the best interest of their customers. Additional claims by the Contractor 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. During a routine inspection in April 2012, the NRC identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. In May 2012, Southern Nuclear received an official notice of violation relating to these findings from the NRC. The design changes were determined to have minimal safety significance and, on August 1, 2012, Southern Nuclear filed a license amendment request with the NRC to clarify that the nuclear island concrete and rebar construction will conform to NRC requirements. Various inspection and other issues are expected to arise from time to time as construction proceeds, which may result in additional license amendments or require other resolution.

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.

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GEORGIA POWER COMPANY

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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.

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

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 in Note (B) 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 the end of 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.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Overview” of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power’s financial condition remained stable at June 30, 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 $915 million for the first six months of 2012 compared to $1.01 billion for the corresponding period in 2011. The $96 million decrease was primarily due to lower retail operating revenues, higher fuel inventory additions in 2012, and lower deferred taxes due to the effect of bonus depreciation in 2011, partially offset by higher recovery of retail fuel costs. Net cash used for investing activities totaled $1.2 billion primarily due to gross property additions to utility plant together with a net increase in restricted cash of $185 million in the first six months of 2012. Net cash provided from financing activities totaled $468 million for the first six months of 2012 compared to $77 million used for financing activities in the corresponding period in 2011. The $545 million increase is primarily due to increased debt issuances in 2012.

Significant balance sheet changes for the first six months of 2012 include increases of $442 million in total property, plant, and equipment, $147 million in fossil fuel stock, $552 million in long-term debt, and $185 million in restricted cash, as well as a $236 million change in under/over 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, including estimated capital expenditures to comply with existing environmental regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $1.3 billion will be required through June 30, 2013 to fund maturities of long-term debt.

See FUTURE EARNINGS POTENTIAL – “Environmental Statutes and Regulations – General” herein for a description of Georgia Power’s estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.

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GEORGIA POWER COMPANY

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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.

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. In the event that the DOE does not issue a loan guarantee or Georgia Power determines that the final terms and conditions of the loan guarantee by the DOE are not in the best interest of its customers, Georgia Power expects to finance the construction of Plant Vogtle Units 3 and 4 through traditional capital markets financings. There can be no assurance that the DOE will issue loan guarantees for Georgia Power. 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.

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GEORGIA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At June 30, 2012, Georgia Power had approximately $188 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:

Expires					Executable Term Loans		Due Within One Year(a)
2012	2013	2014 and Beyond	Total	Unused	One Year	Two Years	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 June 30, 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 June 30, 2012 was approximately $868 million.

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.

Georgia Power had no short-term debt outstanding as of June 30, 2012. Details of short-term borrowings during the period, excluding $2 million of notes payable related to other energy service contracts, were as follows:

	Short-term Debt During the Period (a)
	Average Outstanding	Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)		(in millions)
June 30, 2012:
Commercial paper	$      85	0.3%	$    312
Short-term bank debt	175	1.1%	300
Total	$    260	1.0%

(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.

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Credit Rating Risk

Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. The maximum potential collateral requirements under these contracts at June 30, 2012 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$      65
Below BBB- and/or Baa3	1,316

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.

Market Price Risk

Georgia Power’s market risk exposure relative to interest rate changes for the second 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 for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power had no material change in market risk exposure for the second 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 and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes	Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$(86)	$(82)
Contracts realized or settled	26	44
Current period changes(a)	2	(20)
Contracts outstanding at the end of the period, assets (liabilities), net	$(58)	$(58)

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

79

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes		Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Natural gas swaps		$    22		$    26
Natural gas options		6		(2)
Other energy—related derivatives		—		—
Total changes		$    28		$    24

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

	June 30, 2012	March 31, 2012	December 31, 2011
	mmBtu Volume
	(in millions)
Commodity—Natural gas swaps	23	25	29
Commodity—Natural gas options	73	60	44
Total hedge volume	96	85	73

The weighted average swap contract cost above market prices was approximately $1.37 per mmBtu as of June 30, 2012, $2.13 per mmBtu as of March 31, 2012, and $1.65 per mmBtu as of December 31, 2011. 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 and six months ended June 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.

Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:

	June 30, 2012 Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3
		(in millions)
Level 1	$ —	$ —	$ —
Level 2	(58)	(40)	(18)
Level 3	—	—	—
Fair value of contracts outstanding at end of period	$(58)	$(40)	$(18)

80

GEORGIA 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 Georgia Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Georgia Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Georgia Power does not expect the impact of these rules to be material.

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 and May 2012, Georgia Power issued $750 million and $350 million, respectively, aggregate principal amount of Series 2012A 4.30% Senior Notes due March 15, 2042. Also in May 2012, Georgia Power issued $400 million aggregate principal amount of Series 2012B 2.85% Senior Notes due May 15, 2022. The net proceeds from the sale of the Series 2012B Senior Notes, together with the net proceeds from the sale of the Series 2012A Senior Notes, were used by Georgia Power to repay a portion of Georgia Power’s short-term debt and bank loans, for the redemption in July 2012 of $300 million aggregate principal amount of Georgia Power’s Series 2007D 6.375% Senior Notes due July 15, 2047, and for general corporate purposes, including Georgia Power’s continuous construction program.

In May 2012, the Development Authority of Monroe County issued $48.72 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2012, for the benefit of Georgia Power. The proceeds were used to redeem in June 2012 the $48.72 million aggregate principal amount of Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2006.

In June 2012, the Development Authority of Burke County issued $85 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2012 and $100 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2012 for the benefit of Georgia Power. The proceeds were used to redeem in July 2012 the $85 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2005 and the $100 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2005.

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.

81

GULF POWER COMPANY

82

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	294,878		$	320,474		$	533,398		$	595,300
Wholesale revenues, non-affiliates		28,729			38,874			55,847			69,893
Wholesale revenues, affiliates		28,702			22,857			65,066			26,992
Other revenues		17,899			17,060			32,142			31,688
Total operating revenues		370,208			399,265			686,453			723,873
Operating Expenses:
Fuel		141,220			178,686			262,308			310,468
Purchased power, non-affiliates		12,085			10,889			23,310			17,892
Purchased power, affiliates		5,210			12,549			7,723			29,167
Other operations and maintenance		79,779			72,583			155,009			153,092
Depreciation and amortization		35,173			32,304			68,480			64,060
Taxes other than income taxes		25,276			24,867			49,060			49,763
Total operating expenses		298,743			331,878			565,890			624,442
Operating Income		71,465			67,387			120,563			99,431
Other Income and (Expense):
Allowance for equity funds used during construction		1,736			2,522			2,973			4,657
Interest income		1,809			20			1,396			34
Interest expense, net of amounts capitalized		(15,698	)		(14,423	)		(31,066	)		(28,052	)
Other income (expense), net		(697	)		(447	)		(1,293	)		(1,010	)
Total other income and (expense)		(12,850	)		(12,328	)		(27,990	)		(24,371	)
Earnings Before Income Taxes		58,615			55,059			92,573			75,060
Income taxes		22,102			20,157			33,843			26,916
Net Income		36,513			34,902			58,730			48,144
Dividends on Preference Stock		1,550			1,550			3,101			3,101
Net Income After Dividends on Preference Stock	$	34,963		$	33,352		$	55,629		$	45,043

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
Net Income After Dividends on Preference Stock	$	34,963	$	33,352	$	55,629	$	45,043
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $90, $90, $180 and $180, respectively		143		144		286		287
Total other comprehensive income (loss)		143		144		286		287
Comprehensive Income	$	35,106	$	33,496	$	55,915	$	45,330

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

83

GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2012			2011
	(in thousands)
Operating Activities:
Net income	$	58,730		$	48,144
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		71,707			67,129
Deferred income taxes		70,153			20,411
Allowance for equity funds used during construction		(2,973	)		(4,657	)
Pension, postretirement, and other employee benefits		2,383			(993	)
Stock based compensation expense		1,044			789
Other, net		7,503			(3,496	)
Changes in certain current assets and liabilities —
-Receivables		(18,580	)		(33,496	)
-Prepayments		1,813			1,373
-Fossil fuel stock		3,982			21,458
-Materials and supplies		(4,100	)		(4,088	)
-Prepaid income taxes		(3,566	)		35,287
-Other current assets		—			23
-Accounts payable		(17,481	)		(1,710	)
-Accrued taxes		6,788			28,851
-Accrued compensation		(6,239	)		(6,132	)
-Over recovered regulatory clause revenues		25,099			4,027
-Other current liabilities		(1,659	)		2,274
Net cash provided from operating activities		194,604			175,194
Investing Activities:
Property additions		(169,462	)		(168,986	)
Cost of removal, net of salvage		(14,817	)		(6,616	)
Change in construction payables		3,661			(31	)
Payments pursuant to long-term service agreements		(4,086	)		(4,162	)
Other investing activities		18			222
Net cash used for investing activities		(184,686	)		(179,573	)
Financing Activities:
Increase in notes payable, net		5,980			1,392
Proceeds —
Common stock issued to parent		40,000			50,000
Capital contributions from parent company		954			1,014
Senior notes		100,000			125,000
Redemptions —
Senior notes		(91,363	)		(352	)
Other long-term debt		—			(110,000	)
Payment of preference stock dividends		(3,101	)		(3,101	)
Payment of common stock dividends		(57,900	)		(55,000	)
Other financing activities		(653	)		(3,679	)
Net cash provided from (used for) financing activities		(6,083	)		5,274
Net Change in Cash and Cash Equivalents		3,835			895
Cash and Cash Equivalents at Beginning of Period		17,328			16,434
Cash and Cash Equivalents at End of Period	$	21,163		$	17,329
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $1,185 and $1,856 capitalized for 2012 and 2011, respectively)	$	30,100		$	26,288
Income taxes, net		(32,848	)		(46,824	)
Noncash transactions — accrued property additions at end of period		27,127			14,924

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

84

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2012			At December 31, 2011
	(in thousands)
Current Assets:
Cash and cash equivalents	$	21,163		$	17,328
Receivables —
Customer accounts receivable		83,682			72,754
Unbilled revenues		57,575			49,921
Under recovered regulatory clause revenues		4,070			5,530
Other accounts and notes receivable		10,819			13,350
Affiliated companies		15,189			14,844
Accumulated provision for uncollectible accounts		(1,463	)		(1,962	)
Fossil fuel stock, at average cost		143,588			147,567
Materials and supplies, at average cost		53,881			49,781
Other regulatory assets, current		35,670			35,849
Prepaid expenses		71,492			28,327
Other current assets		1,523			2,051
Total current assets		497,189			435,340
Property, Plant, and Equipment:
In service		4,130,575			3,846,446
Less accumulated provision for depreciation		1,154,842			1,124,291
Plant in service, net of depreciation		2,975,733			2,722,155
Construction work in progress		158,639			287,173
Total property, plant, and equipment		3,134,372			3,009,328
Other Property and Investments		16,377			16,394
Deferred Charges and Other Assets:
Deferred charges related to income taxes		50,696			48,210
Other regulatory assets, deferred		332,325			323,116
Other deferred charges and assets		27,567			39,493
Total deferred charges and other assets		410,588			410,819
Total Assets	$	4,058,526		$	3,871,881

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

85

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At June 30, 2012			At December 31, 2011
	(in thousands)
Current Liabilities:
Notes payable	$	116,907		$	114,507
Accounts payable —
Affiliated		58,897			54,874
Other		50,348			63,265
Customer deposits		36,028			35,779
Accrued taxes —
Accrued income taxes		68			1,362
Other accrued taxes		20,147			12,114
Accrued interest		11,911			14,018
Accrued compensation		8,245			14,485
Other regulatory liabilities, current		56,999			35,639
Liabilities from risk management activities		20,485			22,786
Other current liabilities		23,880			22,916
Total current liabilities		403,915			391,745
Long-term Debt		1,245,567			1,235,447
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		559,600			458,978
Accumulated deferred investment tax credits		6,084			6,760
Employee benefit obligations		109,200			109,740
Other cost of removal obligations		212,981			214,598
Other regulatory liabilities, deferred		47,229			44,843
Other deferred credits and liabilities		209,965			186,824
Total deferred credits and other liabilities		1,145,059			1,021,743
Total Liabilities		2,794,541			2,648,935
Preference Stock		97,998			97,998
Common Stockholder's Equity:
Common stock, without par value—
Authorized — 20,000,000 shares
Outstanding — June 30, 2012: 4,542,717 shares
— December 31, 2011: 4,142,717 shares		393,060			353,060
Paid-in capital		545,733			542,709
Retained earnings		229,062			231,333
Accumulated other comprehensive loss		(1,868	)		(2,154	)
Total common stockholder’s equity		1,165,987			1,124,948
Total Liabilities and Stockholder’s Equity	$	4,058,526		$	3,871,881

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

86

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2012 vs. SECOND QUARTER 2011

AND

YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 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. On July 17, 2012, the Florida PSC denied Gulf Power’s motion and reaffirmed its earlier decision.

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

RESULTS OF OPERATIONS

Net Income

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$1.6	4.8	$10.6	23.5

Gulf Power’s net income after dividends on preference stock for the second quarter 2012 was $35.0 million compared to $33.4 million for the corresponding period in 2011. The increase was primarily due to higher retail base revenues resulting from the retail base rate increase effective April 11, 2012, partially offset by an increase in operations and maintenance expenses in 2012 and a decrease in retail energy sales in 2012 due to a decrease in customer usage.

Gulf Power’s net income after dividends on preference stock for year-to-date 2012 was $55.6 million compared to $45.0 million for the corresponding period in 2011. The increase was primarily due to higher retail base revenues resulting from the retail base rate increase effective April 11, 2012, an increase related to retail interim revenues, and higher wholesale capacity revenues from non-affiliates in 2012. These increases were partially offset by milder weather in 2012 and a decrease in retail energy sales in 2012 due to a decrease in customer usage.

87

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(25.6)	(8.0)	$(61.9)	(10.4)

In the second quarter 2012, retail revenues were $294.9 million compared to $320.5 million for the corresponding period in 2011. For year-to-date 2012, retail revenues were $533.4 million compared to $595.3 million for the corresponding period in 2011.

Details of the change to retail revenues were as follows:

	Second Quarter 2012		Year-to-Date 2012
	(in millions)	(% change)	(in millions)	(% change)
Retail – prior year	$    320.5		$ 595.3
Estimated change in –
Rates and pricing	19.7	6.1	32.2	5.4
Sales growth (decline)	(6.5)	(2.0)	(5.3)	(0.9)
Weather	(0.3)	(0.1)	(8.6)	(1.4)
Fuel and other cost recovery	(38.5)	(12.0)	(80.2)	(13.5)
Retail – current year	$   294.9	(8.0)%	$ 533.4	(10.4)%

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 second quarter 2012 when compared to the corresponding period in 2011 primarily due to higher retail base revenues resulting from the retail base rate increase effective April 11, 2012 and revenues associated with higher recoverable costs under Gulf Power’s energy conservation cost recovery clause. These increases were partially offset by revenues associated with lower recoverable costs under Gulf Power’s environmental cost recovery clause.

Revenues associated with changes in rates and pricing increased year-to-date 2012 when compared to the corresponding period in 2011 primarily due to higher retail base revenues resulting from the retail base rate increase effective April 11, 2012, an increase related to retail interim revenues, and revenues associated with higher recoverable costs under Gulf Power’s energy conservation cost recovery clause. These increases were partially offset by revenues associated with lower recoverable costs under Gulf Power’s environmental cost recovery clause.

Revenues attributable to changes in sales decreased in the second quarter 2012 when compared to the corresponding period in 2011. Weather-adjusted KWH energy sales to residential and commercial customers decreased primarily due to lower use per customer. KWH energy sales to industrial customers decreased 9.0% primarily due to increased customer co-generation due to the lower cost of natural gas in 2012 and changes in customer production levels.

Revenues attributable to changes in sales decreased year-to-date 2012 when compared to the corresponding period in 2011. Weather-adjusted KWH energy sales to residential and commercial customers decreased 1.8% and 1.9%, respectively, due to lower use per customer. KWH energy sales to industrial customers decreased 8.0% primarily due to increased customer co-generation due to the lower cost of natural gas in 2012 and changes in customer production levels.

88

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues attributable to changes in weather decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to milder weather in 2012.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to lower revenues associated with 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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(10.2)	(26.1)	$(14.1)	(20.1)

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

In the second quarter 2012, wholesale revenues from non-affiliates were $28.7 million compared to $38.9 million for the corresponding period in 2011. The decrease was primarily due to lower energy revenues related to a 53.0% decrease in KWH sales as a result of less energy scheduled by unit power customers.

For year-to-date 2012, wholesale revenues from non-affiliates were $55.8 million compared to $69.9 million for the corresponding period in 2011. The decrease was primarily due to lower energy revenues related to a 55.5% decrease in KWH sales as a result of less energy scheduled by unit power customers, partially offset by a 14.3% increase in capacity revenues related to higher capacity rates resulting from change-in-law contract provisions that provide for recovery of costs related to the generating resource’s compliance with new environmental requirements.

Wholesale Revenues – Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$5.8	25.6	$38.1	141.1

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 second quarter 2012, wholesale revenues from affiliates were $28.7 million compared to $22.9 million for the corresponding period in 2011. The increase was primarily due to higher energy revenues related to a 116.2% increase in KWH energy sales resulting from the availability of Gulf Power’s lower priced natural gas resources to serve affiliate demand.

89

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2012, wholesale revenues from affiliates were $65.1 million compared to $27.0 million for the corresponding period in 2011. The increase was primarily due to higher energy revenues related to a 327.0% 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

	Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
	(change in millions)	(% change)	(change in millions)	(% change)
Fuel	$  (37.5)	(21.0)	$  (48.2)	(15.5)
Purchased power – non-affiliates	1.2	11.0	5.4	30.3
Purchased power – affiliates	(7.3)	(58.5)	(21.5)	(73.5)
Total fuel and purchased power expenses	$  (43.6)		$  (64.3)

In the second quarter 2012, total fuel and purchased power expenses were $158.5 million compared to $202.1 million for the corresponding period in 2011. The decrease in fuel and purchased power expenses was primarily due to a $47.2 million decrease in the average cost of generated and purchased power and a $28.8 million decrease related to the volume of KWHs generated, partially offset by a $32.4 million increase related to the volume of KWHs purchased.

For year-to-date 2012, total fuel and purchased power expenses were $293.3 million compared to $357.6 million for the corresponding period in 2011. The decrease in fuel and purchased power expenses was primarily due to a $109.9 million decrease in the average cost of generated and purchased power and a $53.4 million decrease related to the volume of KWHs generated, partially offset by a $99.0 million increase related to the volume of 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.

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

	Second Quarter 2012	Second Quarter 2011	Year-to-Date 2012	Year-to-Date 2011
Total generation (millions of KWHs)	2,650	3,229	4,991	6,031
Total purchased power (millions of KWHs)	1,609	947	3,360	1,395
Sources of generation (percent) –
Coal	66	72	60	70
Gas	34	28	40	30
Cost of fuel, generated (cents per net KWH) –
Coal	4.34	5.00	4.32	5.01
Gas	4.27	4.37	3.81	4.18
Average cost of fuel, generated (cents per net KWH)	4.32	4.82	4.12	4.76
Average cost of purchased power (cents per net KWH)(a)	2.74	4.89	2.61	5.05

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

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Fuel

In the second quarter 2012, fuel expense was $141.2 million compared to $178.7 million for the corresponding period in 2011. The decrease was primarily due to a higher utilization of lower cost natural gas-fired sources, a 2.3% decrease in the average cost of natural gas per KWH generated, and a 17.9% decrease in KWHs generated as a result of displacement of coal-fired generation by energy purchases. These decreases were partially offset by a 69.9% increase in KWHs purchased.

For year-to-date 2012, fuel expense was $262.3 million compared to $310.5 million for the corresponding period in 2011. The decrease was primarily due to a higher utilization of lower cost natural gas-fired sources, an 8.9% decrease in the average cost of natural gas per KWH generated, and a 17.3% decrease in KWHs generated as a result of displacement of coal-fired generation by energy purchases. These decreases were partially offset by a 140.8% increase in KWHs purchased.

In the second quarter and year-to-date 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 second quarter 2012, purchased power expense from non-affiliates was $12.1 million compared to $10.9 million for the corresponding period in 2011. The increase was primarily due to a $1.2 million increase in energy costs resulting from a 119% increase in KWHs purchased as the cost through third party PPAs was lower than the cost of available Gulf Power-owned generation.

For year-to-date 2012, purchased power expense from non-affiliates was $23.3 million compared to $17.9 million for the corresponding period in 2011. The increase was primarily due to a $5.4 million increase in energy costs resulting from a 316% increase in KWHs purchased as the cost through third party PPAs was lower than the cost of available Gulf Power-owned generation.

In the second quarter 2012, the average cost of purchased power from non-affiliates was 2.5 cents per net KWH compared to 4.7 cents per net KWH for the corresponding period in 2011. For year-to-date 2012, the average cost of purchased power from non-affiliates was 2.4 cents per net KWH compared to 5.2 cents per net KWH for the corresponding period in 2011. The decreases were 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 second quarter 2012, purchased power expense from affiliates was $5.2 million compared to $12.5 million for the corresponding period in 2011. The decrease was primarily due to a 72.7% decrease in the volume of KWHs purchased.

For year-to-date 2012, purchased power expense from affiliates was $7.7 million compared to $29.2 million for the corresponding period in 2011. The decrease was primarily due to an 86.1% decrease in the volume of KWHs purchased.

In the second quarter 2012, the average cost of purchased power from affiliates was 8.7 cents per net KWH compared to 5.4 cents per net KWH for the corresponding period in 2011. For year-to-date 2012, the average cost of purchased power from affiliates was 9.9 cents per net KWH compared to 4.9 cents per net KWH for the corresponding period in 2011.

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The increases were primarily due to comparable total capacity costs for fewer KWHs purchased, partially offset by lower energy costs per KWHs.

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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$7.2	9.9	$1.9	1.3

In the second quarter 2012, other operations and maintenance expenses were $79.8 million compared to $72.6 million for the corresponding period in 2011. The increase was primarily due to increases of $3.3 million for labor and benefit-related expenses, $2.0 million in marketing programs, $1.1 million in routine and planned outage maintenance expense at generation facilities, and $1.1 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.

For year-to-date 2012, other operations and maintenance expenses were $155.0 million compared to $153.1 million for the corresponding period in 2011. The increase was primarily due to increases of $6.7 million for labor and benefit-related expenses, $3.4 million in marketing programs, and $1.8 million in other energy services projects, partially offset by a $10.2 million decrease in routine and planned outage maintenance expense at generation facilities. 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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$2.9	8.9	$4.4	6.9

In the second quarter 2012, depreciation and amortization was $35.2 million compared to $32.3 million for the corresponding period in 2011. For year-to-date 2012, depreciation and amortization was $68.5 million compared to $64.1 million for the corresponding period in 2011. The increases were primarily due to additions of environmental control projects at generation facilities and net additions to transmission and distribution facilities.

Allowance for Equity Funds Used During Construction

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(0.8)	(31.2)	$(1.7)	(36.2)

In the second quarter 2012, AFUDC equity was $1.7 million compared to $2.5 million for the corresponding period in 2011. The decrease was primarily due to an environmental control project at Plant Crist being placed into service in the second quarter 2012.

For year-to-date 2012, AFUDC equity was $3.0 million compared to $4.7 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.

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GULF POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Income

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$1.8	N/M	$1.4	N/M

N/M – Not meaningful

In the second quarter and year-to-date 2012, interest income was $1.8 million and $1.4 million, respectively. The amounts for the corresponding periods in 2011 were immaterial. The increases were primarily due to an IRS refund of interest claims for multiple tax years.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$1.3	8.8	$3.0	10.7

In the second quarter 2012, interest expense, net of amounts capitalized was $15.7 million compared to $14.4 million for the corresponding period in 2011. For year-to-date 2012, interest expense, net of amounts capitalized was $31.1 million compared to $28.1 million for the corresponding period in 2011. The increases were primarily due to net increases in long-term debt.

Income Taxes

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$1.9	9.6	$6.9	25.7

In the second quarter 2012, income taxes were $22.1 million compared to $20.2 million for the corresponding period in 2011. The increase was primarily due to higher pre-tax earnings and a reduction in the tax benefits associated with a decrease in AFUDC equity, which is non-taxable.

For year-to-date 2012, income taxes were $33.8 million compared to $26.9 million for the corresponding period in 2011. The increase was primarily due to higher pre-tax earnings.

FUTURE EARNINGS POTENTIAL

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

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Environmental Matters

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

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 and Note (B) to the Condensed Financial Statements under “Environmental Matters – New Source Review Actions” herein for additional information. 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. 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 in May 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.

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed Gulf Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $375 million to up to $300 million as follows:

	2012		2013		2014
				(in millions)
MATS rule		Up to $35		Up to $85		Up to $180

In addition, Gulf Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $105 million to up to $35 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:

	2012		2013		2014
				(in millions)
Proposed water and coal combustion byproducts rules		—		Up to $10		Up to $25

While Gulf Power’s ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Gulf Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) could be approximately $1.6 billion. Included in this amount is approximately $400 million that is also included in the 2012 through 2014 base level capital investment of Gulf Power described in the Form 10-K in anticipation of these rules.

Gulf Power’s ultimate compliance strategy and actual 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; 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. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, 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.

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 and fine particulate matter 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Gulf Power’s service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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 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.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Gulf Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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. Environmental groups and other parties have filed lawsuits 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. The ultimate outcome of these matters 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.

On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA’s actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.

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PSC Matters

Retail Base Rate Case

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

On 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. On July 17, 2012, the Florida PSC denied Gulf Power’s motion and reaffirmed its earlier decision.

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.

On June 19, 2012, the Florida PSC approved a decrease in Gulf Power’s fuel rates of 7.8%, which will reduce annual billings by approximately $58.8 million effective July 2, 2012.

Over recovered fuel costs at June 30, 2012 totaled $41.6 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 June 30, 2012 totaled $7.9 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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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi. 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. Gulf Power’s portion of the cost is expected to be recovered through the environmental cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.

Over recovered environmental costs at June 30, 2012 totaled $3.6 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.

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 June 30, 2012 totaled $1.6 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

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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 in Note (B) 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 – “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 June 30, 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 $194.6 million for the first six months of 2012 compared to $175.2 million for the corresponding period in 2011. The $19.4 million increase was primarily due to a $49.7 million increase in deferred income taxes related to bonus depreciation, partially offset by a $17.5 million decrease resulting from lower fuel inventory reductions in 2012 as compared to 2011.

Net cash used for investing activities totaled $184.7 million in the first six months of 2012 compared to $179.6 million for the corresponding period in 2011. The $5.1 million increase was primarily due to an increase in cost of removal, net of salvage.

Net cash used for financing activities totaled $6.1 million for the first six months of 2012 compared to $5.3 million provided from financing activities for the corresponding period in 2011. The $11.4 million decrease was primarily due to a $25.0 million decrease in issuance of senior notes and a $10.0 million decrease in issuance of common stock, partially offset by $19.0 million fewer redemptions of senior notes and other long-term debt in 2012.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant balance sheet changes for the first six months of 2012 include a net increase of $125.0 million in property, plant, and equipment, primarily due to the addition of environmental control projects, an increase of $100.6 million in accumulated deferred income taxes, primarily related to bonus depreciation, a $43.2 million increase in prepaid expenses, primarily due to an increase in prepaid income taxes, 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, including estimated capital expenditures to comply with existing environmental regulations, 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 June 30, 2013 to fund maturities of long-term debt.

See FUTURE EARNINGS POTENTIAL – “Environmental Statutes and Regulations – General” herein for a description of Gulf Power’s estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.

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.

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 June 30, 2012, Gulf Power had approximately $21.2 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:

Expires					Executable Term Loans		Due Within One Year(a)
2012	2013	2014	Total	Unused	One     Year	Two     Years	Term     Out	No Term Out
(in millions)			(in millions)		(in millions)		(in millions)
$20	$60	$195	$275	$275	$45	$—	$45	$35

(a) Reflects facilities expiring on or before June 30, 2013.

100

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Most of 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 June 30, 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.

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)
June 30, 2012:
Commercial paper	$114	0.3%	$68	0.3%	$116

(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 June 30, 2012 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$120
Below BBB- and/or Baa3	530

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.

101

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Market Price Risk

Gulf Power’s market risk exposure relative to interest rate changes for the second 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 guidelines of the Florida PSC. As such, Gulf Power had no material change in market risk exposure for the second 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 and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes	Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$(54)	$(41)
Contracts realized or settled	12	18
Current period changes(a)	5	(14)
Contracts outstanding at the end of the period, assets (liabilities), net	$(37)	$(37)

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

The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes	Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Natural gas swaps	$16	$4
Natural gas options	1	—
Other energy-related derivatives	—	—
Total changes	$17	$4

102

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	June 30, 2012	March 31, 2012	December 31, 2011
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	50	41	35
Commodity – Natural gas options	1	2	3
Total hedge volume	51	43	38

The weighted average swap contract cost above market prices was approximately $0.72 per mmBtu as of June 30, 2012, $1.27 per mmBtu as of March 31, 2012, and $1.14 per mmBtu as of December 31, 2011. 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 and six months ended June 30, 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 June 30, 2012 were as follows:

	June 30, 2012     Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3	Years 4&5
	(in millions)
Level 1	$—	$—	$—	$—
Level 2	(37)	(20)	(16)	(1)
Level 3	—	—	—	—
Fair value of contracts outstanding at end of period	$(37)	$(20)	$(16)	$(1)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Gulf Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Gulf Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Gulf Power does not expect the impact of these rules to be material.

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.

103

GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 May 2012, Gulf Power issued $100 million aggregate principal amount of Series 2012A 3.10% Senior Notes due May 15, 2022. The proceeds from the sale of the Series 2012A Senior Notes were used by Gulf Power for the redemption in June 2012 of all of approximately $61 million aggregate principal amount of Gulf Power’s Series F 5.60% Senior Insured Quarterly Notes due April 1, 2033 and $30 million aggregate principal amount of Gulf Power’s Series H 5.25% Senior Notes due July 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Gulf Power’s continuous construction program.

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

104

MISSISSIPPI POWER COMPANY

105

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	192,177		$	207,005		$	358,448		$	387,479
Wholesale revenues, non-affiliates		64,116			67,813			118,347			137,664
Wholesale revenues, affiliates		5,324			6,303			9,364			15,603
Other revenues		4,467			4,920			8,639			8,571
Total operating revenues		266,084			286,041			494,798			549,317
Operating Expenses:
Fuel		105,469			123,674			194,088			244,728
Purchased power, non-affiliates		1,134			1,336			3,077			2,346
Purchased power, affiliates		10,843			19,867			19,703			28,217
Other operations and maintenance		60,501			64,512			115,396			134,879
Depreciation and amortization		22,517			20,345			44,998			40,208
Taxes other than income taxes		18,634			17,251			40,337			34,732
Total operating expenses		219,098			246,985			417,599			485,110
Operating Income		46,986			39,056			77,199			64,207
Other Income and (Expense):
Allowance for equity funds used during construction		13,870			4,991			25,697			8,122
Interest income		380			401			500			743
Interest expense, net of amounts capitalized		(13,023	)		(5,532	)		(20,828	)		(11,545	)
Other income (expense), net		(539	)		(613	)		(781	)		(1,016	)
Total other income and (expense)		688			(753	)		4,588			(3,696	)
Earnings Before Income Taxes		47,674			38,303			81,787			60,511
Income taxes		12,214			12,587			20,639			19,745
Net Income		35,460			25,716			61,148			40,766
Dividends on Preferred Stock		433			433			866			866
Net Income After Dividends on Preferred Stock	$	35,027		$	25,283		$	60,282		$	39,900

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2012		2011		2012			2011
	(in thousands)				(in thousands)
Net Income After Dividends on Preferred Stock	$	35,027	$	25,283	$	60,282		$	39,900
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $7, $(296) and $6, respectively		—		13		(478	)		11
Reclassification adjustment for amounts included in net income, net of tax of $132, $-, $148 and $-, respectively		212		—		238			—
Total other comprehensive income (loss)		212		13		(240	)		11
Comprehensive Income	$	35,239	$	25,296	$	60,042		$	39,911

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

106

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months
	Ended June 30,
	2012			2011
	(in thousands)
Operating Activities:
Net income	$	61,148		$	40,766
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		43,955			43,032
Deferred income taxes		1,280			(8,136	)
Investment tax credits received		13,974			29,556
Allowance for equity funds used during construction		(25,697	)		(8,122	)
Pension, postretirement, and other employee benefits		3,993			1,601
Hedge settlements		(15,983	)		—
Stock based compensation expense		1,344			1,060
Other, net		(2,648	)		(5,584	)
Changes in certain current assets and liabilities —
-Receivables		(12,424	)		(8,041	)
-Fossil fuel stock		(32,797	)		(8,838	)
-Materials and supplies		212			(603	)
-Prepaid income taxes		11,974			17,075
-Other current assets		(7,281	)		1,021
-Accounts payable		3,408			17,927
-Accrued taxes		(16,785	)		(6,227	)
-Accrued compensation		(7,002	)		(7,064	)
-Over recovered regulatory clause revenues		15,871			(10,748	)
-Other current liabilities		7,640			2,066
Net cash provided from operating activities		44,182			90,741
Investing Activities:
Property additions		(763,641	)		(365,261	)
Cost of removal, net of salvage		(1,217	)		(4,339	)
Construction payables		57,283			31,949
Capital grant proceeds		6,146			91,650
Distribution of restricted cash		—			50,000
Other investing activities		(9,690	)		(2,217	)
Net cash used for investing activities		(711,119	)		(198,218	)
Financing Activities:
Proceeds —
Capital contributions from parent company		277,633			100,878
Senior notes issuances		400,000			—
Interest-bearing refundable deposit related to asset sale		150,000			—
Other long-term debt issuances		—			75,000
Redemptions —
Capital leases		(633	)		(705	)
Other long-term debt		(165,000	)		(130,000	)
Payment of preferred stock dividends		(866	)		(866	)
Payment of common stock dividends		(53,400	)		(37,750	)
Other financing activities		998			(134)
Net cash provided from financing activities		608,732			6,423
Net Change in Cash and Cash Equivalents		(58,205	)		(101,054	)
Cash and Cash Equivalents at Beginning of Period		211,585			160,779
Cash and Cash Equivalents at End of Period	$	153,380		$	59,725
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $29,433 and $12,050, net of $12,476 and $2,572 capitalized for 2012 and 2011, respectively)	$	16,603		$	9,505
Income taxes, net		(7,756	)		(32,648	)
Noncash transactions—accrued property additions at end of period		193,184			70,772

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

107

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2012			At December 31, 2011
	(in thousands)
Current Assets:
Cash and cash equivalents	$	153,380		$	211,585
Receivables —
Customer accounts receivable		37,632			32,551
Unbilled revenues		36,060			27,239
Other accounts and notes receivable		5,072			7,080
Affiliated companies		25,497			23,078
Accumulated provision for uncollectible accounts		(306	)		(547	)
Fossil fuel stock, at average cost		172,970			140,173
Materials and supplies, at average cost		30,576			30,787
Other regulatory assets, current		65,251			69,201
Prepaid income taxes		192,067			37,793
Other current assets		6,230			8,881
Total current assets		724,429			587,821
Property, Plant, and Equipment:
In service		2,956,019			2,902,240
Less accumulated provision for depreciation		1,052,399			1,019,251
Plant in service, net of depreciation		1,903,620			1,882,989
Construction work in progress		1,699,239			955,135
Total property, plant, and equipment		3,602,859			2,838,124
Other Property and Investments		5,970			6,520
Deferred Charges and Other Assets:
Deferred charges related to income taxes		47,979			25,009
Other regulatory assets, deferred		195,721			185,694
Other deferred charges and assets		37,640			28,674
Total deferred charges and other assets		281,340			239,377
Total Assets	$	4,614,598		$	3,671,842

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

108

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At June 30, 2012			At December 31, 2011
	(in thousands)
Current Liabilities:
Securities due within one year	$	165,000		$	240,633
Interest-bearing refundable deposit related to asset sale		150,000			—
Accounts payable —
Affiliated		62,007			62,650
Other		228,506			168,309
Customer deposits		14,190			13,658
Accrued taxes —
Accrued income taxes		3,803			3,813
Other accrued taxes		37,327			53,825
Accrued interest		20,095			12,750
Accrued compensation		8,887			15,889
Other regulatory liabilities, current		5,553			5,779
Over recovered regulatory clause liabilities		76,373			60,502
Liabilities from risk management activities		26,699			54,127
Other current liabilities		21,913			17,533
Total current liabilities		820,353			709,468
Long-term Debt		1,410,660			1,103,596
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		377,763			270,397
Deferred credits related to income taxes		10,536			11,058
Accumulated deferred investment tax credits		206,607			109,761
Employee benefit obligations		162,266			161,065
Other cost of removal obligations		135,540			126,424
Other regulatory liabilities, deferred		64,710			60,848
Other deferred credits and liabilities		57,181			37,228
Total deferred credits and other liabilities		1,014,603			776,781
Total Liabilities		3,245,616			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		975,198			694,855
Retained earnings		332,450			325,568
Accumulated other comprehensive loss		(9,137	)		(8,897	)
Total common stockholder’s equity		1,336,202			1,049,217
Total Liabilities and Stockholder's Equity	$	4,614,598		$	3,671,842

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

109

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2012 vs. SECOND QUARTER 2011

AND

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

On June 22, 2012, the Mississippi PSC denied the proposed Certificated New Plant-A (CNP-A) rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSC’s issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSC’s June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Power’s request for interim rates under bond while the Mississippi Supreme Court decides Mississippi Power’s appeal of the Mississippi PSC’s June 22, 2012 decision. The ultimate outcome of this matter cannot be determined at this time.

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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$9.7	38.5	$20.4	51.1

Mississippi Power’s net income after dividends on preferred stock for the second quarter 2012 was $35.0 million compared to $25.3 million for the corresponding period in 2011. The increase in net income after dividends on preferred stock for the second quarter 2012 was the result of an increase in AFUDC equity primarily related to the construction of the Kemper IGCC, a decrease in operations and maintenance expenses, and an increase in territorial base revenues primarily due to a wholesale base rate increase effective April 1, 2012, partially offset by an increase in interest expense, net of amounts capitalized.

110

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power’s net income after dividends on preferred stock for year-to-date 2012 was $60.3 million compared to $39.9 million for the corresponding period in 2011. The increase in net income after dividends on preferred stock for year-to-date 2012 was primarily due to an increase in AFUDC equity primarily related to the construction of the Kemper IGCC 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 2012 and an increase in interest expense, net of amounts capitalized.

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.

Retail Revenues

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(14.8)	(7.2)	$(29.1)	(7.5)

In the second quarter 2012, retail revenues were $192.2 million compared to $207.0 million for the corresponding period in 2011. For year-to-date 2012, retail revenues were $358.4 million compared to $387.5 million for the corresponding period in 2011.

Details of the change to retail revenues were as follows:

	Second Quarter 2012		Year-to-Date 2012
	(in millions)	(% change)	(in millions)	(% change)
Retail – prior year	$207.0		$387.5
Estimated change in –
Rates and pricing	(0.6)	(0.3)	(1.7)	(0.4)
Sales growth (decline)	2.1	1.0	5.2	1.3
Weather	(2.8)	(1.4)	(7.8)	(2.0)
Fuel and other cost recovery	(13.5)	(6.5)	(24.8)	(6.4)
Retail – current year	$192.2	(7.2)%	$358.4	(7.5)%

Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 due to decreases of $0.6 million and $1.7 million, respectively, 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 second quarter 2012 when compared to the corresponding period in 2011. KWH energy sales to industrial customers increased 3.3% 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 3.6% and 1.5%, respectively, when compared to the corresponding period in 2011 due to a small increase in the number of residential customers and improving economic conditions.

Revenues attributable to changes in sales increased for year-to-date 2012 when compared to the corresponding period in 2011 due to an increase in sales to residential, commercial, and industrial customers. KWH energy sales to industrial customers increased 3.9% due to increased production for some of the larger customers resulting from an improving economy. Weather-adjusted KWH energy sales to residential and commercial customers increased 2.3% and 1.3%,

111

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

respectively, when compared to the corresponding period in 2011. The increase in residential and commercial sales was primarily due to a small increase in the number of residential customers and improving economic conditions.

Revenues attributable to changes in weather decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily due to milder weather.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2012 when compared to the corresponding periods in 2011 primarily as a result of lower recoverable fuel costs, partially offset by an increase in revenues related to the retail portion of ad valorem taxes. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power’s service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. The retail portion of ad valorem tax expense is recoverable under Mississippi Power’s ad valorem tax cost recovery clause and, therefore, does not affect net income.

Wholesale Revenues – Non-Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(3.7)	(5.5)	$(19.4)	(14.0)

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

In the second quarter 2012, wholesale revenues from non-affiliates were $64.1 million compared to $67.8 million for the corresponding period in 2011. The decrease was due to a $10.1 million decrease in energy revenues, of which $2.1 million was associated with a decrease in KWH sales due to lower demand primarily resulting from milder weather in the second quarter 2012 compared to the corresponding period in 2011 and $8.0 million was associated with lower fuel prices, partially offset by a $6.4 million increase in revenues primarily resulting from a wholesale base rate increase effective April 1, 2012.

For year-to-date 2012, wholesale revenues from non-affiliates were $118.3 million compared to $137.7 million for the corresponding period in 2011. The decrease was due to a $21.0 million decrease in energy revenues, of which $7.2 million was associated with a decrease in KWH sales due to lower demand primarily resulting from milder weather in 2012 compared to the corresponding period in 2011 and $13.8 million was associated with lower fuel prices, partially offset by a $1.6 million increase in revenues primarily resulting from a wholesale base rate increase effective April 1, 2012.

Wholesale Revenues – Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(1.0)	(15.5)	$(6.2)	(40.0)

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.

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In the second quarter 2012, wholesale revenues from affiliates were $5.3 million compared to $6.3 million for the corresponding period in 2011. The decrease was primarily due to a $0.4 million decrease in capacity revenues and a $0.6 million decrease in energy revenues, of which $4.3 million was associated with lower prices, partially offset by $3.7 million associated with an increase in KWH sales.

For year-to-date 2012, wholesale revenues from affiliates were $9.4 million compared to $15.6 million for the corresponding period in 2011. The decrease was primarily due to a $0.4 million decrease in capacity revenues and a $5.8 million decrease in energy revenues, of which $6.1 million was associated with lower prices, partially offset by $0.3 million associated with an increase in KWH sales.

Fuel and Purchased Power Expenses

	Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
	(change in millions)	(% change)	(change in millions)	(% change)
Fuel	$  (18.2)	(14.7)	$  (50.6)	(20.7)
Purchased power – non-affiliates	(0.2)	(15.1)	0.8	31.2
Purchased power – affiliates	(9.1)	(45.4)	(8.5)	(30.2)
Total fuel and purchased power expenses	$  (27.5)		$  (58.3)

In the second quarter 2012, total fuel and purchased power expenses were $117.4 million compared to $144.9 million for the corresponding period in 2011. The decrease was primarily due to a $27.0 million decrease in the cost of fuel and purchased power and a $0.5 million decrease in total KWHs generated and purchased.

For year-to-date 2012, total fuel and purchased power expenses were $216.9 million compared to $275.2 million for the corresponding period in 2011. The decrease was primarily due to a $44.8 million decrease in the cost of fuel and purchased power and a $13.5 million decrease in total KWHs generated and purchased.

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

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

	Second Quarter 2012	Second Quarter 2011	Year-to-Date 2012	Year-to-Date 2011
Total generation (millions of KWHs)	3,359	3,226	6,341	6,590
Total purchased power (millions of KWHs)	466	578	912	882
Sources of generation (percent) –
Coal	29	46	25	41
Gas	71	54	75	59
Cost of fuel, generated (cents per net KWH) –
Coal	4.88	4.34	4.83	4.29
Gas	2.72	3.98	2.77	3.84
Average cost of fuel, generated (cents per net KWH)	3.39	4.16	3.34	4.04
Average cost of purchased power (cents per net KWH)	2.57	3.67	2.50	3.47

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Fuel

In the second quarter 2012, fuel expense was $105.5 million compared to $123.7 million for the corresponding period in 2011. The decrease was primarily due to a 31.7% decrease in the average cost of natural gas per KWH generated primarily resulting from lower gas prices, partially offset by a 4.7% increase in generation from Mississippi Power’s facilities resulting from higher energy demand in the second quarter 2012.

For year-to-date 2012, fuel expense was $194.1 million compared to $244.7 million for the corresponding period in 2011. The decrease was primarily due to a 27.9% decrease in the average cost of natural gas per KWH generated primarily resulting from lower gas prices and a 4.2% decrease in generation from Mississippi Power’s facilities resulting from lower energy demand primarily due to milder weather in 2012.

Purchased Power – Non-Affiliates

In the second quarter 2012, purchased power expense from non-affiliates was $1.1 million compared to $1.3 million for the corresponding period in 2011. The decrease was primarily the result of a 63.1% decrease in the average cost of purchased power per KWH, partially offset by a 129.8% increase in KWH volume purchased. The increase in the volume of KWHs purchased was due to a lower marginal cost of fuel compared to the cost of generation. The decrease in the average cost per KWH purchased was due to a lower marginal cost of fuel.

For year-to-date 2012, purchased power expense from non-affiliates was $3.1 million compared to $2.3 million for the corresponding period in 2011. The increase was primarily the result of a 96.7% increase in KWH volume purchased, partially offset by a 33.3% decrease in the average cost of purchased power per KWH. The increase in the volume of KWHs purchased was due to a lower marginal cost of fuel compared to the cost of generation.

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

Purchased Power – Affiliates

In the second quarter 2012, purchased power expense from affiliates was $10.8 million compared to $19.9 million for the corresponding period in 2011. The decrease was primarily due to a 27.9% decrease in KWH volume purchased and a 24.3% decrease in the average cost of purchased power per KWH.

For year-to-date 2012, purchased power expense from affiliates was $19.7 million compared to $28.2 million for the corresponding period in 2011. The decrease was primarily due to a 6.5% decrease in KWH volume purchased and a 25.4% 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.

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Other Operations and Maintenance Expenses

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(4.0)	(6.2)	$(19.5)	(14.4)

In the second quarter 2012, other operations and maintenance expenses were $60.5 million compared to $64.5 million for the corresponding period in 2011. The decrease was primarily due to a $9.7 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. The decrease was partially offset by a $3.4 million increase in generation expenses primarily related to scheduled outages and a $2.0 million increase in administrative and general expenses.

For year-to-date 2012, other operations and maintenance expenses were $115.4 million compared to $134.9 million for the corresponding period in 2011. The decrease was primarily due to a $20.5 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 $3.1 million decrease in generation maintenance expenses. These decreases were partially offset by a $3.3 million increase in administrative and general expenses.

See Notes 1 and 7 to the financial statements of Mississippi Power under “Purchase of the Plant Daniel Combined Cycle Generating Units” and “Long-Term Service Agreements,” respectively, in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$2.2	10.7	$4.8	11.9

In the second quarter 2012, depreciation and amortization was $22.5 million compared to $20.3 million for the corresponding period in 2011. The increase was primarily due to a $3.4 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 and a $0.5 million decrease in ARO amortization resulting from the deferral of the gain on the settlement of an ARO in 2011.

For year-to-date 2012, depreciation and amortization was $45.0 million compared to $40.2 million for the corresponding period in 2011. The increase was primarily due to a $6.7 million increase in depreciation on additional plant in service and a $3.9 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 $5.3 million decrease in amortization primarily resulting from a regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4 and a $0.5 million decrease in ARO amortization resulting from the deferral of the gain on the settlement of an ARO in 2011.

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.

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Taxes Other Than Income Taxes

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$1.3	8.0	$5.6	16.1

In the second quarter 2012, taxes other than income taxes were $18.6 million compared to $17.3 million for the corresponding period in 2011. The increase was primarily due to a $2.6 million increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4, partially offset by a $1.5 million decrease in franchise taxes.

For year-to-date 2012, taxes other than income taxes were $40.3 million compared to $34.7 million for the corresponding period in 2011. The increase was primarily due to a $6.6 million increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4, partially offset by a $1.3 million decrease in franchise taxes.

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

Allowance for Equity Funds Used During Construction

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$8.9	177.9	$17.6	216.4

In the second quarter 2012, AFUDC equity was $13.9 million compared to $5.0 million for the corresponding period in 2011. For year-to-date 2012, AFUDC equity was $25.7 million compared to $8.1 million for the corresponding period in 2011. These increases were primarily due to the construction of the Kemper IGCC.

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

Interest Expense, Net of Amounts Capitalized

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$7.5	135.4	$9.3	80.4

In the second quarter 2012, interest expense, net of amounts capitalized was $13.0 million compared to $5.5 million for the corresponding period in 2011. Capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC in the second quarter 2012 was $5.9 million compared to $1.6 million for the corresponding period in 2011. The increase in interest expense, net of amounts capitalized was primarily due to an $11.4 million increase in interest expense associated with the issuances of new long-term debt in September 2011, October 2011, and March 2012 and a $3.8 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 an undivided interest in the Kemper IGCC. The increase was partially offset by a $4.3 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.

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For year-to-date 2012, interest expense, net of amounts capitalized was $20.8 million compared to $11.5 million for the corresponding period in 2011. Capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC for year-to-date 2012 was $12.5 million compared to $2.6 million for the corresponding period in 2011. The increase in interest expense, net of amounts capitalized was primarily due to a $19.9 million increase in interest expense associated with the issuances of new long-term debt in September 2011, October 2011, and March 2012 and a $4.8 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 an undivided interest in the Kemper IGCC. The increase was partially offset by a $9.9 million increase in capitalized interest primarily resulting from AFUDC debt associated with the Kemper IGCC and a $3.8 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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(0.4)	(3.0)	$0.9	4.5

In the second quarter 2012, income taxes were $12.2 million compared to $12.6 million for the corresponding period in 2011. The decrease was primarily due to a $3.3 million decrease resulting from higher AFUDC equity, which is non-taxable, and a $0.6 million decrease in unrecognized tax benefits, partially offset by a $3.2 million increase resulting from higher pre-tax earnings and a $0.3 million increase due to lower State of Mississippi manufacturing investment tax credits.

For year-to-date 2012, income taxes were $20.6 million compared to $19.7 million for the corresponding period in 2011. The increase was primarily due to a $7.8 million increase resulting from higher pre-tax earnings and a $0.6 million increase due to lower State of Mississippi manufacturing investment tax credits, partially offset by a $6.7 million decrease resulting from higher AFUDC equity, which is non-taxable, and a $0.8 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.

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

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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 the unit co-owned by Mississippi Power). 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. While further analysis of the MATS rule is required and the ultimate costs remain uncertain, the compliance decisions made through the second quarter 2012 have allowed Mississippi Power to further develop its cost estimates for compliance with the MATS rule. As a result, estimated compliance costs for the MATS rule in the 2012 through 2014 period have been revised from up to $430 million to approximately $55 million as follows:

	2012	2013	2014
		(in millions)
MATS rule	—	$5	$50

In addition, Mississippi Power has further developed its estimated capital expenditures and associated timing of these expenditures to comply with the proposed water and coal combustion byproducts rules, resulting in a reduction, due primarily to timing, in estimated compliance costs for 2012 through 2014. Potential incremental environmental compliance investments to comply with the proposed water and coal combustion byproducts rules have been revised from up to $121 million to approximately $40 million over the 2012 through 2014 period, based on the assumption that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule. These potential incremental environmental compliance investments are estimated as follows:

	2012	2013	2014
		(in millions)
Proposed water and coal combustion byproducts rules	$1	$10	$30

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While Mississippi Power’s ultimate costs of compliance with the MATS rule and the proposed water and coal combustion byproducts rules remain uncertain, Mississippi Power estimates that compliance costs through 2021 (assuming that coal combustion byproducts will continue to be regulated as non-hazardous solid waste under the proposed rule) will be at the low end of the $1 billion to $2 billion range provided in the Form 10-K. Included in this amount is approximately $354 million that is also included in the 2012 through 2014 base level capital investment of Mississippi Power described herein in anticipation of these rules. See FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” herein for additional information.

Mississippi Power’s ultimate compliance strategy and actual 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; 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. Compliance costs may arise from retirement and replacement of existing units, installation of additional environmental controls, upgrades to the transmission system, 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.

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 and fine particulate matter 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.

On June 14, 2012, the EPA proposed a rule that would increase the stringency of the fine particulate matter national ambient air quality standards. If adopted, the proposed standards could result in the designation of new nonattainment areas within Mississippi Power’s service territory. As part of a related settlement, the EPA has agreed to finalize the proposed rule by December 14, 2012. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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 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.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Water Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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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. Environmental groups and other parties have filed lawsuits 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. The ultimate outcome of these matters 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.

On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA’s actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.

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 2012. The ultimate outcome of this matter cannot be determined at this time.

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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. An order granting the suspension of the 2011 PEP lookback was signed by the Mississippi PSC on May 8, 2012. 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 February 14, 2012, Mississippi Power submitted its 2012 ECO Plan filing, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2, Mississippi Power revised the 2012 ECO Plan filing to exclude scrubber expenditures from rate base, which resulted in a 0.16% decrease in annual revenues. On June 22, 2012, the 2012 ECO Plan filing, including the proposed rate decrease, was approved by the Mississippi PSC, effective on June 29, 2012.

On April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power’s portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power’s portion of the cost is expected to be recovered through the ECO Plan. As of June 30, 2012, total project expenditures were $82.0 million, with Mississippi Power’s portion being $41.0 million. The ultimate outcome of this matter cannot be determined at this time.

Certificated New Plant

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 and “Integrated Coal Gasification Combined Cycle” herein for additional information.

On May 23, 2012, the Mississippi Public Utilities Staff signed a joint stipulation with Mississippi Power to establish a new rate schedule for CNP-A, a proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. An amended and restated stipulation was subsequently executed and filed on June 1, 2012. On June 14, 2012, Mississippi Power submitted to the Mississippi PSC a proposed supplemental compliance filing to establish the new CNP-A rate schedule and a stipulated rate increase based upon the revenue request of between $55.3 million and $58.6 million to recover financing costs over the remainder of 2012.

121

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On June 22, 2012, the Mississippi PSC denied the proposed CNP-A rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSC’s issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSC’s June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Power’s request for interim rates under bond while the Mississippi Supreme Court decides Mississippi Power’s appeal of the Mississippi PSC’s June 22, 2012 decision. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

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

At June 30, 2012, the amount of over recovered retail fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $55.5 million compared to $42.4 million at December 31, 2011. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At June 30, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $17.4 million and $2.4 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at June 30, 2012 and December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Power’s Condensed Balance Sheets herein was $1.0 million and $1.7 million, respectively. 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, any changes in the billing factors will not have a significant effect on Mississippi Power’s revenues or net income, but will affect 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. 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. In February 2011, the Chancery Court issued a judgment affirming the 2010 MPSC Order and, in March 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.

122

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On March 30, 2012, the Mississippi PSC issued temporary authorization for the continuation of construction of the Kemper IGCC. 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 18, 2012, Mississippi Power’s motion to join the appeal was approved.

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 and certain general exceptions, including change of law, force majeure, and beneficial capital), (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 Kemper IGCC). The current cost estimate of the Kemper IGCC is $2.88 billion, including a $72 million contingency.

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, 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 Kemper IGCC 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 has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site in Kemper County. The estimated capital cost of the mine is approximately $245 million, of which $99.9 million has been incurred through June 30, 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. Due to the fact that Liberty Fuels conducts all of its activities on behalf of Mississippi Power, Liberty Fuels qualifies as a variable interest entity for which Mississippi Power is the primary beneficiary. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Consistent with the requirements of consolidation accounting, Liberty Fuels is consolidated in the financial statements of Mississippi Power and accordingly the asset retirement cost and the ARO have been recorded in Mississippi Power’s financial statements. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

In December 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.

123

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. In April 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 June 30, 2012, Mississippi Power received or accrued tax benefits totaling $197 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. Based on current tax laws and regulations in effect, Mississippi Power expects to receive substantially all of the tax credits accrued through June 30, 2012 by June 30, 2013.

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. 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 June 29, 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012 and reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC, subject to approval by the Mississippi PSC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.

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 is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody’s or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA’s ability to request a refund, the deposit has been presented as a current liability in Mississippi Power’s Condensed Balance Sheet herein and as financing proceeds in Mississippi Power’s Condensed Statement of Cash Flows herein.

As of June 30, 2012, Mississippi Power had spent a total of $1.7 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, $1.6 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $29.0 million was recorded in other regulatory assets, $2.6 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 and “PSC Matters — Certificated New Plant” herein for information on the proposed rate schedules related to the Kemper IGCC.

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

124

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, the utilization of a portion of Mississippi Power’s tax credits has been delayed, thereby offsetting the positive cash flow benefit of bonus depreciation for Mississippi Power in 2012. Mississippi Power expects to receive substantially all of the tax credits accrued through June 30, 2012 by June 30, 2013.

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 in Note (B) 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.

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.

125

MISSISSIPPI 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 Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Power’s financial condition remained stable at June 30, 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 $44.2 million for the first six months of 2012 compared to $90.7 million for the corresponding period in 2011. The $46.5 million decrease in cash provided from operating activities is primarily due to a $15.6 million decrease in investment tax credits received, a $16.0 million decrease in hedge settlements related to the settlement of interest rate swaps, a $24.0 million increase in fuel inventory, and a $14.5 million decrease in accounts payable primarily due to timing of cash payments. These decreases in cash provided from operating activities are partially offset by a $26.6 million increase in over recovered regulatory clause revenues primarily due to lower fuel costs.

Net cash used for investing activities totaled $711.1 million for the first six months of 2012 compared to $198.2 million for the corresponding period in 2011. The $512.9 million increase in net cash used for investing activities is primarily due to an increase in property additions of $398.4 million primarily related to the Kemper IGCC, a $50.0 million decrease in restricted cash, a $25.3 million increase in construction payable, and an $85.5 million decrease in capital grant proceeds related to CCPI2 and smart grid investment grants.

Net cash provided from financing activities totaled $608.7 million for the first six months of 2012 compared to $6.4 million for the corresponding period in 2011. The $602.3 million increase in net cash provided from financing activities was primarily due to the issuance of $400.0 million of senior notes in March 2012, a $176.8 million increase in capital contributions from Southern Company, a $75.0 million decrease in other long-term debt issuances, and the receipt of a $150.0 million interest-bearing refundable deposit related to a pending asset sale, partially offset by a $35.0 million increase in redemptions of long-term debt in the second quarter 2012 compared to the corresponding period in 2011.

Significant balance sheet changes for the first six months of 2012 include a decrease in cash and cash equivalents of $58.2 million primarily due to $165.0 million of long-term debt redemptions and payments and increased capital spending, partially offset by 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 an undivided interest in the Kemper IGCC. Prepaid income taxes increased $154.3 million primarily due to the Kemper IGCC investment tax credit. Total property, plant, and equipment increased $764.7 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 increased $307.1 million primarily due to the issuance of $400.0 million of senior notes, partially offset by the redemption of $90.0 million of senior notes. Paid-in capital increased $280.3 million primarily due to a $275.0 million capital contribution from Southern Company.

126

MISSISSIPPI POWER COMPANY

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 Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power’s capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental regulations, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $165 million will be required through June 30, 2013 to fund maturities of long-term debt.

See FUTURE EARNINGS POTENTIAL — “Environmental Statutes and Regulations — General” herein for a description of Mississippi Power’s estimated capital expenditures to comply with the MATS rule and proposed water and coal combustion byproducts rules.

See Note 7 to the financial statements of Mississippi Power in Item 8 of the Form 10-K for information on Mississippi Power’s construction program. The construction program of Mississippi Power is currently estimated to include a base level investment of $1.8 billion, $843 million, and $418 million for 2012, 2013, and 2014, respectively. Included in these estimated amounts are expenditures related to the Kemper IGCC of $1.6 billion, $603 million, and $141 million in 2012, 2013, and 2014, respectively, which include additional AFUDC due to the delay in the rate recovery and are net of SMEPA’s 15% expected ownership share of the Kemper IGCC of approximately $482 million and $14 million in 2013 and 2014, respectively. See FUTURE EARNINGS POTENTIAL  — “PSC Matters — Certificated New Plant” and “Integrated Coal Gasification Combined Cycle” herein for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to 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. During the first six months of 2012, Mississippi Power received $275 million in capital contributions from Southern Company. On July 13, 2012, Mississippi Power received $150 million in additional capital contributions from Southern Company. On March 6, 2012, Mississippi Power received a $150 million interest-bearing refundable deposit from SMEPA towards its pending purchase of an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power’s AFUDC rate, which was 9.967% per annum at June 30, 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 is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody’s or ceases to be rated by either of these rating agencies. 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.

127

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees to Mississippi Power. In the event that the DOE does not issue a conditional commitment or a final definitive loan guarantee, Mississippi Power intends to finance the construction of the Kemper IGCC through traditional capital markets financings. 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.

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.

At June 30, 2012, Mississippi Power had approximately $153.4 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2012, including expiration dates, were as follows:

Expires					Executable Term Loans		Due Within One Year(a)
2012	2013	2014	Total	Unused	One     Year	Two     Years	Term     Out	No Term Out
(in millions)			(in millions)		(in millions)		(in millions)
$41	$95	$165	$301	$301	$25	$41	$66	$70

(a) Reflects facilities expiring on or before June 30, 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 June 30, 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 six months ended June 30, 2012.

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

128

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2012, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $311 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool 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 an undivided interest in the Kemper IGCC that could require a refund of the $150 million deposit within 15 days at SMEPA’s discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody’s or ceases to be rated by either of these rating agencies. Additionally, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.

On July 3, 2012, Fitch downgraded the issuer default and unsecured long-term debt ratings of Mississippi Power to A- from A and to A from A+, respectively. Fitch also announced that it had downgraded the pollution control revenue bond ratings of Mississippi Power to A from A+ and the preferred stock ratings of Mississippi Power to BBB+ from A-. Fitch revised the ratings outlook for Mississippi Power to negative from stable.

Market Price Risk

Mississippi Power’s market risk exposure relative to interest rate changes for the second 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 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 second 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 and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes	Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$(56)	$(51)
Contracts realized or settled	15	25
Current period changes(a)	4	(11)
Contracts outstanding at the end of the period, assets (liabilities), net	$(37)	$(37)

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

129

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The changes in the fair value positions of the energy-related derivative contracts, which are substantially all attributable to both the volume and the price of natural gas, for the three and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes	Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Natural gas swaps	$14	$11
Natural gas options	5	3
Other energy-related derivatives	—	—
Total changes	$19	$14

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

	June 30, 2012	March 31, 2012	December 31, 2011
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	29	21	22
Commodity – Natural gas options	5	7	9
Total hedge volume	34	28	31

The weighted average swap contract cost above market prices was approximately $1.08 per mmBtu as of June 30, 2012, $2.13 per mmBtu as of March 31, 2012, and $1.98 per mmBtu as of December 31, 2011. 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 and six months ended June 30, 2012 and 2011 for energy-related derivative contracts that are not hedges were not material.

Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:

		June 30, 2012 Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3	Years 4&5
	(in millions)
Level 1	$ —	$ —	$ —	$—
Level 2	(37)	(25)	(11)	(1)
Level 3	—	—	—	—
Fair value of contracts outstanding at end of period	$(37)	$(25)	$(11)	$(1)

130

MISSISSIPPI 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 Mississippi Power. Regulations to implement the Dodd-Frank Act will impose additional requirements on the use of over-the-counter derivatives for both Mississippi Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Mississippi Power does not expect the impact of these rules to be material.

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 Senior Notes 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 Senior Notes was $300 million. The proceeds from the sales 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, of which $250 million related to the Series 2012A 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 the Series 2011A 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 an undivided interest in the Kemper IGCC. Until the acquisition is closed, the deposit bears interest at Mississippi Power’s AFUDC rate, which was 9.967% per annum at June 30, 2012, and is refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA’s discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody’s or ceases to be rated by either of these rating agencies.

In May 2012, Mississippi Power redeemed $90 million aggregate principal amount of Series E 5-5/8% Senior Notes due May 1, 2033.

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.

131

SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

132

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	177,865		$	232,960		$	318,422		$	430,126
Wholesale revenues, affiliates		105,950			70,569			217,738			153,843
Other revenues		1,990			1,680			3,326			3,027
Total operating revenues		285,805			305,209			539,486			586,996
Operating Expenses:
Fuel		91,551			101,158			180,629			203,873
Purchased power, non-affiliates		22,514			19,664			43,164			28,606
Purchased power, affiliates		2,914			22,178			5,254			37,277
Other operations and maintenance		40,205			40,047			88,594			82,801
Depreciation and amortization		34,016			30,805			65,929			60,972
Taxes other than income taxes		4,567			4,565			9,535			9,328
Total operating expenses		195,767			218,417			393,105			422,857
Operating Income		90,038			86,792			146,381			164,139
Other Income and (Expense):
Interest expense, net of amounts capitalized		(13,949	)		(17,774	)		(27,591	)		(36,603	)
Other income (expense), net		(194	)		(260	)		(164	)		(201	)
Total other income and (expense)		(14,143	)		(18,034	)		(27,755	)		(36,804	)
Earnings Before Income Taxes		75,895			68,758			118,626			127,335
Income taxes		29,293			24,157			42,708			44,991
Net Income	$	46,602		$	44,601		$	75,918		$	82,344

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012		2011			2012			2011
	(in thousands)					(in thousands)
Net Income	$	46,602	$	44,601		$	75,918		$	82,344
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $53, $(23), $(120) and $400, respectively		88		(35	)		(186	)		608
Reclassification adjustment for amounts included in net income, net of tax of $956, $1,084, $1,912 and $2,155, respectively		1,529		1,631			3,039			3,261
Total other comprehensive income (loss)		1,617		1,596			2,853			3,869
Comprehensive Income	$	48,219	$	46,197		$	78,771		$	86,213

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

133

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2012			2011
	(in thousands)
Operating Activities:
Net income	$	75,918		$	82,344
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		71,834			65,877
Deferred income taxes		58,921			12,315
Convertible investment tax credits		1,750			62,298
Deferred revenues		(16,431	)		(23,776	)
Mark-to-market adjustments		(3,847	)		853
Other, net		1,927			3,590
Changes in certain current assets and liabilities —
-Receivables		(30,101	)		(19,276	)
-Fossil fuel stock		(3,301	)		41
-Materials and supplies		(7,761	)		(4,431	)
-Prepaid income taxes		(32,804	)		1,282
-Other current assets		(377	)		1,810
-Accounts payable		(494	)		3,079
-Accrued taxes		13,295			7,737
-Accrued interest		409			50
-Other current liabilities		(195	)		(497	)
Net cash provided from operating activities		128,743			193,296
Investing Activities:
Plant acquisition		(86,500	)		—
Property additions		(67,846	)		(162,004	)
Change in construction payables		(1,168	)		(14,231	)
Payments pursuant to long-term service agreements		(36,316	)		(24,874	)
Other investing activities		153			(3,212	)
Net cash used for investing activities		(191,677	)		(204,321	)
Financing Activities:
Increase (decrease) in notes payable, net		107,147			(68,941	)
Proceeds — Capital contributions		490			120,574
Other long-term debt		3,590			—
Repayments — Other long-term debt		(650	)		(3,116	)
Payment of common stock dividends		(63,500	)		(45,600	)
Other financing activities		2,746			146
Net cash provided from financing activities		49,823			3,063
Net Change in Cash and Cash Equivalents		(13,111	)		(7,962	)
Cash and Cash Equivalents at Beginning of Period		16,943			14,204
Cash and Cash Equivalents at End of Period	$	3,832		$	6,242
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $12,941 and $8,855 capitalized for 2012 and 2011, respectively)	$	21,461		$	37,413
Income taxes, net		13,708			(31,142	)
Noncash transactions — accrued property additions at end of period		46,922			21,077

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

134

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2012		At December 31, 2011
	(in thousands)
Current Assets:
Cash and cash equivalents	$	3,832	$	16,943
Receivables —
Customer accounts receivable		74,413		59,360
Other accounts receivable		2,792		2,122
Affiliated companies		52,796		36,508
Fossil fuel stock, at average cost		16,339		13,038
Materials and supplies, at average cost		45,700		37,603
Prepaid service agreements—current		59,784		28,621
Prepaid income taxes		43,720		5,192
Other prepaid expenses		4,390		4,645
Assets from risk management activities		393		177
Total current assets		304,159		204,209
Property, Plant, and Equipment:
In service		3,602,377		3,167,840
Less accumulated provision for depreciation		710,351		652,087
Plant in service, net of depreciation		2,892,026		2,515,753
Construction work in progress		407,289		666,280
Total property, plant, and equipment		3,299,315		3,182,033
Other Property and Investments:
Goodwill		1,839		1,839
Other intangible assets, net of amortization of $1,867 and $1,476 at June 30, 2012 and December 31, 2011, respectively		47,253		47,644
Total other property and investments		49,092		49,483
Deferred Charges and Other Assets:
Prepaid long-term service agreements		100,971		115,838
Other deferred charges and assets — affiliated		5,259		3,029
Other deferred charges and assets — non-affiliated		26,637		26,385
Total deferred charges and other assets		132,867		145,252
Total Assets	$	3,785,433	$	3,580,977

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

135

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder’s Equity	At June 30, 2012			At December 31, 2011
	(in thousands)
Current Liabilities:
Securities due within one year	$	—		$	555
Notes payable — non-affiliated		289,241			179,520
Accounts payable —
Affiliated		60,378			63,609
Other		46,360			44,321
Accrued taxes —
Accrued income taxes		5,473			2,548
Other accrued taxes		10,526			2,158
Accrued interest		22,284			21,874
Liabilities from risk management activities		6,645			9,651
Other current liabilities		18,940			7,401
Total current liabilities		459,847			331,637
Long-term Debt		1,303,691			1,302,758
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		382,832			319,790
Deferred convertible investment tax credits		131,696			125,065
Deferred capacity revenues — affiliated		8,389			20,637
Other deferred credits and liabilities — affiliated		3,147			3,618
Other deferred credits and liabilities — non-affiliated		4,743			4,965
Total deferred credits and other liabilities		530,807			474,075
Total Liabilities		2,294,345			2,108,470
Redeemable Noncontrolling Interest		6,644			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		1,028,701			1,028,210
Retained earnings		459,719			447,301
Accumulated other comprehensive loss		(3,976	)		(6,829	)
Total common stockholder’s equity		1,484,444			1,468,682
Total Liabilities and Stockholder’s Equity	$	3,785,433		$	3,580,977

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

136

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2012 vs. SECOND QUARTER 2011

AND

YEAR-TO-DATE 2012 vs. YEAR-TO-DATE 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. In accordance with this strategy, the Nacogdoches biomass plant began commercial operation on June 22, 2012. See FUTURE EARNINGS POTENTIAL – “Construction Projects” herein for additional information.

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

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$2.0	4.5	$(6.4)	(7.8)

Southern Power’s net income for the second quarter 2012 was $46.6 million compared to $44.6 million for the corresponding period in 2011. The increase was primarily due to an increase in energy revenues from sales to affiliates under the IIC, lower fuel and purchased power expenses, and lower interest expense. The increase was partially offset by a decrease in energy revenues from non-affiliates, a decrease in capacity revenues due to a reduction in total MWs of capacity under long-term contracts, increased depreciation, and higher income taxes.

Southern Power’s net income for year-to-date 2012 was $75.9 million compared to $82.3 million for the corresponding period in 2011. The decrease was primarily due to a decrease in energy revenues from non-affiliates, a decrease in capacity revenues due to a reduction in total MWs of capacity under long-term contracts, an increase in depreciation, 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 and purchased power expenses, and lower interest expense.

137

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues — Non-Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(55.1)	(23.6)	$(111.7)	(26.0)

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 second quarter 2012 were $177.9 million compared to $233.0 million for the corresponding period in 2011. The decrease was primarily due to a $60.8 million decrease in energy sales, reflecting a 40.3% decrease in the average price of energy, partially offset by a 1.8% increase in KWH sales. The decrease in revenue from energy sales was partially offset by a $5.7 million increase in capacity revenue due to an increase in the total MWs of capacity under contract with non-affiliates.

Wholesale energy sales to non-affiliates for year-to-date 2012 were $318.4 million compared to $430.1 million for the corresponding period in 2011. The decrease was primarily due to a $121.3 million decrease in energy sales, reflecting a 41.7% decrease in the average price of energy and a 4.0% decrease in KWH sales. The decrease in revenue from energy sales was partially offset by a $9.6 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.

Wholesale Revenues — Affiliates

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$35.4	50.1	$63.9	41.5

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 second quarter 2012 were $106.0 million compared to $70.6 million for the corresponding period in 2011. The increase was primarily the result of a $45.4 million increase in energy sales under the IIC, reflecting a 435.1% increase in KWH sales, partially offset by a 37.4% reduction in the average price of energy. The increase in revenue from energy sales was partially offset by an $8.6 million decrease in capacity revenue due to a decrease in total MWs of capacity under contract with affiliates.

Wholesale revenues from affiliates for year-to-date 2012 were $217.7 million compared to $153.8 million for the corresponding period in 2011. The increase was primarily the result of an $87.2 million increase in energy sales under the IIC, reflecting a 360.3% increase in KWH sales, partially offset by a 40.6% reduction in the average price of energy. The increase in revenue from energy sales was partially offset by a $20.6 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.

138

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
	(change in millions)	(% change)	(change in millions)	(% change)
Fuel	$(9.6)	(9.5)	$(23.3)	(11.4)
Purchased power — non-affiliates	2.9	14.5	14.5	50.9
Purchased power — affiliates	(19.3)	(86.9)	(32.0)	(85.9)
Total fuel and purchased power expenses	$(26.0)		$(40.8)

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 throughout the Southern Company system and other available contract resources. Load requirements are submitted to the Power Pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, affiliate-owned generation, or external purchases.

In the second quarter 2012, total fuel and purchased power expenses were $117.0 million compared to $143.0 million for the corresponding period in 2011. Fuel and purchased power expenses decreased $83.3 million due to a 44.8% decrease in the average cost of fuel and a 26.1% decrease in the average cost of purchased power. The decrease was partially offset by a $57.3 million net increase associated with a 43.1% increase in the volume of KWHs generated and purchased.

For year-to-date 2012, total fuel and purchased power expenses were $229.0 million compared to $269.8 million for the corresponding period in 2011. Fuel and purchased power expenses decreased $146.9 million due to a 41.8% decrease in the average cost of fuel and a 25.9% decrease in the average cost of purchased power. The decrease was partially offset by a $106.2 million net increase associated with a 41.3% increase in the volume of KWHs generated and purchased.

In the second quarter 2012, fuel expense was $91.6 million compared to $101.2 million for the corresponding period in 2011. The decrease was due to a $74.4 million decrease associated with the cost of fuel, partially offset by a $64.8 million increase associated with the volume of KWHs generated.

For year-to-date 2012, fuel expense was $180.6 million compared to $203.9 million for the corresponding period in 2011. The decrease was due to a $130.0 million decrease associated with the cost of fuel, partially offset by a $106.8 million increase associated with the volume of KWHs generated.

In the second quarter 2012, purchased power expenses were $25.4 million compared to $41.8 million for the corresponding period in 2011. The decrease was due to an $8.9 million decrease associated with the cost of purchased power and a $7.5 million decrease associated with the volume of KWHs purchased.

For year-to-date 2012, purchased power expenses were $48.4 million compared to $65.9 million for the corresponding period in 2011. The decrease was due to a $16.9 million decrease associated with the cost of purchased power and a $0.5 million decrease associated with the volume of KWHs purchased.

139

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$0.2	0.4	$5.8	7.0

In the second quarter 2012, other operations and maintenance expenses were $40.2 million compared to $40.0 million for the corresponding period in 2011. The increase was not material.

For year-to-date 2012, other operations and maintenance expenses were $88.6 million compared to $82.8 million for the corresponding period in 2011. The increase was primarily due to a $4.0 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 $1.1 million increase in transmission cost.

Depreciation and Amortization

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$3.2	10.4	$5.0	8.1

In the second quarter 2012, depreciation and amortization was $34.0 million compared to $30.8 million for the corresponding period in 2011. The increase was primarily due to a $1.3 million increase in depreciation resulting from an increase in plant in service, a $0.9 million increase due to higher depreciation rates from a depreciation study adopted in January 2012, and a $1.0 million increase in depreciation related to asset retirements.

For year-to-date 2012, depreciation and amortization was $65.9 million compared to $60.9 million for the corresponding period in 2011. The increase was primarily due to a $2.6 million increase in depreciation resulting from an increase in plant in service, a $1.7 million increase due to higher depreciation rates from a depreciation study adopted in January 2012, and a $0.6 million increase in depreciation related to asset retirements.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$(3.9)	(21.5)	$(9.0)	(24.6)

In the second quarter 2012, interest expense, net of amounts capitalized was $13.9 million compared to $17.8 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 $1.8 million increase in capitalized interest associated with the construction of the Cleveland County combustion turbine generating plant and the Nacogdoches biomass plant.

For year-to-date 2012, interest expense, net of amounts capitalized was $27.6 million compared to $36.6 million for the corresponding period in 2011. The decrease was primarily due to a $4.4 million expense reduction associated with the refinancing of $575 million in long-term debt in 2011 and a $4.1 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.

140

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes

Second Quarter 2012 vs. Second Quarter 2011		Year-to-Date 2012 vs. Year-to-Date 2011
(change in millions)	(% change)	(change in millions)	(% change)
$5.1	21.3	$(2.3)	(5.1)

In the second quarter 2012, income taxes were $29.3 million compared to $24.2 million for the corresponding period in 2011. The increase was primarily due to a $2.9 million increase associated with higher pre-tax earnings, a $1.2 million increase related to a decrease in investment tax credits (ITCs) recognized associated with the construction of the Nacogdoches biomass plant, and a $1.2 million increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid.

For year-to-date 2012, income taxes were $42.7 million compared to $45.0 million for the corresponding period in 2011. The decrease was primarily due to a $3.4 million decrease associated with lower pre-tax earnings and a $2.2 million decrease due to the conclusion of prior year IRS audits, partially offset by a $2.5 million increase related to a decrease in ITCs recognized associated with the construction of the Nacogdoches biomass plant and a $1.2 million increase in Alabama state income taxes due to a decrease in the state income tax deduction for federal income taxes paid.

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.

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.

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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 in May 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.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Southern Power in Item 7 of the Form 10-K for additional information on the proposed rules regarding certain cooling water intake structures. The EPA has entered into an amended settlement agreement to extend the deadline for issuing a final rule until June 27, 2013. The ultimate outcome of this rulemaking will depend on the final rule and the outcome of any legal challenges and cannot be determined at this time.

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.

On June 26, 2012, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit unanimously rejected all challenges to four of the EPA’s actions relating to the greenhouse gas permitting programs under the Clean Air Act. These rules may impact the amount of time it takes to obtain prevention of significant deterioration permits for new generation and major modifications to existing generating units and the requirements ultimately imposed by those permits. The ultimate impact of these rules cannot be determined at this time and will depend on the outcome of any other legal challenges.

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 $145 million and $190 million in 2012.

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Acquisitions

Apex Nevada Solar, LLC Acquisition

On June 29, 2012, Southern Power and Turner Renewable Energy, Inc. (TRE), through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Apex Nevada Solar, LLC (Apex) from Sun Edison, LLC, the original developer of the project. Apex constructed and owns a 20-MW solar photovoltaic facility in North Las Vegas, Nevada. Commercial operation of the solar facility was declared by Apex on July 21, 2012. The output of the plant is contracted under a PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that began in 2012 and expires in 2037. See Note (I) to the Condensed Financial Statements herein for additional information.

Construction Projects

Cleveland County Units 1-4

In 2008, Southern Power announced plans to 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 June 30, 2012 were $292.5 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 constructed a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant is fueled from wood waste. The plant began commercial operation on June 22, 2012. Project costs incurred through June 30, 2012 were $456.5 million. The final cost of the project is expected to be between $465 million and $470 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.

On June 29, 2012, a subsidiary of Southern Power assumed the PPA with Nevada Power Company in connection with the acquisition of Apex. Commercial operation was declared by Apex on July 21, 2012.

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

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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 in Note (B) herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power’s financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power’s financial condition remained stable at June 30, 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 $128.7 million for the first six months of 2012 compared to $193.3 million for the corresponding period in 2011. The decrease was primarily due to cash received in 2011 for convertible ITCs. Net cash used for investing activities totaled $191.7 million for the first six months of 2012 compared to $204.3 million for the corresponding period in 2011. The decrease was primarily due to a decrease in CWIP expenditures related to construction activities at the Cleveland County and Nacogdoches facilities, partially offset by the acquisition of Apex. Net cash provided from financing activities totaled $49.8 million for the first six months of 2012 compared to $3.1 million for the corresponding period in 2011. The increase was primarily due to an increase in notes payable in 2012 and the repayment of a $65.9 million affiliate loan in 2011, partially offset by lower capital contributions from Southern Company due to contributions received in 2011 to fund construction activities.

Significant asset changes in the balance sheet for the first six months of 2012 include: a $15.1 million increase in accounts receivables from non-affiliated companies and a $16.3 million increase in accounts receivables from affiliated companies primarily due to the seasonality in PPAs; a $38.5 million increase in prepaid income taxes; and a $117.3 million increase in total property, plant, and equipment primarily due to the acquisition of Apex.

Significant liability and stockholder’s equity changes in the balance sheet for the first six months of 2012 include a $109.7 million increase in notes payable non-affiliated primarily due to the acquisition of Apex and a $63.0 million increase in accumulated deferred income taxes primarily due to bonus depreciation.

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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 June 30, 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 June 30, 2012 cash and cash equivalents of approximately $3.8 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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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)
June 30, 2012:
Commercial paper	$	287		0.5	%	$	205		0.5	%	$	287

(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 Facility, and cash. In addition, $2.6 million in anticipated prepayment of notes payable to TRE has been reclassified as short-term debt.

Credit Rating Risk

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

The maximum potential collateral requirements under these contracts at June 30, 2012 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$       9
At BBB- and/or Baa3	451
Below BBB- and/or Baa3	1,307

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

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

Market Price Risk

Southern Power is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power’s policies in areas such as counterparty exposure and risk management practices. Southern Power’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk

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management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis.

Southern Power’s market risk exposure relative to interest rate changes for the second quarter 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 and six months ended June 30, 2012 were as follows:

	Second Quarter 2012 Changes		Year-to-Date 2012 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(16.1)	$	(9.2)
Contracts realized or settled		8.4		9.2
Current period changes(a)		2.0		(5.7)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(5.7)	$	(5.7)

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

The changes in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2012 were an increase of $10.4 million and $3.5 million, respectively, which are due to both power and natural gas positions. The changes are attributable to both the volume and prices of power and natural gas as follows:

	June 30, 2012	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	18.3	28.2	8.3
Commodity — weighted average contract cost per mmBtu above (below) market prices (in dollars)	$0.83	$ 1.57	$ 1.18

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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	June 30, 2012		December 31, 2011
	(in millions)
Cash flow hedges		$  (1.1)		$  (0.8)
Not designated		(4.6)		(8.4)
Total fair value		$  (5.7)		$  (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 and six months ended June 30, 2012 for energy-related derivative contracts that were not hedges were $10.3 million and $3.8 million, respectively, and will continue to be marked to market until the settlement date. Included in these amounts are gains (losses) on derivative contracts payable to third parties in the amounts of $9.0 million and $3.8 million, respectively. For the three and six months ended June 30, 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 $(0.9) million and $(0.8) million, respectively.

Southern Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2012 were as follows:

			June 30, 2012 Fair Value Measurements
	Total		Maturity
	Fair Value		Year 1		Years 2&3		Years 4&5
	(in millions)
Level 1	$	—	$	—	$	—	$	—
Level 2		(5.7)		(6.2)		0.1		0.4
Level 3		—		—		—		—
Fair value of contracts outstanding at end of period	$	(5.7)	$	(6.2)	$	0.1	$	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 will impose additional requirements on the use of over-the-counter derivatives for both Southern Power and its derivative counterparties, which could affect both the use and cost of over-the-counter derivatives. Although all relevant regulations have not been finalized, Southern Power does not expect the impact of these rules to be material.

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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Financing Activities

In June 2012, Southern Power issued a $3.6 million promissory note, due June 15, 2032, to TRE related to the financing of Apex.

During the six months ended June 30, 2012, Southern Power prepaid $0.6 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

INDEX TO APPLICABLE NOTES TO

FINANCIAL STATEMENTS BY REGISTRANT

Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, J
Alabama Power	A, B, C, E, F, G, H
Georgia Power	A, B, C, E, F, G, H
Gulf Power	A, B, C, E, F, G, H
Mississippi Power	A, B, C, E, F, G, H
Southern Power	A, B, C, E, G, H, I

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(A) INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 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 June 30, 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. Current projections indicate significant uncertainty as to whether the lessee will be able to pay the December 2012 semi-annual rent payment in full. 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 believes there is a reasonable possibility that it will be able to reach an agreement with the lessee and the debtholders to restructure the project. However, due to continued poor performance of the generation assets and the uncertainties surrounding the receipt of the December 2012 semi-annual rent payment and its ability to successfully restructure the project, Southern Company has placed the lease on nonaccrual status whereby income associated with this investment will not be recognized in the financial statements beginning in July 2012. 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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.

Insurance Recovery

Mirant Corporation (Mirant) was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and other countries. Mirant was a wholly-owned subsidiary of Southern Company until its initial public offering in 2000. In 2001, Southern Company completed a spin-off to its stockholders of its remaining ownership, and Mirant became an independent corporate entity.

In 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In 2005, Mirant, as a debtor in possession, and the unsecured creditors’ committee filed a complaint against Southern Company. Later in 2005, this complaint was transferred to MC Asset Recovery, LLC (MC Asset Recovery) as part of Mirant’s plan of reorganization. In 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve this action. The settlement included an agreement where Southern Company paid MC Asset Recovery $202 million. Southern Company filed an insurance claim in 2009 to recover a portion of this settlement and received a nontaxable $25 million payment from its insurance provider on June 14, 2012. Additionally, legal fees related to this insurance settlement totaled approximately $6 million. The net reduction to expense for this insurance settlement was approximately $19 million.

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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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. In March 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). 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. In May 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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 June 30, 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. In September 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, in November 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. In November 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 June 30, 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. The feasibility study/presumptive remedy document was originally filed with TCEQ in 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, in March 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. In July 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 were received and credited to the Georgia Power accounts where the original costs were charged and were 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 June 30, 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 has begun and is expected to be operational 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

FERC Matters

See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K 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 2012. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power

Rate CNP

See Note 3 to the financial statements of Southern Company and Alabama Power under “Retail Regulatory Matters  — Alabama Power — Rate CNP” and “Retail Regulatory Matters — Rate CNP,” respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power’s recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power’s under recovered Rate CNP balance as of June 30, 2012 was $2 million as compared to $6 million at December 31, 2011. Alabama Power’s under recovered Rate CNP Environmental balance as of June 30, 2012 was $26 million as compared to $11 million at December 31, 2011. These under recovered balances at June 30, 2012 are included in deferred under recovered regulatory clause revenues on Southern Company’s and Alabama Power’s Condensed Balance Sheets herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.

Natural Disaster Cost Recovery

See Note 3 to the financial statements of Southern Company and Alabama Power under “Retail Regulatory Matters  — Alabama Power — Natural Disaster Reserve” and “Retail Regulatory Matters — Natural Disaster Reserve,” respectively, in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2012, the NDR had an accumulated balance of $105 million, which is included in Southern Company’s and Alabama Power’s Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Southern Company’s and Alabama Power’s Condensed Statements of Income herein.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Georgia Power

Fuel Cost Recovery

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

On June 21, 2012, the Georgia PSC approved a decrease in Georgia Power’s fuel cost recovery rates of 19%, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.

As of June 30, 2012, Georgia Power had a total over recovered fuel cost balance of approximately $99 million compared to an under recovered balance of $137 million at December 31, 2011. The over recovered fuel costs at June 30, 2012 are included in other current liabilities and 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.

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. On July 11, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitioners’ motion to stay the effectiveness of the COLs. Georgia Power has intervened in and intends to vigorously contest these petitions.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 June 30, 2012, approximately $64 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, Contractor) 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 Contractor 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. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and Georgia Power (on behalf of the Owners) are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate to 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 by the NRC. The Owners and the Contractor have begun negotiations regarding these issues, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Through correspondence sent to the Owners, the Contractor has provided its proposed adjustment to the contract price and has initiated the formal dispute resolution process. The Contractor’s estimated adjustment attributable to Georgia Power (based on Georgia Power’s ownership interest regarding these issues) is approximately $425 million (in 2008 dollars) with respect to these issues. 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. While the formal dispute resolution process has been initiated, Georgia Power expects negotiations with the Contractor to continue over the next several months with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Georgia Power intends to vigorously defend its positions. If these costs ultimately are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. In connection with these negotiations, the Owners are evaluating whether maintaining the currently scheduled commercial operation dates of 2016 and 2017 remains in the best interest of their customers. Additional claims by the Contractor 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. During a routine inspection in April 2012, the NRC identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. In May 2012, Southern Nuclear received an official notice of violation relating to these findings from the NRC. The design changes were determined to have minimal safety significance and, on August 1, 2012, Southern Nuclear filed a license amendment request with the NRC to clarify that the nuclear island concrete and rebar construction will conform to NRC requirements. Various inspection and other issues are expected to arise from time to time as construction proceeds, which may result in additional license amendments or require other resolution.

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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.

Plant McDonough Unit 1 was retired on February 29, 2012. Georgia Power placed Plant McDonough-Atkinson Unit 5 into service on April 26, 2012. Plant McDonough-Atkinson Unit 6 is scheduled to be placed into service in November 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. On July 17, 2012, the Florida PSC denied Gulf Power’s motion and reaffirmed its earlier decision.

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.

On June 19, 2012, the Florida PSC approved a decrease in Gulf Power’s fuel rates of 7.8%, which will reduce annual billings by approximately $58.8 million effective July 2, 2012.

Over recovered fuel costs at June 30, 2012 totaled $41.6 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 June 30, 2012 totaled $7.9 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.

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. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015. Gulf Power’s portion of the cost is expected to be recovered through the environmental cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.

Over recovered environmental costs at June 30, 2012 totaled $3.6 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.

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 June 30, 2012 totaled $1.6 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. An order granting the suspension of the 2011 PEP lookback was signed by the Mississippi PSC on May 8, 2012. The ultimate outcome of these matters cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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 February 14, 2012, Mississippi Power submitted its 2012 ECO Plan filing, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct a scrubber on Plant Daniel Units 1 and 2, Mississippi Power revised the 2012 ECO Plan filing to exclude scrubber expenditures from rate base, which resulted in a 0.16% decrease in annual revenues. On June 22, 2012, the 2012 ECO Plan filing, including the proposed rate decrease, was approved by the Mississippi PSC, effective on June 29, 2012.

On April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power’s portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power’s portion of the cost is expected to be recovered through the ECO Plan. As of June 30, 2012, total project expenditures were $82.0 million, with Mississippi Power’s portion being $41.0 million. The ultimate outcome of this matter cannot be determined at this time.

Certificated New Plant

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 and “Integrated Coal Gasification Combined Cycle” herein for additional information.

On May 23, 2012, the Mississippi Public Utilities Staff signed a joint stipulation with Mississippi Power to establish a new rate schedule for Certificated New Plant-A (CNP-A), a proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. An amended and restated stipulation was subsequently executed and filed on June 1, 2012. On June 14, 2012, Mississippi Power submitted to the Mississippi PSC a proposed supplemental compliance filing to establish the new CNP-A rate schedule and a stipulated rate increase based upon the revenue request of between $55.3 million and $58.6 million to recover financing costs over the remainder of 2012.

On June 22, 2012, the Mississippi PSC denied the proposed CNP-A rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSC’s issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSC’s June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million while the Mississippi Supreme Court decides Mississippi Power’s appeal of the Mississippi PSC’s June 22, 2012 decision. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Power’s request for interim rates under bond. The ultimate outcome of this matter cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery.

At June 30, 2012, the amount of over recovered retail fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $55.5 million compared to $42.4 million at December 31, 2011. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At June 30, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $17.4 million and $2.4 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at June 30, 2012 and December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Power’s Condensed Balance Sheets herein was $1.0 million and $1.7 million, respectively. 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, any changes in the billing factors will not have a significant effect on Mississippi Power’s revenues or net income, but will affect 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. 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. In February 2011, the Chancery Court issued a judgment affirming the 2010 MPSC Order and, in March 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. 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 18, 2012, Mississippi Power’s motion to join the appeal was approved.

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 and certain general exceptions, including change of law, force majeure, and beneficial capital), (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

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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 Kemper IGCC). The current cost estimate of the Kemper IGCC is $2.88 billion, including a $72 million contingency.

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, 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 Kemper IGCC 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 has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site in Kemper County. The estimated capital cost of the mine is approximately $245 million, of which $99.9 million has been incurred through June 30, 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. Due to the fact that Liberty Fuels conducts all of its activities on behalf of Mississippi Power, Liberty Fuels qualifies as a variable interest entity for which Mississippi Power is the primary beneficiary. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Consistent with the requirements of consolidation accounting, Liberty Fuels is consolidated in the financial statements of Mississippi Power and accordingly the asset retirement cost and the ARO have been recorded in Mississippi Power’s financial statements. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

In December 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. In April 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 June 30, 2012, Mississippi Power received or accrued tax benefits totaling $197 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. Based on current tax laws and regulations in effect, Mississippi Power expects to receive substantially all of the tax credits accrued through June 30, 2012 by June 30, 2013.

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. 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 June 29, 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012 and reduced its purchase

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC, subject to approval by the Mississippi PSC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.

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 is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody’s or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA’s ability to request a refund, the deposit has been presented as a current liability in Mississippi Power’s Condensed Balance Sheet herein and as financing proceeds in Mississippi Power’s Condensed Statement of Cash Flows herein.

As of June 30, 2012, Mississippi Power had spent a total of $1.7 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, $1.6 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $29.0 million was recorded in other regulatory assets, $2.6 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 and “Retail Regulatory Matters – Certificated New Plant” herein 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 June 30, 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 June 30, 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		—		12		—		12
Nuclear decommissioning trusts(a)		450		784		—		1,234
Cash equivalents and restricted cash		512		—		—		512
Other investments		1		53		15		69
Total	$	963	$	873	$	15	$	1,851
Liabilities:
Energy-related derivatives	$	—	$	194	$	—	$	194
Interest rate derivatives		—		28		—		28
Foreign currency derivatives		—		2		—		2
Total	$	—	$	224	$	—	$	224
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Nuclear decommissioning trusts:(b)
Domestic equity		274		60		—		334
Foreign equity(d)		25		49		—		74
U.S. Treasury and government agency securities		—		23		—		23
Corporate bonds		—		101		—		101
Mortgage and asset backed securities		—		25		—		25
Other		—		12		—		12
Total	$	299	$	273	$	—	$	572
Liabilities:
Energy-related derivatives	$	—	$	35	$	—	$	35
Interest rate derivatives		—		28		—		28
Total	$	—	$	63	$	—	$	63

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Fair Value Measurements Using
As of June 30, 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	$	—	$	17	$	—	$	17
Nuclear decommissioning trusts:(b) (c)
Domestic equity		151		1		—		152
Foreign equity(d)		—		102		—		102
U.S. Treasury and government agency securities		—		45		—		45
Municipal bonds		—		103		—		103
Corporate bonds		—		120		—		120
Mortgage and asset backed securities		—		118		—		118
Other		—		24		—		24
Cash equivalents		149		—		—		149
Total	$	300	$	530	$	—	$	830
Liabilities:
Energy-related derivatives	$	—	$	75	$	—	$	75
Gulf Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents		15		—		—		15
Total	$	15	$	2	$	—	$	17
Liabilities:
Energy-related derivatives	$	—	$	39	$	—	$	39
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents		146		—		—		146
Total	$	146	$	1	$	—	$	147
Liabilities:
Energy-related derivatives	$	—	$	38	$	—	$	38
Foreign currency derivatives		—		2		—		2
Total	$	—	$	40	$	—	$	40
Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	7

(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 payables related to the securities lending program. As of June 30, 2012, approximately $38 million of the fair market value of Georgia Power’s nuclear decommissioning trust funds’ securities were on loan and pledged to creditors under the funds’ managers’ securities lending program.

(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 June 30, 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 June 30, 2012:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	8	None	Daily	1 to 3 days
Other — commingled funds		73	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		91	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		512	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Other — commingled funds		49	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		91	None	Daily	15 days
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds		8	None	Daily	1 to 3 days
Other — commingled funds		24	None	Daily	Not applicable
Cash equivalents:
Money market funds		149	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds		15	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds		146	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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three and six months ended June 30, 2012, the change in fair value of the funds, which includes reinvested interest and dividends and excludes the Funds’ expenses, is recorded in the regulatory liability and was a decrease of $22 million and an increase of $64 million, respectively, for Southern Company, a decrease of $16 million and an increase of $33 million, respectively, for Alabama Power, and a decrease of $6 million and an increase of $31 million, respectively, 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 June 30, 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	$21,451	$23,477
Alabama Power	$  6,130	$  6,893
Georgia Power	$  9,856	$10,703
Gulf Power	$  1,246	$  1,384
Mississippi Power	$  1,576	$  1,690
Southern Power	$  1,306	$  1,416

The fair values are primarily 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 June 30, 2012	Three Months Ended June 30, 2011	Six Months Ended June 30, 2012	Six Months Ended June 30, 2011
	(in millions)
As reported shares	872	855	870	851
Effect of options and performance share award units	8	7	9	7
Diluted shares	880	862	879	858

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for both the three months and six months ended June 30, 2012 and 2011.

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	—	—	991	—	991
Other comprehensive income (loss)	—	—	(1)	—	(1)
Stock issued	9,697	—	395	—	395
Cash dividends on common stock	—	—	(837)	—	(837)
Other	—	(26)	(2)	—	(2)
Balance at June 30, 2012	875,361	(565)	$18,124	$707	$18,831
Balance at December 31, 2010	843,814	(474)	$16,202	$707	$16,909
Net income after dividends on preferred and preference stock	—	—	1,026	—	1,026
Other comprehensive income (loss)	—	—	8	—	8
Stock issued	14,337	—	533	—	533
Cash dividends on common stock	—	—	(787)	—	(787)
Other	—	(25)	—	—	—
Balance at June 30, 2011	858,151	(499)	$16,982	$707	$17,689

(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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The following table outlines the credit arrangements by company as of June 30, 2012, including expiration dates:

	Expires					Executable Term Loans		Due Within  One Year(a)
Company	2012	2013	2014 and Beyond(b)	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	37	101	1,150	1,288	1,288	51	—	51	52
Georgia Power	—	—	1,750	1,750	1,745	—	—	—	—
Gulf Power	20	60	195	275	275	45	—	45	35
Mississippi Power	41	95	165	301	301	25	41	66	70
Southern Power	—	—	500	500	500	—	—	—	—
Other	—	50	—	50	50	25	—	25	—
Total	$98	$306	$4,760	$5,164	$5,159	$146	$  41	$187	$157

(a) Reflects facilities expiring on or before June 30, 2013.

(b) All remaining Gulf Power and Mississippi Power credit agreements in this column expire in 2014.

(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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Components of the net periodic benefit costs for the three and six months ended June 30, 2012 and 2011 were as follows:

Pension Plans	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended June 30, 2012
Service cost	$   49	$ 11	$ 15	$   3	$ 3
Interest cost	99	24	36	4	4
Expected return on plan assets	(146)	(41)	(55)	(7)	(6)
Net amortization	31	7	11	2	1
Net cost (income)	$   33	$   1	$7	$   2	$ 2
Six Months Ended June 30, 2012
Service cost	$   99	$ 22	$ 30	$   5	$  5
Interest cost	197	47	71	8	9
Expected return on plan assets	(291)	(81)	(110)	(13)	(12)
Net amortization	62	15	22	3	2
Net cost (income)	$  67	$   3	$ 13	$   3	$  4
Three Months Ended June 30, 2011
Service cost	$   46	$ 10	$ 15	$  2	$  2
Interest cost	97	24	36	5	5
Expected return on plan assets	(152)	(43)	(58)	(7)	(6)
Net amortization	13	4	4	—	—
Net cost (income)	$    4	$  (5)	$ (3)	$—	$  1
Six Months Ended June 30, 2011
Service cost	$    92	$  21	$  29	$  4	$  4
Interest cost	195	48	72	9	9
Expected return on plan assets	(304)	(86)	(117)	(14)	(12)
Net amortization	26	7	9	1	1
Net cost (income)	$     9	$ (10)	$  (7)	$ —	$  2

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Postretirement Benefits	Southern Company				Alabama Power				Georgia Power				Gulf Power				Mississippi Power
	(in millions)
Three Months Ended June 30, 2012
Service cost		$	6			$	2			$	2			$	1			$	1
Interest cost			21				6				10				1				1
Expected return on plan assets			(15	)			(6	)			(7	)			(1	)			(1	)
Net amortization			5				1				2				—				—
Net cost (income)		$	17			$	3			$	7			$	1			$	1
Six Months Ended June 30, 2012
Service cost		$	11			$	3			$	3			$	1			$	1
Interest cost			42				11				19				2				2
Expected return on plan assets			(30	)			(12	)			(14	)			(1	)			(1	)
Net amortization			10				3				5				—				—
Net cost (income)		$	33			$	5			$	13			$	2			$	2
Three Months Ended June 30, 2011
Service cost		$	5			$	2			$	2			$	1			$	1
Interest cost			23				6				10				1				1
Expected return on plan assets			(16	)			(7	)			(7	)			(1	)			(1	)
Net amortization			5				1				2				—				—
Net cost (income)		$	17			$	2			$	7			$	1			$	1
Six Months Ended June 30, 2011
Service cost		$	10			$	3			$	4			$	1			$	1
Interest cost			46				12				20				2				2
Expected return on plan assets			(32	)			(13	)			(15	)			(1	)			(1	)
Net amortization			10				3				5				—				—
Net cost (income)		$	34			$	5			$	14			$	2			$	2

173

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(G) EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

Effective Tax Rate

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for information on the effective income tax rate.

Southern Company

Southern Company’s effective tax rate is typically lower than the statutory rate due to its employee stock plans’ dividend deduction and non-taxable AFUDC equity.

Southern Company’s effective tax rate was 34.1% for the six months ended June 30, 2012 compared to 35.4% for the corresponding period in 2011. The decrease was primarily related to state income tax credits. See “Unrecognized Tax Benefits” herein for additional information.

Alabama Power

Alabama Power’s effective tax rate was 38.9% for the six months ended June 30, 2012 compared to 38.5% 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 34.2% for the six months ended June 30, 2012 compared to 34.8% for the corresponding period in 2011. The decrease was primarily related to state income tax credits, partially offset by a decrease in non-taxable AFUDC equity. See “Unrecognized Tax Benefits” herein for additional information.

Gulf Power

Gulf Power’s effective tax rate was 36.6% for the six months ended June 30, 2012 compared to 35.9% for the corresponding period in 2011. The increase was primarily due to a decrease in non-taxable AFUDC equity.

Mississippi Power

Mississippi Power’s effective tax rate was 25.2% for the six months ended June 30, 2012 compared to 32.6% for the corresponding period in 2011. The decrease was primarily due to an increase in non-taxable AFUDC equity related to the Kemper IGCC construction.

Southern Power

Southern Power’s effective tax rate was 35.9% for the six months ended June 30, 2012 compared to 35.3% for the corresponding period in 2011. The increase was due to less tax benefits from convertible investment tax credits associated with qualifying construction activity.

174

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		4			2			2			1			—			—
Tax positions from prior periods		(23	)		(3	)		(19	)		(1	)		(1	)		(2	)
Reductions due to settlements		(5	)		(2	)		(4	)		(1	)		—			1
Reductions due to expired statute of limitations		(3	)		—			(3	)		—			—			—
Balance as of June 30, 2012	$	93		$	29		$	23		$	2		$	4		$	2

The tax positions from current periods relate primarily to state income 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 primarily relate to state income tax credits. The 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 June 30, 2012						As of December 31, 2011
	Georgia Power		Other Registrants		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	3	$	4	$	38	$	69
Tax positions not impacting the effective tax rate		20		33		55		51
Balance of unrecognized tax benefits	$	23	$	37	$	93	$	120

The tax positions impacting the effective tax rate primarily relate to state income 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		(6	)		(2	)		(9	)
Interest accrued during the period		—			—			—
Balance as of June 30, 2012	$	—		$	1		$	1

All of the registrants classify interest on tax uncertainties as interest expense. The interest reclassified due to settlements is primarily associated with state income tax credits and 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.

175

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. In August 2011, the IRS issued a revenue procedure, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. 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. In December 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 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.

176

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Energy-related derivative contracts are accounted for in one of three methods:

• Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies’ fuel hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

• Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges, which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions, are reflected in earnings.

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

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

At June 30, 2012, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu		Longest Hedge Date		Longest Non-Hedge Date
	(in millions)
Southern Company		242		2017		2017
Alabama Power		43		2017		—
Georgia Power		96		2017		—
Gulf Power		51		2017		—
Mississippi Power		34		2017		—
Southern Power		18		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 8 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 3 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 1 million mmBtu for Mississippi Power, and 2 million mmBtu for Southern Power.

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending June 30, 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.

177

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At June 30, 2012, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received		Interest Rate Paid		Hedge Maturity Date		Fair Value Gain (Loss) June 30, 2012
	(in millions)								(in millions)
Cash flow hedges of forecasted transactions
Alabama Power	$	300		3-month LIBOR		2.90%(a)		December 2022	$(28)
Fair value hedges of existing debt
Southern Company		350		4.15%		3-month LIBOR  + 1.96%(a)		May 2014	12
Total	$	650							$(16)

(a) 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 June 30, 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 June 30, 2013	Total Deferred Gains (Losses) Amortized Through
	(in millions)
Southern Company	$(17)	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.

178

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At June 30, 2012, the following foreign currency derivatives were outstanding:

	Notional Amount	Forward Rate	Hedge Maturity Date	Fair Value Gain (Loss) June 30, 2012
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR6.3	1.3850 Dollars per Euro(a)	Various through March 2014	$(1)
Derivatives not designated as hedges
Mississippi Power	EUR18.1	1.3186 Dollars per Euro(a)	N/A	(1)
Total	EUR24.4			$(2)

(a) Weighted Average

Derivative Financial Statement Presentation and Amounts

At June 30, 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 June 30, 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	$	14	$	1	$	13	$	—	$	—
Other deferred charges and assets		9		2		4		2		1
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	3	$	17	$	2	$	1		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		6		—		—		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	12	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	$	1	$	—	$	—	$	—	$	—	$	1
Total asset derivatives	$	36	$	3	$	17	$	2	$	1	$	1

179

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Liability Derivatives at June 30, 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	$123	$26	$  52	$20	$25
Other deferred credits and liabilities	64	9	23	19	13
Total derivatives designated as hedging instruments for regulatory purposes	$187	$35	$75	$39	$38	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities	$    1	$—	$  —	$  —	$  —	$1
Interest rate derivatives:
Liabilities from risk management activities	28	28	—	—	—	—
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$  30	$28	$—	$—	$1	$1
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$    6	$—	$  —	$—	$—	$6
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$    7	$—	$  —	$  —	$  1	$6
Total liability derivatives	$224	$63	$75	$39	$40	$7

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

At June 30, 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		$(123)		$(26)		$(52)		$(20)		$(25)
Other regulatory assets, deferred		(64)		(9)		(23)		(19)		(13)
Other regulatory liabilities, current		14		1		13		—		—
Other regulatory liabilities, deferred		9		2		—		2		1
Other deferred credits and liabilities(a)		—		—		4		—		—
Total energy-related derivative gains (losses)		$(164)		$(32)		$(58)		$(37)		$(37)

(a) Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

180

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three and six months ended June 30, 2012 and June 30, 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 and six months ended June 30, 2012 and June 30, 2011, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were immaterial and were offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there was no impact on Southern Company’s or Mississippi Power’s statements of income.

For the three months ended June 30, 2012 and 2011, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

Derivatives in Cash Flow	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
Interest rate derivatives	$    (18)	$    —	Interest expense, net of amounts capitalized	$            (4)	$            (1)
Alabama Power
Interest rate derivatives	$    (18)	$    —	Interest expense, net of amounts capitalized	$            —	$      3
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (1)	$            (1)
Southern Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (3)	$            (3)

181

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the six months ended June 30, 2012 and 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 Hedging	Gain (Loss) Recognized in OCI on Derivative		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Relationships	(Effective Portion)		Statements of Income Location	Amount
	2012	2011		2012	2011
	(in millions)			(in millions)
Southern Company
Energy-related derivatives	$    —	$       1	Fuel	$            —	$            —
Interest rate derivatives	(12)	4	Interest expense, net of amounts capitalized	(7)	(6)
Total	$    (12)	$         5		$            (7)	$            (6)
Alabama Power
Interest rate derivatives	$    (11)	$         4	Interest expense, net of amounts capitalized	$          —	$            3
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (2)	$            (2)
Mississippi Power
Interest rate derivatives	$    (1)	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Southern Power
Energy-related derivatives	$    —	$       1	Fuel	$            —	$            —
Interest rate derivatives	—	—	Interest expense, net of amounts capitalized	(5)	(6)
Total	$    —	$       1		$            (5)	$            (6)

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

For the three and six months ended June 30, 2012, the net unrealized pre-tax gains from energy-related derivatives not designated as hedging instruments on Southern Company’s and Southern Power’s statements of income were $10 million and $4 million, respectively. For the three and six months ended June 30, 2011, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.

For the three and six months ended June 30, 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.

182

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 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	$27	$6	$8	$6	$5	$2

At June 30, 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 $27 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.

(I) ACQUISITIONS

Apex Nevada Solar, LLC Acquisition

On June 29, 2012, Southern Power and Turner Renewable Energy, Inc., through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Apex Nevada Solar, LLC (Apex) from Sun Edison, LLC, the original developer of the project. Apex constructed and owns a 20-MW solar photovoltaic facility in North Las Vegas, Nevada. Commercial operation of the solar facility was declared by Apex on July 21, 2012. The output of the plant is contracted under a PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that began in 2012 and expires in 2037. This PPA will be accounted for as an operating lease. The acquisition is in accordance with Southern Power’s overall growth strategy.

Southern Power’s acquisition of Apex included cash consideration of $102 million, of which $86.5 million was paid at closing. The remaining $15.5 million will be paid upon achievement of certain milestones. Due to the proximity of the closing date to June 30, 2012, there has not been sufficient time to complete the final allocation of the purchase price to individual assets. As of June 30, 2012, the entire purchase price is reflected in CWIP on Southern Power’s Condensed Balance Sheet herein.

183

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(J) SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $106 million and $218 million for the three and six months ended June 30, 2012, respectively, and $71 million and $154 million for the three and six months ended June 30, 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 June 30, 2012:
Operating revenues	$	3,989	$	286	$	(109)		$	4,166	$	35	$	(20)	$	4,181
Segment net income (loss)(a)		549		47		—			596		27		—		623
Six Months Ended June 30, 2012:
Operating revenues	$	7,438	$	539	$	(222)		$	7,755	$	73	$	(43)	$	7,785
Segment net income (loss)(a)		888		76		—			964		28		(1)		991
Total assets at June 30, 2012	$	56,726	$	3,785	$	(126)		$	60,385	$	1,132	$	(620)	$	60,897
Three Months Ended June 30, 2011:
Operating revenues	$	4,291	$	305	$	(93)		$	4,503	$	38	$	(20)	$	4,521
Segment net income (loss)(a)		559		44		—			603		1		—		604
Six Months Ended June 30, 2011:
Operating revenues	$	8,101	$	587	$	(191)		$	8,497	$	76	$	(40)	$	8,533
Segment net income (loss)(a)		943		82		—			1,025		2		(1)		1,026
Total assets at December 31, 2011	$	54,622	$	3,581	$	(127	)	$	58,076	$	1,592	$	(401)	$	59,267

(a) 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 June 30, 2012	$	3,597	$	415	$	154	$	4,166
Three Months Ended June 30, 2011		3,842		507		154		4,503
Six Months Ended June 30, 2012	$	6,689	$	764	$	302	$	7,755
Six Months Ended June 30, 2011		7,238		956		303		8,497

184

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

185

Item 6.    Exhibits.

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

Georgia Power

(c)1 - Forty-Seventh Supplemental Indenture to Senior Note Indenture dated as of May 11, 2012, providing for the issuance of the Series 2012B 2.85% Senior Notes due May 15, 2022. (Designated in Form 8-K dated May 8, 2012, File No. 1-6468, as Exhibit 4.2(b).)

Gulf Power

(e)1 - Nineteenth Supplemental Indenture to Senior Note Indenture dated as of May 18, 2012, providing for the issuance of the Series 2012A 3.10% Senior Notes due May 15, 2022. (Designated in Form 8-K dated May 15, 2012, File No. 001-31737, as Exhibit 4.2.)

(10) Material Contracts

Southern Company

(a)1 - Retention and Restricted Stock Unit Award Agreement by and between Southern Company and Charles D. McCrary effective May 22, 2012.

(a)2 - Consulting Agreement by and with Southern Company Services, Inc. and Anthony J. Topazi effective August 1, 2012.

Alabama Power

(a)1 - Retention and Restricted Stock Unit Award Agreement by and between Southern Company and Charles D. McCrary effective May 22, 2012. See Exhibit 10(a)1 herein.

(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.)

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.)

(d)2 - Power of Attorney for S. W. Connally, Jr.

186

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.
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.

187

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.

188

(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

189

THE SOUTHERN COMPANY

SIGNATURES

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

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

Date: August 6, 2012

190

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: August 6, 2012

191

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: August 6, 2012

192

GULF POWER COMPANY

SIGNATURES

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

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

Date: August 6, 2012

193

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: August 6, 2012

194

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: August 6, 2012

195

EX-10

Exhibit 10(a)1

RETENTION AND RESTRICTED STOCK UNIT AWARD AGREEMENT

THIS RETENTION AND RESTRICTED STOCK UNIT AWARD AGREEMENT (the "Agreement"), made and entered into by and between THE SOUTHERN COMPANY (the “Company”) and CHARLES D. MCCRARY ("Employee"), shall be effective as of May 22, 2012 (the "Effective Date").

W I T N E S S E T H:

WHEREAS, the Compensation and Management Succession Committee of the Company Board of Directors (the “Compensation Committee”) has approved the Agreement in order to encourage Employee to continue employment with an affiliate of the Company for a specified term and to provide Employee with a retention award for service he will provide to the Company and its affiliates; and

WHEREAS, the Agreement is an Award made by the Compensation Committee under the Southern Company Omnibus Incentive Compensation Plan (the "Omnibus Plan").

NOW, THEREFORE, in consideration of the premises, and the agreement of the parties set forth in the Agreement, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows:

1.           Retention Award.   Employee is awarded under the Agreement the number of Restricted Stock Units valued at Two Million Dollars and No Cents ($2,000,000.00) at the closing Common Stock price on the effective date of the Agreement and shall become vested  in the Award provided Employee is actively employed with an affiliate of the Company on December 31, 2014 (the “Vesting Date”).

The award under this Paragraph 1 shall be treated as an award of Restricted Stock Units under the terms of the Omnibus Plan, and therefore governed by the terms of that plan.  The deemed dividends associated with the Restricted Stock Units shall be credited and treated as reinvested in additional Restricted Stock Units until the award is vested and paid in accordance with Paragraph 2.

2.           Timing and Form of Payment of Retention Amount.

(a)           Generally.  Unless modified by the provisions set forth in Paragraphs 2(b)-2(f),

the vested amount shall be paid in shares of Common Stock to Employee in a lump sum within 30 days following the Vesting Date (the "Scheduled Payment Date").

(b)           Death.  If Employee dies while in active service prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the retention award set forth in Paragraph 1.  The amount vested under this Paragraph 2(b) shall be paid on the earlier of (i) the Scheduled Payment Date or (ii) within 30 days

1

following the Employee's date of death.  Employee shall designate his beneficiary(ies) in the beneficiary designation form set forth in Exhibit 1 to the Agreement.

(c)           Disability.  If Employee separates from service on account of becoming totally disabled as defined under the Company's long term disability plan prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the retention award set forth in Paragraph 1.  The amount vested under this Paragraph 2(c) shall be paid on the earlier of (i) the Scheduled Payment Date or (ii) within 30 days following the date Employee separates from service on account of disability.

(d)             Involuntary Termination.  If Employee separates from service on account of being involuntarily terminated for reasons other than Cause prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the retention award set forth in Paragraph 1.  The amount vested under this Paragraph 2(d) shall be paid on the earlier of (i) the Scheduled Payment Date or (ii) within 30 days following the date the Employee separates from service.

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

               (1)      Failure to Discharge Duties.  Employee willfully neglects or refuses to discharge his duties hereunder or refuses to comply with any lawful or reasonable instructions given to him by the Company without reasonable excuse;

              (2)  Breach.  Employee commits any material breach or repeats or continues (after written warning) any breach of his obligations hereunder;

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

                           (i)           Any act involving fraud or dishonesty or breach of appropriate regulations of competent authorities in relation to trading or dealing with stocks, securities, investments and the like;

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

2

              (iii)          Attendance at a Company worksite in a state of intoxication or otherwise being found in possession on Company or any of its affiliates' property of any prohibited drug or substance, possession of which would amount to a criminal offense;

                          (iv)         Assault or other act of violence against any employee of the Company or other person during the course of his employment; or

                          (v)           Conviction of any felony or misdemeanor involving moral turpitude.

(f)           Delaying Payment. Notwithstanding the foregoing, if Employee is a “specified employee” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”) as of the date of his separation from service, then payment of any amounts under the Agreement shall be deferred for six months after the date of his separation from service to the extent required by Section 409A of the Code.

3.Amendment and/or Termination of the Agreement. The Agreement terminates when all amounts have been paid or forfeited pursuant to Paragraph 2.  Notwithstanding the preceding sentence, the Employee and the Company may mutually agree to amend or terminate the Agreement prior to the Vesting Date only by written agreement signed by each party.

4.           Confidentiality. Employee represents and agrees that he will keep all terms and provisions of the Agreement completely confidential, except for possible disclosures to his legal and financial advisors and his spouse or to the extent required by law, and Employee further agrees that he will not disclose the terms, provisions or information contained in or concerning the Agreement to anyone other than those persons named above, including, but not limited to, any past, present or prospective employee or applicant for employment with the Company or any affiliate of the Company.  The Agreement is not intended in any way to proscribe Employee's right and ability to provide information to any federal, state or local government in the lawful exercise of such governments' governmental functions.

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

6.           Unsecured General Creditor.  The Company shall neither reserve nor specifically set aside funds for the payment of its obligations under the Agreement, and such obligations shall be paid solely from the general assets of the Company.  Notwithstanding that Employee may be entitled to receive payments under the terms and conditions of the Agreement, the assets from which such amounts may be paid shall at all times be subject to the claims

3

of the Company's creditors.

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

8.           Tax Withholding and Implications.  To the extent permitted under Section 409A of the Code, there shall be deducted from the vested retention amount the number of shares of Common Stock necessary to cover the amount of any tax required by any governmental authority to be withheld from the Employee and paid over by the Company  or an affiliate of the Company to such governmental authority for the account of the Employee.  The Company makes no representations or guarantees regarding the tax implications of the Agreement and advises Employee to consult with his attorney and/or tax advisor regarding the tax implications of the Agreement.  In addition, Employee agrees to hold harmless the Company with respect to any tax liability for any and all federal, state or local taxes or assessments, interest or penalties of any kind arising from the Agreement.

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

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

11.           Governing Law.  The Agreement, and all rights under it, shall be governed by and construed in accordance with the laws of the State of Georgia, without giving effect to principles of conflicts of laws.

12.           409A. The parties agree that the terms and provisions of the Agreement will be construed and interpreted to the maximum extent permitted in order to comply with Section 409A of the Code, and the regulations promulgated thereunder.  Neither the Employee nor the Company may accelerate any deferred payment under the Agreement, except in compliance with Section 409A of the Code.

[SIGNATURES ON FOLLOWING PAGE]

4

IN WITNESS WHEREOF, the Agreement has been executed by the parties first listed above, this _6__ day of __June_____2012.

“COMPANY”

THE SOUTHERN COMPANY

By:   /s/Thomas A. Fanning                                          

Its: Chairman, President, and Chief Executive Officer                                                                                        

                                                     “EMPLOYEE”

                                                    CHARLES D. MCCRARY

      /s/Charles D. McCrary                                                               

5

RETENTION AND RESTRICTED STOCK UNIT AWARD AGREEMENT

EXHIBIT 1

BENEFICIARY DESIGNATION

Beneficiary

Name                                    Relationship                                               Percentage

Name                                    Relationship                                               Percentage

In the event that all or some beneficiaries designated above are not living at the time payment

should be made, I designate the following contingent beneficiaries to be paid such amounts:

Contingent Beneficiary

Name                                    Relationship                                               Percentage

Name                                    Relationship                                               Percentage

Any amounts not paid to the contingent beneficiary(ies) shall be paid to the Employee's estate.

6

EX-10

Exhibit 10(a)2

CONSULTING AGREEMENT

THIS CONSULTING AGREEMENT (the “Agreement”) is entered into by and with Southern Company Services, Inc.(the “Company”) and Anthony J. Topazi(“Consultant”).

WITNESSETH

WHEREAS, the Company desires to retain Consultant to provide certain services to the Company, and Consultant desires to provide such services to the Company, all subject to the terms and conditions set forth herein.

NOW THEREFORE, for and in consideration of the premises, the mutual covenants and agreements contained herein, and for other good and valuable consideration, the receipt, sufficiency and adequacy of which are hereby acknowledged, the parties hereby agree as follows:

1.           Engagement as an Independent Consultant.

The Company hereby agrees to engage Consultant as an independent contractor, and Consultant hereby accepts such engagement as an independent contractor, upon the terms and conditions set forth in the Agreement.

2.           Term.

a)          The term of the Agreement shall commence on August 1, 2012 and shall expire on December 31, 2013 (“Term”), unless the Agreement is terminated prior to the expiration of the Term pursuant to Section 2(b) below.

b)          Notwithstanding Section 2(a), the Company may immediately terminate the Agreement at any time for Cause (as defined below).  If the Company terminates the Agreement pursuant to this Section 2(c), Consultant shall be entitled to keep the Retainer Fees under Section 5 hereof which have already been paid and the Company shall have no further obligations under the Agreement.  “Cause” or “Termination for Cause” shall include the following conditions as solely determined by the Company:

1)   Failure to Discharge Duties.  Consultant willfully neglects or refuses to discharge his duties hereunder or refuses to comply with any lawful or reasonable instructions given to his by the Company without reasonable excuse;

2)   Breach.  Consultant commits any material breach or repeats or continues (after written warning) any breach of his obligations hereunder;

- 1 -

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

i.   Any act involving fraud or dishonesty or breach of appropriate regulations of competent authorities in relation to trading or dealing with stocks, securities, investments and the like;

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

iii.   Attendance at a Company worksite in a state of intoxication or otherwise being found in possession on Company property of any prohibited drug or substance, possession of which would amount to a criminal offense;

iv.   Assault or other act of violence against any employee of the Company or other person during the course of his engagement; or

v.   Conviction of any felony or misdemeanor involving moral turpitude.

3. Duties.

Unless otherwise detailed in a specific letter or memorandum, Consultant shall manage, perform and provide professional consulting services and advice (“Consulting Services”) as the Company may request from time to time.  The Consulting Services shall include but not be limited to such matters as the construction of the Kemper County Project, including attendance of meetings of the Kemper Executive Review Board, global commercialization of TRIG technology and Southern Power Company growth and operations strategy.  Consultant shall be available to provide Consulting Services for the Company for no more than four (4) days during each calendar month during the Term of the Agreement.  Consultant must obtain prior written approval from an authorized officer of the Company before Consultant contracts with or in any other way employs any agents or subcontractors to perform work in any way related to the Agreement.  Consultant shall cause its agents, employees and subcontractors to perform such duties in a professional and competent manner which shall be consistent with the Company’s Code of Ethics.  Additionally, during the Term of the Agreement, Consultant agrees to promote the best interests of the Company and to take no actions that in any way damage the public image or reputation of the Company or its affiliates or to knowingly assist, in any way, a competitor of the Company.

- 2 -

4.           Consultant as an Independent Contractor.

In the performance of the Agreement, both Consultant and the Company will be acting in their own separate capacities and not as agents, employees, partners, joint venturers or associates of one another.  It is expressly understood and agreed that Consultant is an independent contractor of the Company in all manners and respects.  The parties further agree that:

(a)          Consultant is not authorized to bind the Company to any liability or obligation or to represent that Consultant has any such authority.

(b)          Consultant shall obtain and maintain (at Consultant’s own cost) any required insurance or other protection required for the performance of the services under the Agreement.

(c)          Consultant shall be solely and exclusively responsible and liable for all other expenses, costs, liabilities, assessments, taxes, maintenance, insurance, undertakings and other obligations incurred by Consultant at any time and for any reason as a result of the Agreement or the performance of services by Consultant.  However, Consultant may be reimbursed for reasonable out-of-pocket expenses where prior approval has been received from a Company Officer.

(d)          Consultant shall be solely and exclusively responsible for obtaining and providing (at Consultant’s own cost) whatever computer, training, software or other equipment Consultant believes is necessary to complete the services required under the Agreement.

(e)          Consultant shall complete the services required under the Agreement according to Consultant’s own means and methods of work which shall be in the exclusive charge and control of Consultant and which shall not be subject to the control or supervision of Company, except as to the results of the work.

(f)          Consultant shall not be subject to the Company’s employee personnel policies and procedures.  Other than as a retired employee of the Company, Consultant also shall not be eligible to receive any employee benefits or participate in any employee benefit plan sponsored by the Company, including, but not limited to, any retirement plan, insurance program, disability plan, medical benefits plan or any other fringe benefit program sponsored and maintained by the Company for its employees.

(g)          The Company and Consultant acknowledge and agree that Consultant shall not provide the services to Company on a full-time basis.  Except to the extent restricted under the Agreement, the Consultant may engage in other activities for and on behalf of other clients during the Term of the Agreement.

- 3 -

              5.Retainer Fee.

As payment for the Consulting Services rendered pursuant to the Agreement, the Company shall pay, and Consultant shall accept, a fee in the amount of One Million Seven Hundred Thousand Dollars and No Cents ($1,700,000.00).  The payment of the Retainer Fee shall be made in two (2) equal installments of Eight Hundred Fifty Thousand Dollars and No Cents ($850,000.00) each, payable on August 1, 2012 and January 2, 2013, or as soon as practicable after such dates, except that any extended period shall not exceed fourteen (14) business days.

6.           Confidentiality.

             (a)       For purposes of the Agreement, the following terms shall have the following respective meanings:

            (1)     “Confidential Information” shall mean all valuable, proprietary and confidential information belonging to or pertaining to the Company that does not constitute a “Trade Secret” of the Company and that is not generally known by or available to the Company’s competitors but is generally known only to the Company and those of its employees, independent contractors, clients or agents to whom such information must be confided for internal business purposes.

            (2)     “Trade Secrets” shall mean the “trade secrets” of the Company as defined under applicable laws

             (b)       During the performance of his duties hereunder, Consultant will be exposed to certain Trade Secrets and Confidential Information.  Consultant acknowledges and agrees that the Trade Secrets and Confidential Information represent a substantial investment by Company and that any disclosure or use of any such Trade Secrets or Confidential Information, except as otherwise authorized in the Agreement, or any other violation of the confidentiality provisions of this Section 6, would be wrongful and could cause immediate and irreparable injury to Company.

            (c)        Except as required in order to perform his obligations under the Agreement, Consultant hereby covenants and agrees that Consultant shall regard and treat Trade Secrets and all Confidential Information as strictly confidential and wholly-owned by the Company and shall not, for any reason, in any fashion, either directly or indirectly, use, sell, lend, lease, distribute, license, give, transfer, assign, show, disclose, disseminate, reproduce, copy, misappropriate or otherwise communicate any such item or information to any third party entity for any purpose other than in accordance with the Agreement or as required by applicable law:  (i) with regard to any Confidential Information, during the Term of the Agreement and for a period of three (3) years thereafter, and (ii) with regard to any Trade Secret, at any time during which such information constitutes a trade secret under applicable law.

- 4 -

7.           Ownership of Work Product.

All work product, property, data, documentation, information or materials conceived, discovered, developed or created by Consultant in performing the Consulting Services pursuant to the Agreement (collectively, the “Work Product”) shall be owned exclusively by the Company.  To the greatest extent possible, any Work Product shall be deemed to be a “work made for hire” (as defined in the United States Copyright Act, 17 U.S.C.A §101 et seq., as amended) and owned exclusively by the Company.  Consultant hereby unconditionally and irrevocably transfers and assigns to the Company all right, title and interest in or to any Work Product.

8.           Remedies.

The parties represent and agree that any disclosure or use of any Trade Secrets or Confidential Information by Consultant except as otherwise permitted under the Agreement or authorized by the Company in writing, or any other violation of Sections 6 or 7, would be wrongful and cause immediate, significant, continuing and irreparable injury and damage to Company that is not fully compensable by monetary damages.  Should Consultant breach or threaten to breach any provisions of Sections 6 and 7, the Company shall be entitled to obtain immediate relief and remedies in a court of competent jurisdiction (including but not limited to damages, preliminary or permanent injunctive relief and an accounting for all profits and benefits arising out of Consultant’s breach), cumulative of and in addition to any other rights or remedies to which Company may be entitled by the Agreement, at law or in equity.

9.           Return of Materials.

Immediately upon termination of the Agreement, or at any point prior to or after that time upon the specific request of Company, the Consultant shall return to the Company, all written or descriptive materials of any kind belonging or relating to the Company or its affiliates, including, without limitation, any Work Produce, Confidential Information and Trade Secrets, in Consultant’s possession or control.

10.           Laws, Regulations and Public Ordinances.

Consultant shall comply with all federal, state and local statutes, regulations and public ordinances governing his work hereunder and shall indemnify, defend and hold the Company harmless from any and all liability, damage, cost, fine, penalty, fee and expense arising from Consultant’s failure to do so.

11.           Notices.

All notices required, necessary or desired to be given pursuant to the Agreement shall be in writing and shall be effective when delivered or on the third day following the date upon which such notice is deposited, postage prepaid, in the United States mail, certified return receipt requested, and addressed to the party at the address set forth below:

- 5 -

If to Consultant: Anthony J. Topazi 7341 Kings Mountain Road Vestavia Hills, AL 35242    If to the Company: Stacy Kilcoyne Vice President Southern Company Services, Inc. 30 Ivan Allen Blvd. NW Atlanta, Georgia  30308

12.           Indemnification.

Consultant shall and does hereby expressly agree to indemnify and hold harmless the Company, its officers, directors, shareholders, employees, parent and affiliates against any and all suits, actions, judgments, costs (including, without limitation, all court costs and attorneys’ fees), losses, damages or claims of whatever nature arising out of or related to any acts or omissions of Consultant, his agents, employees or subcontractors, including, but not limited to, any injuries to or deaths of persons or any damage to property or equipment.  Consultant further agrees to defend any and all such actions in any court or in arbitration.

13.           Waiver of Breach.

The waiver by any party to the Agreement of a breach of any provision, section or paragraph of the Agreement shall not operate or be construed as a waiver of any subsequent breach of the same, or of a different provision, section or paragraph, by any party hereto.

14.           Assignment by Consultant.

Consultant may not assign, transfer or subcontract any of his rights or obligations under the Agreement to any party without the prior written consent of the Company.  Consultant’s obligations under the Agreement shall be binding on Consultant’s successors and permitted assigns.  Any assignment, transfer or subcontracting in violation of this provision shall be null and void.

15.           Governing Law.

The Agreement shall be construed and enforced in accordance with the laws of the State of Alabama.

16.           Severability.

The unenforceability or invalidity of any particular provision of the Agreement shall not affect its other provisions, and to the extent necessary to give such other provisions effect, they shall be deemed severable.  The judicial body interpreting the Agreement shall be authorized and instructed to rewrite any of the sections which are enforceable as written in such a fashion so that they may be enforced to the greatest extent legally possible.  Consultant acknowledges and agrees that the covenants and agreements contained in the Agreement shall be construed as covenants and agreements independent of each other or any other contract between the parties

- 6 -

hereto and that the existence of any claim or cause of action by Consultant against the Company, whether predicated upon the Agreement or any other contract, shall not constitute a defense to the enforcement by the Company of said covenants and agreements.

17.           Interpretation.

Should a provision of the Agreement require judicial interpretation, it is agreed that the judicial body interpreting or construing the Agreement shall not apply the assumption that the terms hereof shall be more strictly construed against one party by reason of the rule of construction that an instrument is to be construed more strictly against the party which itself or through its or his agents prepared the agreement, it being agreed that all parties and/or their agents have participated in the preparation hereof.

18.           Survival.

Notwithstanding any expiration or termination of the Agreement, the provisions of Sections 6 through 19 hereof shall survive and remain in full force and effect, as shall any other provision hereof that, by its terms or reasonable interpretation thereof, sets forth obligations that extend beyond the termination of the Agreement.

19.           Entire Agreement.

The Agreement and the Separation and Release Agreement embodies the entire agreement of the parties and supersedes all prior agreements between the parties hereto relating to the subject matter hereof.  The Agreement may not be modified or amended except by a written instrument signed by both Employee and an authorized representative of the Company.

IN WITNESS WHEREOF, the parties hereto have executed the Agreement this ___5____ day of __June__, 2012.

“COMPANY”                                                                                     “CONSULTANT”

SOUTHERN COMPANY SERVICES, INC.                                   ANTHONY J. TOPAZI

By:  /s/Thomas A Fanning                                                                       /s/Anthony J. Topazi

Its:  Chairman of the Board                                                                

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EX-24

Exhibit 24(d)2

July 18, 2012

Mr. Art P. Beattie The Southern Company 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308 Ms. Melissa K. Caen Southern Company Services, Inc. 30 Ivan Allen Jr. Blvd, NW Atlanta, GA  30308  

Dear Mr. Beattie and Ms. Caen:

As a Director and an officer of Gulf Power Company, I hereby make, constitute, and appoint you my true and lawful Attorney in my name, place and stead, to sign and cause to be filed with the Securities and Exchange Commission (1) this Company's Quarterly Reports on Form 10-Q during 2012, and (2) any necessary or appropriate amendment or amendments to any such reports and to this Company’s Annual Report on Form 10-K for the year ended December 31, 2011, each such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

                                                                                     /s/S. W. Connally, Jr.

S. W. Connally, Jr.

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:  August 6, 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:  August 6, 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:  August 6, 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:  August 6, 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:  August 6, 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:  August 6, 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, S. W. Connally, Jr., certify that:

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

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

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

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

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 6, 2012

          /s/S. W. Connally, Jr.         

S. W. Connally, Jr.

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:  August 6, 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:  August 6, 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:  August 6, 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:  August 6, 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:  August 6, 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 June 30, 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 June 30, 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 June 30, 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

August 6, 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 June 30, 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 June 30, 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 June 30, 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

August 6, 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 June 30, 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 June 30, 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 June 30, 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

August 6, 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 June 30, 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 June 30, 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 June 30, 2012, fairly presents, in all material respects, the financial condition and results of operations of Gulf Power Company.

           /s/S. W. Connally, Jr.              

S. W. Connally, Jr.

President and Chief Executive Officer

              /s/Richard S. Teel                 

Richard S. Teel

Vice President and Chief Financial Officer

August 6, 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 June 30, 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 June 30, 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 June 30, 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

August 6, 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 June 30, 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 June 30, 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 June 30, 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

August 6, 2012

XML

Effective Tax Rate and Unrecognized Tax Benefits (Details Textual)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	34.10%	35.40%
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	38.90%	38.50%
Georgia Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	34.20%	34.80%
Gulf Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	36.60%	35.90%
Mississippi Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	25.20%	32.60%
Southern Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	35.90%	35.30%

XML

Segment and Related Information (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Financial data for business segments
Operating revenues	$ 4,181,000,000	$ 4,521,000,000	$ 7,785,000,000	$ 8,533,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	623,000,000	604,000,000	991,000,000	1,026,000,000
Total Assets	60,897,000,000	59,267,000,000	60,897,000,000	59,267,000,000	59,267,000,000
Electric Utilities [Member]
Financial data for business segments
Operating revenues	4,166,000,000	4,503,000,000	7,755,000,000	8,497,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	596,000,000	603,000,000	964,000,000	1,025,000,000
Total Assets	60,385,000,000	58,076,000,000	60,385,000,000	58,076,000,000
Traditional Operating Companies [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	3,989,000,000	4,291,000,000	7,438,000,000	8,101,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	549,000,000	559,000,000	888,000,000	943,000,000
Total Assets	56,726,000,000	54,622,000,000	56,726,000,000	54,622,000,000
Southern Power [Member]
Segment and Related Information (Textual) [Abstract]
Southern Power's revenues from sales to the traditional operating companies	106,000,000	71,000,000	218,000,000	154,000,000
Southern Power [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	286,000,000	305,000,000	539,000,000	587,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	47,000,000	44,000,000	76,000,000	82,000,000
Total Assets	3,785,000,000	3,581,000,000	3,785,000,000	3,581,000,000
Eliminations [Member]
Financial data for business segments
Operating revenues	(20,000,000)	(20,000,000)	(43,000,000)	(40,000,000)
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries			(1,000,000)	(1,000,000)
Total Assets	(620,000,000)	(401,000,000)	(620,000,000)	(401,000,000)
Eliminations [Member] | Electric Utilities [Member]
Financial data for business segments
Operating revenues	(109,000,000)	(93,000,000)	(222,000,000)	(191,000,000)
Total Assets	(126,000,000)	(127,000,000)	(126,000,000)	(127,000,000)
All Other [Member]
Financial data for business segments
Operating revenues	35,000,000	38,000,000	73,000,000	76,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	27,000,000	1,000,000	28,000,000	2,000,000
Total Assets	$ 1,132,000,000	$ 1,592,000,000	$ 1,132,000,000	$ 1,592,000,000

XML

Stockholder's Equity (Details) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Earnings per Share
As reported shares	872	855	870	851
Effect of options and performance share award units	8	7	9	7
Diluted shares	880	862	879	858

XML

Derivatives (Tables)

6 Months Ended

Jun. 30, 2012

Derivatives [Abstract]

Energy-related derivative contracts

	Net Purchased mmBtu		Longest Hedge Date		Longest Non-Hedge Date
	(in millions)
Southern Company		242		2017		2017
Alabama Power		43		2017		—
Georgia Power		96		2017		—
Gulf Power		51		2017		—
Mississippi Power		34		2017		—
Southern Power		18		2012		2017

Notional amount of interest rate derivatives

	Notional Amount		Interest Rate Received		Interest Rate Paid		Hedge Maturity Date		Fair Value Gain (Loss) June 30, 2012
	(in millions)								(in millions)
Cash flow hedges of forecasted transactions
Alabama Power	$	300		3-month LIBOR		2.90%(a)		December 2022	$(28)
Fair value hedges of existing debt
Southern Company		350		4.15%		3-month LIBOR  + 1.96%(a)		May 2014	12
Total	$	650							$(16)

(a) 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 June 30, 2013	Total Deferred Gains (Losses) Amortized Through
	(in millions)
Southern Company	$(17)	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) June 30, 2012
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR6.3	1.3850 Dollars per Euro(a)	Various through March 2014	$(1)
Derivatives not designated as hedges
Mississippi Power	EUR18.1	1.3186 Dollars per Euro (a)	N/A	(1)
Total	EUR24.4			$(2)

(a) Weighted Average

Fair value of energy-related derivatives and interest rate derivatives

Asset Derivatives at June 30, 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	$	14	$	1	$	13	$	—	$	—
Other deferred charges and assets		9		2		4		2		1
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	3	$	17	$	2	$	1		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		6		—		—		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	12	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	$	1	$	—	$	—	$	—	$	—	$	1
Total asset derivatives	$	36	$	3	$	17	$	2	$	1	$	1

Liability Derivatives at June 30, 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	$123	$26	$  52	$20	$25
Other deferred credits and liabilities	64	9	23	19	13
Total derivatives designated as hedging instruments for regulatory purposes	$187	$35	$75	$39	$38	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities	$    1	$—	$  —	$  —	$  —	$1
Interest rate derivatives:
Liabilities from risk management activities	28	28	—	—	—	—
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$  30	$28	$—	$—	$1	$1
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$    6	$—	$  —	$—	$—	$6
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$    7	$—	$  —	$  —	$  1	$6
Total liability derivatives	$224	$63	$75	$39	$40	$7

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		$(123)		$(26)		$(52)		$(20)		$(25)
Other regulatory assets, deferred		(64)		(9)		(23)		(19)		(13)
Other regulatory liabilities, current		14		1		13		—		—
Other regulatory liabilities, deferred		9		2		—		2		1
Other deferred credits and liabilities (a)		—		—		4		—		—
Total energy-related derivative gains (losses)		$(164)		$(32)		$(58)		$(37)		$(37)

(a) Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

Pre-tax effect of derivatives designated as cash flow hedging instruments

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
Interest rate derivatives	$    (18)	$    —	Interest expense, net of amounts capitalized	$            (4)	$            (1)
Alabama Power
Interest rate derivatives	$    (18)	$    —	Interest expense, net of amounts capitalized	$            —	$      3
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (1)	$            (1)
Southern Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (3)	$            (3)

For the six months ended June 30, 2012 and 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 Hedging	Gain (Loss) Recognized in OCI on Derivative		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Relationships	(Effective Portion)		Statements of Income Location	Amount
	2012	2011		2012	2011
	(in millions)			(in millions)
Southern Company
Energy-related derivatives	$    —	$       1	Fuel	$            —	$            —
Interest rate derivatives	(12)	4	Interest expense, net of amounts capitalized	(7)	(6)
Total	$    (12)	$         5		$            (7)	$            (6)
Alabama Power
Interest rate derivatives	$    (11)	$         4	Interest expense, net of amounts capitalized	$          —	$            3
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (2)	$            (2)
Mississippi Power
Interest rate derivatives	$    (1)	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Southern Power
Energy-related derivatives	$    —	$       1	Fuel	$            —	$            —
Interest rate derivatives	—	—	Interest expense, net of amounts capitalized	(5)	(6)
Total	$    —	$       1		$            (5)	$            (6)

Fair value of derivative liabilities with contingent features

	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi Power	Southern Power
			(in millions)
Derivative liabilities	$27	$6	$8	$6	$5	$2

XML

Derivatives (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			$ (12)	$ 5
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(7)	(6)
Fuel [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
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)	(4)	(1)	(7)	(6)
Alabama Power [Member] | Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		3		3
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)	(2)	(2)
Mississippi Power [Member] | Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Southern Power [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				1
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(5)	(6)
Southern Power [Member] | Fuel [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Southern Power [Member] | Interest expense, net of amounts capitalized [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(3)	(3)	(5)	(6)
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
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
Interest rate derivatives [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(18)		(12)	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)	(18)		(11)	4
Interest rate derivatives [Member] | Georgia Power [Member]
Pre-tax effect of derivatives designated as cash flow hedging instruments
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)
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)
Interest rate 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)

XML

Effective Tax Rate and Unrecognized Tax Benefits (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	$ 120
Tax positions from current periods	4
Tax positions from prior periods	(23)
Reductions due to settlements	(5)
Reductions due to expired statute of limitations	(3)
Unrecognized tax benefits as of June 30, 2012	93
Alabama Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	32
Tax positions from current periods	2
Tax positions from prior periods	(3)
Reductions due to settlements	(2)
Unrecognized tax benefits as of June 30, 2012	29
Georgia Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	47
Tax positions from current periods	2
Tax positions from prior periods	(19)
Reductions due to settlements	(4)
Reductions due to expired statute of limitations	(3)
Unrecognized tax benefits as of June 30, 2012	23
Gulf Power [Member]
Changes for unrecognized tax benefits
Unrecognized tax benefits as of December 31, 2011	3
Tax positions from current periods	1
Tax positions from prior periods	(1)
Reductions due to settlements	(1)
Unrecognized tax benefits as of June 30, 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)
Unrecognized tax benefits as of June 30, 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
Unrecognized tax benefits as of June 30, 2012	$ 2

XML

Segment and Related Information (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Financial data for Products and Services
Electric Utilities Revenues	$ 4,166	$ 4,503	$ 7,755	$ 8,497
Retail [Member]
Financial data for Products and Services
Electric Utilities Revenues	3,597	3,842	6,689	7,238
Wholesale [Member]
Financial data for Products and Services
Electric Utilities Revenues	415	507	764	956
Other Electric Revenue [Member]
Financial data for Products and Services
Electric Utilities Revenues	$ 154	$ 154	$ 302	$ 303

XML

Introduction

6 Months Ended

Jun. 30, 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 June 30, 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. Current projections indicate significant uncertainty as to whether the lessee will be able to pay the December 2012 semi-annual rent payment in full. 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 believes there is a reasonable possibility that it will be able to reach an agreement with the lessee and the debtholders to restructure the project. However, due to continued poor performance of the generation assets and the uncertainties surrounding the receipt of the December 2012 semi-annual rent payment and its ability to successfully restructure the project, Southern Company has placed the lease on nonaccrual status whereby income associated with this investment will not be recognized in the financial statements beginning in July 2012. 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	Jun. 30, 2012
Fair value of derivative liabilities with contingent features
Derivative liabilities	$ 27
Alabama Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	6
Georgia Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	8
Gulf Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	6
Mississippi Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	5
Southern Power [Member]
Fair value of derivative liabilities with contingent features
Derivative liabilities	$ 2

XML

Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	$ 24
Interest rate derivatives	12
Nuclear decommissioning trusts	1,234
Cash equivalents and restricted cash	512
Other	69
Fair value assets, total	1,851
Liabilities:
Energy-related derivatives	194
Interest rate derivatives	28
Foreign currency derivatives	2
Fair value liabilities, total	224
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Nuclear decommissioning trusts	450
Cash equivalents and restricted cash	512
Other	1
Fair value assets, total	963
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	24
Interest rate derivatives	12
Nuclear decommissioning trusts	784
Other	53
Fair value assets, total	873
Liabilities:
Energy-related derivatives	194
Interest rate derivatives	28
Foreign currency derivatives	2
Fair value liabilities, total	224
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	3
Fair value assets, total	572
Liabilities:
Energy-related derivatives	35
Interest rate derivatives	28
Fair value liabilities, total	63
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	334
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	74
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	101
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	25
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	12
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Fair value assets, total	299
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	274
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	25
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	3
Fair value assets, total	273
Liabilities:
Energy-related derivatives	35
Interest rate derivatives	28
Fair value liabilities, total	63
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	60
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	49
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	23
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	101
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	25
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	12
Georgia Power [Member]
Assets:
Nuclear decommissioning trusts	38
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	17
Cash equivalents and restricted cash	149
Fair value assets, total	830
Liabilities:
Energy-related derivatives	75
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	152
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	102
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	45
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	103
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	120
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	118
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	24
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents and restricted cash	149
Fair value assets, total	300
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	151
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	17
Fair value assets, total	530
Liabilities:
Energy-related derivatives	75
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	102
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	45
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	103
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	120
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	118
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	24
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	2
Cash equivalents and restricted cash	15
Fair value assets, total	17
Liabilities:
Energy-related derivatives	39
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
Fair value assets, total	15
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	2
Fair value assets, total	2
Liabilities:
Energy-related derivatives	39
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	1
Cash equivalents and restricted cash	146
Fair value assets, total	147
Liabilities:
Energy-related derivatives	38
Foreign currency derivatives	2
Fair value liabilities, total	40
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	146
Fair value assets, total	146
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	1
Fair value assets, total	1
Liabilities:
Energy-related derivatives	38
Foreign currency derivatives	2
Fair value liabilities, total	40
Southern Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	1
Liabilities:
Energy-related derivatives	7
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	1
Liabilities:
Energy-related derivatives	$ 7

XML

Contingencies and Regulatory Matters (Details) (USD $)	3 Months Ended	6 Months Ended	12 Months Ended			6 Months Ended	1 Months Ended	6 Months Ended		1 Months Ended		6 Months Ended			6 Months Ended						6 Months Ended	12 Months Ended	13 Months Ended													6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012 Entity	Dec. 31, 2009	Jun. 14, 2012	Dec. 31, 2011	Jun. 30, 2012 Kivalina Case [Member]	Jul. 31, 2007 Alabama Power [Member]	Jun. 30, 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]	Jun. 30, 2012 Georgia Power [Member] MW Coal_Fired_Generating_Facilities Claims	Jun. 01, 2012 Georgia Power [Member]	Dec. 31, 2011 Georgia Power [Member]	Jun. 30, 2012 Gulf Power [Member]	Jun. 19, 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]	Jun. 30, 2012 Mississippi Power [Member]	Dec. 31, 2009 Mississippi Power [Member]	Apr. 30, 2012 Mississippi Power [Member]	Jul. 09, 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]	Jun. 14, 2012 Mississippi Power [Member] Minimum [Member]	Jun. 14, 2012 Mississippi Power [Member] Maximum [Member]	Jun. 30, 2012 Mississippi Power [Member] MRA Revenue [Member]	Dec. 31, 2011 Mississippi Power [Member] MRA Revenue [Member]	Jun. 30, 2012 Mississippi Power [Member] MB Revenue [Member]	Dec. 31, 2011 Mississippi Power [Member] MB Revenue [Member]	Jun. 30, 2012 Gulf Power and Mississippi Power [Member]	Jun. 30, 2012 Electricity Generation Plant, Non-Nuclear [Member] Mississippi Power [Member]	Jun. 30, 2012 Mine [Member] Mississippi Power [Member]	Jun. 30, 2012 Kemper IGCC [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	16,144,000,000	16,144,000,000			15,383,000,000			5,440,000,000	5,326,000,000			6,943,000,000		6,703,000,000	1,145,059,000			1,021,743,000			1,014,603,000						776,781,000
Claims awarded to companies related to nuclear fuel disposal litigation							17,000,000				30,000,000
Damages awarded										27,000,000
Amount have been recognized in the financial statements for the second claim												0
Under recovered rate CNP balance								2,000,000	6,000,000
Under recovered rate CNP Environmental balance								26,000,000	11,000,000
Accumulated reserve balance for future storms								105,000,000
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%
Percentage of decrease in annual revenue after revised notice																									0.16%
Interim rates under bond subject to refund																								55,300,000
Revenue request to recover financing costs for stipulated rate increase																													55,300,000	58,600,000
Amount approved for property damage reserve																										3,700,000
Amount of over recovered retail fuel costs included in the balance sheets																					55,500,000						42,400,000
Percentage of decrease in fuel rates													19.00%			7.80%
Decrease in annual billings for fuel costs													567,000,000			58,800,000
Amount of over recovered fuel costs																															17,400,000	14,300,000	2,400,000	2,200,000
Amount of over recovered MRA emissions allowance cost included in the balance sheets																					1,000,000						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
Under recovered energy conservation costs															1,600,000			3,100,000
Electric generating capacity in Mega Watts under contractor												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												99,000,000
Under recovered regulatory clause revenues	20,000,000	20,000,000			143,000,000			16,000,000						137,000,000	4,070,000			5,530,000
Over recovered purchased power capacity costs															7,900,000			8,000,000
Over recovered environmental cost.															3,600,000			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																					99,900,000
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																					197,000,000
Percentage interest acquired under asset purchase agreement																					17.50%
Percentage interest transferred under asset purchase agreement																					17.50%
Reduced Percentage interest transferred under asset purchase agreement																					15.00%
Deposit received																					150,000,000
Maximum period to refund deposit upon termination of asset purchase agreement																					60 days
Maximum period of discretion in the event senior unsecured credit rating falls																					15 days
Estimated cost																																				2,400,000,000		2,880,000,000
Estimated cost less cost cap																																						72,000,000
Percentage of financing costs of construction work in progress																												100.00%
Cost deferred in other regulatory assets	3,484,000,000	3,484,000,000			3,532,000,000			1,001,000,000	994,000,000			1,550,000,000		1,604,000,000	332,325,000			323,116,000			195,721,000						185,694,000
Other deferred charges and assets	455,000,000	455,000,000			481,000,000			144,000,000	186,000,000			221,000,000		187,000,000	27,567,000			39,493,000			37,640,000						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%
Scrubber project expenditures amount																					41,000,000														82,000,000
Cost deferred in other regulatory assets																					29,000,000
Previously expensed																					1,000,000
Amortization to earnings of financing costs capitalized over the five year period												91,000,000
Costs included in CWIP												64,000,000									1,600,000,000
Contractor's estimated adjustment to contract price												425,000,000
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
Over Recovered Fuel Cost															41,600,000			9,900,000
Estimated capital cost of mine																					245,000,000
Cost incurred by Mississippi Power associated with plant including regulatory filing costs																					1,700,000,000
Costs associated with CCP12 grant funds																					245,300,000
Other deferred charges and assets																					2,600,000
Contingencies and Regulatory Matters (Additional Textual) [Abstract]
MC Asset Recovery insurance settlement	19,000,000	19,000,000	(202,000,000)
Amount of insurance claim received in respect of litigation settlement				25,000,000
Legal fee related to insurance recoveries				6,000,000
Net amount received of insurance claim in respect of litigation settlement				19,000,000
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

Derivatives (Details Textual) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints		8,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	$ 27	$ 27
Energy-related derivatives [Member]
Derivatives (Textual) [Abstract]
Pre-tax gains from energy-related derivatives not designated as hedging instruments on the statements of income	10	4
Alabama Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints		1,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	27	27
Georgia Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints		3,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	27	27
Gulf Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints		1,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	27	27
Mississippi Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints		1,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	27	27
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	$ 27	$ 27

XML

Fair Value Measurements (Details 1) (USD $) In Millions, unless otherwise specified	Jun. 30, 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	$ 8
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	8
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	73
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	49
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	24
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	91
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	91
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	512
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable
Money market 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	149
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	146
Unfunded Commitments	$ 0
Redemption Frequency	Daily
Redemption Notice Period	Not applicable

XML

Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
Long-term debt:
Long-term debt, Carrying Amount	$ 21,451
Long-term debt, Fair Value	23,477
Alabama Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	6,130
Long-term debt, Fair Value	6,893
Georgia Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	9,856
Long-term debt, Fair Value	10,703
Gulf Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,246
Long-term debt, Fair Value	1,384
Mississippi Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,576
Long-term debt, Fair Value	1,690
Southern Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,306
Long-term debt, Fair Value	$ 1,416

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Changes in fair value of qualifying hedges, tax	$ (8,000,000)		$ (5,000,000)	$ 2,000,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	2,000,000	1,000,000	3,000,000	3,000,000
Change in fair value of marketable securities, tax		2,000,000		1,000,000
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	1,000,000	(1,000,000)	1,000,000	1,000,000
Alabama Power [Member]
Changes in fair value of qualifying hedges, tax	(7,000,000)	(1,000,000)	(4,000,000)	1,000,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax		(1,000,000)		(1,000,000)
Georgia Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1,000,000	1,000,000	1,000,000	1,000,000
Gulf Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	90,000	90,000	180,000	180,000
Mississippi Power [Member]
Changes in fair value of qualifying hedges, tax		7,000	(296,000)	6,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	132,000		148,000
Southern Power [Member]
Changes in fair value of qualifying hedges, tax	53,000	(23,000)	(120,000)	400,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 956,000	$ 1,084,000	$ 1,912,000	$ 2,155,000

XML

Fair Value Measurements (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Fair Value Measurements (Textual) [Abstract]
Increase in fair value of funds including reinvested interest and dividends	$ (22)	$ 64
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	(16)	33
Georgia Power [Member]
Fair Value Measurements (Textual) [Abstract]
Nuclear decommissioning trusts	38	38
Increase in fair value of funds including reinvested interest and dividends	$ (6)	$ 31

XML

Derivatives (Details) In Millions, unless otherwise specified	6 Months Ended		6 Months Ended		6 Months Ended								6 Months Ended
	Jun. 30, 2012 USD ($)	Jun. 30, 2012 Fair Value Hedging [Member] USD ($)	Jun. 30, 2012 Alabama Power [Member] USD ($)	Jun. 30, 2012 Alabama Power [Member] Cash Flow Hedging [Member] USD ($)	Jun. 30, 2012 Georgia Power [Member] USD ($)	Jun. 30, 2012 Gulf Power [Member] USD ($)	Jun. 30, 2012 Mississippi Power [Member] USD ($)	Jun. 30, 2012 Mississippi Power [Member] EUR (€)	Jun. 30, 2012 Mississippi Power [Member] Derivatives not designated as hedges [Member] USD ($)	Jun. 30, 2012 Mississippi Power [Member] Derivatives not designated as hedges [Member] EUR (€)	Jun. 30, 2012 Mississippi Power [Member] Fair Value Hedging [Member] USD ($)	Jun. 30, 2012 Mississippi Power [Member] Fair Value Hedging [Member] EUR (€)	Jun. 30, 2012 Southern Power [Member] USD ($)	Jun. 30, 2012 Gas [Member] MMBTU	Jun. 30, 2012 Gas [Member] Alabama Power [Member] MMBTU	Jun. 30, 2012 Gas [Member] Georgia Power [Member] MMBTU	Jun. 30, 2012 Gas [Member] Gulf Power [Member] MMBTU	Jun. 30, 2012 Gas [Member] Mississippi Power [Member] MMBTU	Jun. 30, 2012 Gas [Member] Southern Power [Member] MMBTU
Energy-related derivative contracts
Net Purchased mmBtu														242,000,000	43,000,000	96,000,000	51,000,000	34,000,000	18,000,000
Longest Hedge Date														2017	2017	2017	2017	2017	2012
Longest Non-Hedge Date														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) June 30, 2012	(16)	12		(28)
Total deferred gains and losses are expected to be amortized into earnings
Estimated Gain (Loss) to be Reclassified for the 12 Months Ending June 30, 2013	(17)		(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								24.4		18.1		6.3
Forward Rate									1.3186		1.3850
Hedge maturity date											Various through March 2014	Various through March 2014
Fair Value Gain (Loss) June 30, 2012							$ (2)		$ (1)		$ (1)

XML

Condensed Consolidated Statements of Income (Unaudited) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Operating Revenues:
Retail revenues	$ 3,597,000,000	$ 3,842,000,000	$ 6,689,000,000	$ 7,238,000,000
Wholesale revenues	415,000,000	507,000,000	764,000,000	956,000,000
Other electric revenues	154,000,000	154,000,000	302,000,000	303,000,000
Other revenues	15,000,000	18,000,000	30,000,000	36,000,000
Total operating revenues	4,181,000,000	4,521,000,000	7,785,000,000	8,533,000,000
Operating Expenses:
Fuel	1,290,000,000	1,673,000,000	2,354,000,000	3,149,000,000
Purchased power	150,000,000	145,000,000	291,000,000	245,000,000
Other operations and maintenance	944,000,000	910,000,000	1,911,000,000	1,854,000,000
MC Asset Recovery insurance settlement	(19,000,000)		(19,000,000)
Depreciation and amortization	445,000,000	430,000,000	886,000,000	848,000,000
Taxes other than income taxes	228,000,000	227,000,000	453,000,000	447,000,000
Total operating expenses	3,038,000,000	3,385,000,000	5,876,000,000	6,543,000,000
Operating Income	1,143,000,000	1,136,000,000	1,909,000,000	1,990,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	32,000,000	36,000,000	63,000,000	71,000,000
Interest expense, net of amounts capitalized	(220,000,000)	(199,000,000)	(431,000,000)	(421,000,000)
Other income (expense), net	13,000,000	(4,000,000)	11,000,000	(2,000,000)
Total other income and (expense)	(175,000,000)	(167,000,000)	(357,000,000)	(352,000,000)
Earnings Before Income Taxes	968,000,000	969,000,000	1,552,000,000	1,638,000,000
Income taxes	329,000,000	349,000,000	529,000,000	580,000,000
Consolidated Net Income	639,000,000	620,000,000	1,023,000,000	1,058,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	16,000,000	16,000,000	32,000,000	32,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	623,000,000	604,000,000	991,000,000	1,026,000,000
Earnings per share (EPS) -
Basic EPS	$ 0.71	$ 0.71	$ 1.14	$ 1.20
Diluted EPS	$ 0.71	$ 0.70	$ 1.13	$ 1.20
Average number of shares of common stock outstanding (in millions)
Basic	872	855	870	851
Diluted	880	862	879	858
Cash dividends paid per share of common stock	$ 0.4900	$ 0.4725	$ 0.9625	$ 0.9275
Alabama Power [Member]
Operating Revenues:
Retail revenues	1,254,000,000	1,244,000,000	2,346,000,000	2,370,000,000
Wholesale revenues, non-affiliates	70,000,000	70,000,000	131,000,000	138,000,000
Wholesale revenues, affiliates	6,000,000	75,000,000	20,000,000	150,000,000
Other revenues	47,000,000	51,000,000	96,000,000	102,000,000
Total operating revenues	1,377,000,000	1,440,000,000	2,593,000,000	2,760,000,000
Operating Expenses:
Fuel	343,000,000	428,000,000	649,000,000	823,000,000
Purchased power, non-affiliates	17,000,000	17,000,000	32,000,000	28,000,000
Purchased power, affiliates	66,000,000	57,000,000	106,000,000	103,000,000
Other operations and maintenance	316,000,000	290,000,000	637,000,000	587,000,000
Depreciation and amortization	160,000,000	159,000,000	317,000,000	316,000,000
Taxes other than income taxes	85,000,000	85,000,000	171,000,000	170,000,000
Total operating expenses	987,000,000	1,036,000,000	1,912,000,000	2,027,000,000
Operating Income	390,000,000	404,000,000	681,000,000	733,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	4,000,000	6,000,000	9,000,000	11,000,000
Interest income	4,000,000	5,000,000	8,000,000	9,000,000
Interest expense, net of amounts capitalized	(73,000,000)	(77,000,000)	(146,000,000)	(151,000,000)
Other income (expense), net	(4,000,000)	(7,000,000)	(11,000,000)	(13,000,000)
Total other income and (expense)	(69,000,000)	(73,000,000)	(140,000,000)	(144,000,000)
Earnings Before Income Taxes	321,000,000	331,000,000	541,000,000	589,000,000
Income taxes	126,000,000	131,000,000	210,000,000	227,000,000
Consolidated Net Income	195,000,000	200,000,000	331,000,000	362,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	10,000,000	10,000,000	20,000,000	20,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	185,000,000	190,000,000	311,000,000	342,000,000
Georgia Power [Member]
Operating Revenues:
Retail revenues	1,857,000,000	2,070,000,000	3,451,000,000	3,885,000,000
Wholesale revenues, non-affiliates	75,000,000	97,000,000	141,000,000	180,000,000
Wholesale revenues, affiliates	6,000,000	16,000,000	9,000,000	27,000,000
Other revenues	82,000,000	82,000,000	164,000,000	162,000,000
Total operating revenues	2,020,000,000	2,265,000,000	3,765,000,000	4,254,000,000
Operating Expenses:
Fuel	572,000,000	784,000,000	1,012,000,000	1,461,000,000
Purchased power, non-affiliates	94,000,000	96,000,000	187,000,000	170,000,000
Purchased power, affiliates	129,000,000	157,000,000	288,000,000	320,000,000
Other operations and maintenance	411,000,000	419,000,000	845,000,000	841,000,000
Depreciation and amortization	185,000,000	178,000,000	373,000,000	351,000,000
Taxes other than income taxes	94,000,000	94,000,000	181,000,000	181,000,000
Total operating expenses	1,485,000,000	1,728,000,000	2,886,000,000	3,324,000,000
Operating Income	535,000,000	537,000,000	879,000,000	930,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	13,000,000	22,000,000	26,000,000	47,000,000
Interest expense, net of amounts capitalized	(90,000,000)	(71,000,000)	(181,000,000)	(167,000,000)
Other income (expense), net	(6,000,000)	(5,000,000)	(9,000,000)	(6,000,000)
Total other income and (expense)	(83,000,000)	(54,000,000)	(164,000,000)	(126,000,000)
Earnings Before Income Taxes	452,000,000	483,000,000	715,000,000	804,000,000
Income taxes	152,000,000	169,000,000	244,000,000	280,000,000
Consolidated Net Income	300,000,000	314,000,000	471,000,000	524,000,000
Dividends on Preferred and Preference Stock of Subsidiaries	5,000,000	5,000,000	9,000,000	9,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	295,000,000	309,000,000	462,000,000	515,000,000
Gulf Power [Member]
Operating Revenues:
Retail revenues	294,878,000	320,474,000	533,398,000	595,300,000
Wholesale revenues, non-affiliates	28,729,000	38,874,000	55,847,000	69,893,000
Wholesale revenues, affiliates	28,702,000	22,857,000	65,066,000	26,992,000
Other revenues	17,899,000	17,060,000	32,142,000	31,688,000
Total operating revenues	370,208,000	399,265,000	686,453,000	723,873,000
Operating Expenses:
Fuel	141,220,000	178,686,000	262,308,000	310,468,000
Purchased power, non-affiliates	12,085,000	10,889,000	23,310,000	17,892,000
Purchased power, affiliates	5,210,000	12,549,000	7,723,000	29,167,000
Other operations and maintenance	79,779,000	72,583,000	155,009,000	153,092,000
Depreciation and amortization	35,173,000	32,304,000	68,480,000	64,060,000
Taxes other than income taxes	25,276,000	24,867,000	49,060,000	49,763,000
Total operating expenses	298,743,000	331,878,000	565,890,000	624,442,000
Operating Income	71,465,000	67,387,000	120,563,000	99,431,000
Other Income and (Expense):
Allowance for equity funds used during construction	1,736,000	2,522,000	2,973,000	4,657,000
Interest income	1,809,000	20,000	1,396,000	34,000
Interest expense, net of amounts capitalized	(15,698,000)	(14,423,000)	(31,066,000)	(28,052,000)
Other income (expense), net	(697,000)	(447,000)	(1,293,000)	(1,010,000)
Total other income and (expense)	(12,850,000)	(12,328,000)	(27,990,000)	(24,371,000)
Earnings Before Income Taxes	58,615,000	55,059,000	92,573,000	75,060,000
Income taxes	22,102,000	20,157,000	33,843,000	26,916,000
Consolidated Net Income	36,513,000	34,902,000	58,730,000	48,144,000
Dividends on Preferred and Preference Stock of Subsidiaries	1,550,000	1,550,000	3,101,000	3,101,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	34,963,000	33,352,000	55,629,000	45,043,000
Mississippi Power [Member]
Operating Revenues:
Retail revenues	192,177,000	207,005,000	358,448,000	387,479,000
Wholesale revenues, non-affiliates	64,116,000	67,813,000	118,347,000	137,664,000
Wholesale revenues, affiliates	5,324,000	6,303,000	9,364,000	15,603,000
Other revenues	4,467,000	4,920,000	8,639,000	8,571,000
Total operating revenues	266,084,000	286,041,000	494,798,000	549,317,000
Operating Expenses:
Fuel	105,469,000	123,674,000	194,088,000	244,728,000
Purchased power, non-affiliates	1,134,000	1,336,000	3,077,000	2,346,000
Purchased power, affiliates	10,843,000	19,867,000	19,703,000	28,217,000
Other operations and maintenance	60,501,000	64,512,000	115,396,000	134,879,000
Depreciation and amortization	22,517,000	20,345,000	44,998,000	40,208,000
Taxes other than income taxes	18,634,000	17,251,000	40,337,000	34,732,000
Total operating expenses	219,098,000	246,985,000	417,599,000	485,110,000
Operating Income	46,986,000	39,056,000	77,199,000	64,207,000
Other Income and (Expense):
Allowance for equity funds used during construction	13,870,000	4,991,000	25,697,000	8,122,000
Interest income	380,000	401,000	500,000	743,000
Interest expense, net of amounts capitalized	(13,023,000)	(5,532,000)	(20,828,000)	(11,545,000)
Other income (expense), net	(539,000)	(613,000)	(781,000)	(1,016,000)
Total other income and (expense)	688,000	(753,000)	4,588,000	(3,696,000)
Earnings Before Income Taxes	47,674,000	38,303,000	81,787,000	60,511,000
Income taxes	12,214,000	12,587,000	20,639,000	19,745,000
Consolidated Net Income	35,460,000	25,716,000	61,148,000	40,766,000
Dividends on Preferred and Preference Stock of Subsidiaries	433,000	433,000	866,000	866,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	35,027,000	25,283,000	60,282,000	39,900,000
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	177,865,000	232,960,000	318,422,000	430,126,000
Wholesale revenues, affiliates	105,950,000	70,569,000	217,738,000	153,843,000
Other revenues	1,990,000	1,680,000	3,326,000	3,027,000
Total operating revenues	285,805,000	305,209,000	539,486,000	586,996,000
Operating Expenses:
Fuel	91,551,000	101,158,000	180,629,000	203,873,000
Purchased power, non-affiliates	22,514,000	19,664,000	43,164,000	28,606,000
Purchased power, affiliates	2,914,000	22,178,000	5,254,000	37,277,000
Other operations and maintenance	40,205,000	40,047,000	88,594,000	82,801,000
Depreciation and amortization	34,016,000	30,805,000	65,929,000	60,972,000
Taxes other than income taxes	4,567,000	4,565,000	9,535,000	9,328,000
Total operating expenses	195,767,000	218,417,000	393,105,000	422,857,000
Operating Income	90,038,000	86,792,000	146,381,000	164,139,000
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13,949,000)	(17,774,000)	(27,591,000)	(36,603,000)
Other income (expense), net	(194,000)	(260,000)	(164,000)	(201,000)
Total other income and (expense)	(14,143,000)	(18,034,000)	(27,755,000)	(36,804,000)
Earnings Before Income Taxes	75,895,000	68,758,000	118,626,000	127,335,000
Income taxes	29,293,000	24,157,000	42,708,000	44,991,000
Consolidated Net Income	$ 46,602,000	$ 44,601,000	$ 75,918,000	$ 82,344,000

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Acquisitions (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Jun. 29, 2012 MW
Acquisitions (Textual) [Abstract]
Percent of interest owned indirectly by Southern Power		90.00%
Apex Nevada Solar LLC [Member] | Southern Power [Member]
Acquisitions (Textual) [Abstract]
Power of solar polycrystalline silicon facility		20
Beginning year of output of constructed plant		2012
Ending year of output of constructed plant		2037
Cash Consideration for acquisition of the interests in Apex		$ 102
Cash Consideration paid at closing	86.5
Cash Consideration will be paid under MIPA	$ 15.5

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Jun. 30, 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	875,000,000	866,000,000
Treasury shares at cost	600,000	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	$ 1,867	$ 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

XML

Financing (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
Credit arrangements by company
Expires, 2012	$ 98
Expires, 2013	306
Expires, 2014 and Beyond	4,760
Total	5,164
Unused	5,159
Executable Term-Loans, One Year	146
Executable Term-Loans, Two Years	41
Due Within One Year, Term Out	187
Due Within One Year, No Term Out	157
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	37
Expires, 2013	101
Expires, 2014 and Beyond	1,150
Total	1,288
Unused	1,288
Executable Term-Loans, One Year	51
Due Within One Year, Term Out	51
Due Within One Year, No Term Out	52
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	20
Expires, 2013	60
Expires, 2014 and Beyond	195
Total	275
Unused	275
Executable Term-Loans, One Year	45
Due Within One Year, Term Out	45
Due Within One Year, No Term Out	35
Mississippi Power [Member]
Credit arrangements by company
Expires, 2012	41
Expires, 2013	95
Expires, 2014 and Beyond	165
Total	301
Unused	301
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	70
Southern Power [Member]
Credit arrangements by company
Expires, 2014 and Beyond	500
Total	500
Unused	500
Other Subsidiaries [Member]
Credit arrangements by company
Expires, 2013	50
Total	50
Unused	50
Executable Term-Loans, One Year	25
Due Within One Year, Term Out	$ 25

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Financing (Tables)

6 Months Ended

Jun. 30, 2012

Financing [Abstract]

Credit arrangements by company

	Expires					Executable Term Loans		Due Within  One Year(a)
Company	2012	2013	2014 and Beyond(b)	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	37	101	1,150	1,288	1,288	51	—	51	52
Georgia Power	—	—	1,750	1,750	1,745	—	—	—	—
Gulf Power	20	60	195	275	275	45	—	45	35
Mississippi Power	41	95	165	301	301	25	41	66	70
Southern Power	—	—	500	500	500	—	—	—	—
Other	—	50	—	50	50	25	—	25	—
Total	$98	$306	$4,760	$5,164	$5,159	$146	$  41	$187	$157

(a) Reflects facilities expiring on or before June 30, 2013.

(b) All remaining Gulf Power and Mississippi Power credit agreements in this column expire in 2014.

XML

Retirement Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	$ 49	$ 46	$ 99	$ 92
Interest cost	99	97	197	195
Expected return on plan assets	(146)	(152)	(291)	(304)
Net amortization	31	13	62	26
Net cost (income)	33	4	67	9
Pension Plans [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	11	10	22	21
Interest cost	24	24	47	48
Expected return on plan assets	(41)	(43)	(81)	(86)
Net amortization	7	4	15	7
Net cost (income)	1	(5)	3	(10)
Pension Plans [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	15	15	30	29
Interest cost	36	36	71	72
Expected return on plan assets	(55)	(58)	(110)	(117)
Net amortization	11	4	22	9
Net cost (income)	7	(3)	13	(7)
Pension Plans [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	2	5	4
Interest cost	4	5	8	9
Expected return on plan assets	(7)	(7)	(13)	(14)
Net amortization	2		3	1
Net cost (income)	2		3
Pension Plans [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	2	5	4
Interest cost	4	5	9	9
Expected return on plan assets	(6)	(6)	(12)	(12)
Net amortization	1		2	1
Net cost (income)	2	1	4	2
Other Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost	6	5	11	10
Interest cost	21	23	42	46
Expected return on plan assets	(15)	(16)	(30)	(32)
Net amortization	5	5	10	10
Net cost (income)	17	17	33	34
Other Postretirement Benefits [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	2	3	3
Interest cost	6	6	11	12
Expected return on plan assets	(6)	(7)	(12)	(13)
Net amortization	1	1	3	3
Net cost (income)	3	2	5	5
Other Postretirement Benefits [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	2	3	4
Interest cost	10	10	19	20
Expected return on plan assets	(7)	(7)	(14)	(15)
Net amortization	2	2	5	5
Net cost (income)	7	7	13	14
Other Postretirement Benefits [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	1	1	1
Interest cost	1	1	2	2
Expected return on plan assets	(1)	(1)	(1)	(1)
Net cost (income)	1	1	2	2
Other Postretirement Benefits [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	1	1	1
Interest cost	1	1	2	2
Expected return on plan assets	(1)	(1)	(1)	(1)
Net cost (income)	$ 1	$ 1	$ 2	$ 2

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Effective Tax Rate and Unrecognized Tax Benefits (Tables)

6 Months Ended

Jun. 30, 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		4			2			2			1			—			—
Tax positions from prior periods		(23	)		(3	)		(19	)		(1	)		(1	)		(2	)
Reductions due to settlements		(5	)		(2	)		(4	)		(1	)		—			1
Reductions due to expired statute of limitations		(3	)		—			(3	)		—			—			—
Balance as of June 30, 2012	$	93		$	29		$	23		$	2		$	4		$	2

Impact on effective tax rate

	As of June 30, 2012						As of December 31, 2011
	Georgia Power		Other Registrants		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	3	$	4	$	38	$	69
Tax positions not impacting the effective tax rate		20		33		55		51
Balance of unrecognized tax benefits	$	23	$	37	$	93	$	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		(6	)		(2	)		(9	)
Interest accrued during the period		—			—			—
Balance as of June 30, 2012	$	—		$	1		$	1

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Consolidated Net Income	$ 639,000,000	$ 620,000,000	$ 1,023,000,000	$ 1,058,000,000
Net Income After Dividends on Preferred and Preference Stock	623,000,000	604,000,000	991,000,000	1,026,000,000
Qualifying hedges:
Changes in fair value, net of tax	(10,000,000)		(7,000,000)	3,000,000
Reclassification adjustment for amounts included in net income, net of tax	2,000,000		4,000,000	3,000,000
Marketable securities:
Change in fair value, net of tax of $-, $2, $- and $1, respectively		3,000,000		2,000,000
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $(1), $1 and $1, respectively	1,000,000	1,000,000	2,000,000
Total other comprehensive income (loss)	(7,000,000)	4,000,000	(1,000,000)	8,000,000
Dividends on preferred and preference stock of subsidiaries	(16,000,000)	(16,000,000)	(32,000,000)	(32,000,000)
Consolidated Comprehensive Income	616,000,000	608,000,000	990,000,000	1,034,000,000
Alabama Power [Member]
Consolidated Net Income	195,000,000	200,000,000	331,000,000	362,000,000
Net Income After Dividends on Preferred and Preference Stock	185,000,000	190,000,000	311,000,000	342,000,000
Qualifying hedges:
Changes in fair value, net of tax	(11,000,000)	1,000,000	(7,000,000)	3,000,000
Reclassification adjustment for amounts included in net income, net of tax		(2,000,000)		(2,000,000)
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	(11,000,000)	(1,000,000)	(7,000,000)	1,000,000
Dividends on preferred and preference stock of subsidiaries	(10,000,000)	(10,000,000)	(20,000,000)	(20,000,000)
Consolidated Comprehensive Income	174,000,000	189,000,000	304,000,000	343,000,000
Georgia Power [Member]
Consolidated Net Income	300,000,000	314,000,000	471,000,000	524,000,000
Net Income After Dividends on Preferred and Preference Stock	295,000,000	309,000,000	462,000,000	515,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax			1,000,000	1,000,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)			1,000,000	1,000,000
Dividends on preferred and preference stock of subsidiaries	(5,000,000)	(5,000,000)	(9,000,000)	(9,000,000)
Consolidated Comprehensive Income	295,000,000	309,000,000	463,000,000	516,000,000
Gulf Power [Member]
Consolidated Net Income	36,513,000	34,902,000	58,730,000	48,144,000
Net Income After Dividends on Preferred and Preference Stock	34,963,000	33,352,000	55,629,000	45,043,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	143,000	144,000	286,000	287,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	143,000	144,000	286,000	287,000
Dividends on preferred and preference stock of subsidiaries	(1,550,000)	(1,550,000)	(3,101,000)	(3,101,000)
Consolidated Comprehensive Income	35,106,000	33,496,000	55,915,000	45,330,000
Mississippi Power [Member]
Consolidated Net Income	35,460,000	25,716,000	61,148,000	40,766,000
Net Income After Dividends on Preferred and Preference Stock	35,027,000	25,283,000	60,282,000	39,900,000
Qualifying hedges:
Changes in fair value, net of tax		13,000	(478,000)	11,000
Reclassification adjustment for amounts included in net income, net of tax	212,000		238,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	212,000	13,000	(240,000)	11,000
Dividends on preferred and preference stock of subsidiaries	(433,000)	(433,000)	(866,000)	(866,000)
Consolidated Comprehensive Income	35,239,000	25,296,000	60,042,000	39,911,000
Southern Power [Member]
Consolidated Net Income	46,602,000	44,601,000	75,918,000	82,344,000
Qualifying hedges:
Changes in fair value, net of tax	88,000	(35,000)	(186,000)	608,000
Reclassification adjustment for amounts included in net income, net of tax	1,529,000	1,631,000	3,039,000	3,261,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	1,617,000	1,596,000	2,853,000	3,869,000
Consolidated Comprehensive Income	$ 48,219,000	$ 46,197,000	$ 78,771,000	$ 86,213,000

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Operating Activities:
Consolidated net income	$ 1,023,000,000	$ 1,058,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	1,064,000,000	1,011,000,000
Deferred income taxes	327,000,000	427,000,000
Allowance for equity funds used during construction	(63,000,000)	(71,000,000)
Pension, postretirement, and other employee benefits	13,000,000	(38,000,000)
Stock based compensation expense	35,000,000	27,000,000
Retail fuel cost over recovery - long-term	44,000,000
Other, net	(17,000,000)	(6,000,000)
Changes in certain current assets and liabilities --
-Receivables	(55,000,000)	(156,000,000)
-Fossil fuel stock	(305,000,000)	81,000,000
-Other current assets	(53,000,000)	(106,000,000)
-Accounts payable	(167,000,000)	58,000,000
-Accrued taxes	45,000,000	300,000,000
-Accrued compensation	(216,000,000)	(193,000,000)
-Retail fuel cost over recovery - short-term	101,000,000	(6,000,000)
-Other current liabilities	(19,000,000)	3,000,000
Net cash provided from operating activities	1,757,000,000	2,389,000,000
Investing Activities:
Property additions	(2,356,000,000)	(2,126,000,000)
Investment of restricted cash	(230,000,000)	(3,000,000)
Distribution of restricted cash	49,000,000	61,000,000
Nuclear decommissioning trust fund purchases	(576,000,000)	(1,405,000,000)
Nuclear decommissioning trust fund sales	574,000,000	1,401,000,000
Proceeds from property sales	2,000,000	17,000,000
Cost of removal, net of salvage	(58,000,000)	(68,000,000)
Change in construction payables	(134,000,000)	37,000,000
Other investing activities	(62,000,000)	22,000,000
Net cash used for investing activities	(2,791,000,000)	(2,064,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(406,000,000)	(440,000,000)
Proceeds --
Long-term debt issuances	2,487,000,000	1,950,000,000
Interest-bearing refundable deposit related to asset sale	150,000,000
Common stock issuances	316,000,000	482,000,000
Redemptions --
Long-term debt	(1,319,000,000)	(1,504,000,000)
Payment of common stock dividends	(837,000,000)	(787,000,000)
Payment of dividends on preferred and preference stock of subsidiaries	(32,000,000)	(32,000,000)
Other financing activities	19,000,000	(4,000,000)
Net cash provided from (used for) financing activities	378,000,000	(335,000,000)
Net Change in Cash and Cash Equivalents	(656,000,000)	(10,000,000)
Cash and Cash Equivalents at Beginning of Period	1,315,000,000	447,000,000
Cash and Cash Equivalents at End of Period	659,000,000	437,000,000
Cash paid (received) during the period for --
Interest (net capitalized for 2012 and 2011, respectively)	391,000,000	419,000,000
Income taxes, net	(34,000,000)	(355,000,000)
Noncash transactions - accrued property additions at end of period	488,000,000	407,000,000
Alabama Power [Member]
Operating Activities:
Consolidated net income	331,000,000	362,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	380,000,000	373,000,000
Deferred income taxes	85,000,000	174,000,000
Allowance for equity funds used during construction	(9,000,000)	(11,000,000)
Pension, postretirement, and other employee benefits	(8,000,000)	(24,000,000)
Stock based compensation expense	6,000,000	4,000,000
Other, net	(24,000,000)	(3,000,000)
Changes in certain current assets and liabilities --
-Receivables	(46,000,000)	(57,000,000)
-Fossil fuel stock	(125,000,000)	13,000,000
-Materials and supplies	(6,000,000)	(5,000,000)
-Other current assets	(31,000,000)	(66,000,000)
-Accounts payable	(145,000,000)	(77,000,000)
-Accrued taxes	128,000,000	193,000,000
-Accrued compensation	(45,000,000)	(52,000,000)
-Other current liabilities	(10,000,000)	(5,000,000)
Net cash provided from operating activities	481,000,000	819,000,000
Investing Activities:
Property additions	(436,000,000)	(485,000,000)
Distribution of restricted cash from pollution control revenue bonds		11,000,000
Nuclear decommissioning trust fund purchases	(88,000,000)	(252,000,000)
Nuclear decommissioning trust fund sales	88,000,000	252,000,000
Cost of removal, net of salvage	(7,000,000)	(47,000,000)
Change in construction payables	(12,000,000)	(14,000,000)
Other investing activities	(9,000,000)	(22,000,000)
Net cash used for investing activities	(464,000,000)	(557,000,000)
Proceeds --
Capital contributions from parent company	11,000,000	5,000,000
Senior notes issuances	250,000,000	700,000,000
Redemptions --
Pollution control revenue bonds	(1,000,000)
Senior notes	(250,000,000)	(650,000,000)
Payment of preferred and preference stock dividends	(20,000,000)	(20,000,000)
Payment of common stock dividends	(270,000,000)	(277,000,000)
Other financing activities	(3,000,000)	(12,000,000)
Net cash provided from (used for) financing activities	(283,000,000)	(254,000,000)
Net Change in Cash and Cash Equivalents	(266,000,000)	8,000,000
Cash and Cash Equivalents at Beginning of Period	344,000,000	154,000,000
Cash and Cash Equivalents at End of Period	78,000,000	162,000,000
Cash paid (received) during the period for --
Interest (net capitalized for 2012 and 2011, respectively)	136,000,000	141,000,000
Income taxes, net	31,000,000	(100,000,000)
Noncash transactions - accrued property additions at end of period	7,000,000	14,000,000
Georgia Power [Member]
Operating Activities:
Consolidated net income	471,000,000	524,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	458,000,000	426,000,000
Deferred income taxes	128,000,000	189,000,000
Allowance for equity funds used during construction	(26,000,000)	(47,000,000)
Retail fuel cost over recovery - long-term	44,000,000
Other, net	(3,000,000)	(73,000,000)
Deferred expenses	26,000,000	33,000,000
Changes in certain current assets and liabilities --
-Receivables	19,000,000	(100,000,000)
-Fossil fuel stock	(147,000,000)	55,000,000
-Prepaid income taxes	13,000,000	77,000,000
-Other current assets	8,000,000	(14,000,000)
-Accounts payable	(37,000,000)	60,000,000
-Accrued taxes	(77,000,000)	(123,000,000)
-Accrued compensation	(60,000,000)	(42,000,000)
-Retail fuel cost over recovery - short-term	55,000,000
-Other current liabilities	43,000,000	46,000,000
Net cash provided from operating activities	915,000,000	1,011,000,000
Investing Activities:
Property additions	(812,000,000)	(931,000,000)
Investment of restricted cash	(234,000,000)
Distribution of restricted cash	49,000,000
Nuclear decommissioning trust fund purchases	(488,000,000)	(1,152,000,000)
Nuclear decommissioning trust fund sales	486,000,000	1,149,000,000
Cost of removal, net of salvage	(34,000,000)	(9,000,000)
Change in construction payables, net of joint owner portion	(161,000,000)	34,000,000
Other investing activities	(14,000,000)	(12,000,000)
Net cash used for investing activities	(1,208,000,000)	(921,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(513,000,000)	(253,000,000)
Proceeds --
Capital contributions from parent company	18,000,000	183,000,000
Pollution control revenue bonds issuances	234,000,000	250,000,000
Senior notes issuances	1,500,000,000	550,000,000
Other long-term debt issuances		250,000,000
Redemptions --
Pollution control revenue bonds	(49,000,000)	(197,000,000)
Senior notes		(101,000,000)
Other long-term debt	(250,000,000)	(300,000,000)
Payment of preferred and preference stock dividends	(9,000,000)	(9,000,000)
Payment of common stock dividends	(454,000,000)	(448,000,000)
Other financing activities	(9,000,000)	(2,000,000)
Net cash provided from (used for) financing activities	468,000,000	(77,000,000)
Net Change in Cash and Cash Equivalents	175,000,000	13,000,000
Cash and Cash Equivalents at Beginning of Period	13,000,000	8,000,000
Cash and Cash Equivalents at End of Period	188,000,000	21,000,000
Cash paid (received) during the period for --
Interest (net capitalized for 2012 and 2011, respectively)	156,000,000	177,000,000
Income taxes, net	44,000,000	(15,000,000)
Noncash transactions - accrued property additions at end of period	234,000,000	299,000,000
Gulf Power [Member]
Operating Activities:
Consolidated net income	58,730,000	48,144,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	71,707,000	67,129,000
Deferred income taxes	70,153,000	20,411,000
Allowance for equity funds used during construction	(2,973,000)	(4,657,000)
Pension, postretirement, and other employee benefits	2,383,000	(993,000)
Stock based compensation expense	1,044,000	789,000
Other, net	7,503,000	(3,496,000)
Changes in certain current assets and liabilities --
-Receivables	(18,580,000)	(33,496,000)
-Prepayments	1,813,000	1,373,000
-Fossil fuel stock	3,982,000	21,458,000
-Materials and supplies	(4,100,000)	(4,088,000)
-Prepaid income taxes	(3,566,000)	35,287,000
-Other current assets		23,000
-Accounts payable	(17,481,000)	(1,710,000)
-Accrued taxes	6,788,000	28,851,000
-Accrued compensation	(6,239,000)	(6,132,000)
-Over recovered regulatory clause revenues	25,099,000	4,027,000
-Other current liabilities	(1,659,000)	2,274,000
Net cash provided from operating activities	194,604,000	175,194,000
Investing Activities:
Property additions	(169,462,000)	(168,986,000)
Cost of removal, net of salvage	(14,817,000)	(6,616,000)
Change in construction payables	3,661,000	(31,000)
Payments pursuant to long-term service agreements	(4,086,000)	(4,162,000)
Other investing activities	18,000	222,000
Net cash used for investing activities	(184,686,000)	(179,573,000)
Financing Activities:
Increase (decrease) in notes payable, net	5,980,000	1,392,000
Proceeds --
Capital contributions from parent company	954,000	1,014,000
Common stock issuances	40,000,000	50,000,000
Senior notes issuances	100,000,000	125,000,000
Redemptions --
Senior notes	(91,363,000)	(352,000)
Other long-term debt		(110,000,000)
Payment of preferred and preference stock dividends	(3,101,000)	(3,101,000)
Payment of common stock dividends	(57,900,000)	(55,000,000)
Other financing activities	(653,000)	(3,679,000)
Net cash provided from (used for) financing activities	(6,083,000)	5,274,000
Net Change in Cash and Cash Equivalents	3,835,000	895,000
Cash and Cash Equivalents at Beginning of Period	17,328,000	16,434,000
Cash and Cash Equivalents at End of Period	21,163,000	17,329,000
Cash paid (received) during the period for --
Interest (net capitalized for 2012 and 2011, respectively)	30,100,000	26,288,000
Income taxes, net	(32,848,000)	(46,824,000)
Noncash transactions - accrued property additions at end of period	27,127,000	14,924,000
Mississippi Power [Member]
Operating Activities:
Consolidated net income	61,148,000	40,766,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	43,955,000	43,032,000
Deferred income taxes	1,280,000	(8,136,000)
Allowance for equity funds used during construction	(25,697,000)	(8,122,000)
Pension, postretirement, and other employee benefits	3,993,000	1,601,000
Stock based compensation expense	1,344,000	1,060,000
Other, net	(2,648,000)	(5,584,000)
Convertible investment tax credits	13,974,000	29,556,000
Hedge settlements	(15,983,000)
Changes in certain current assets and liabilities --
-Receivables	(12,424,000)	(8,041,000)
-Fossil fuel stock	(32,797,000)	(8,838,000)
-Materials and supplies	212,000	(603,000)
-Prepaid income taxes	11,974,000	17,075,000
-Other current assets	(7,281,000)	1,021,000
-Accounts payable	3,408,000	17,927,000
-Accrued taxes	(16,785,000)	(6,227,000)
-Accrued compensation	(7,002,000)	(7,064,000)
-Over recovered regulatory clause revenues	15,871,000	(10,748,000)
-Other current liabilities	7,640,000	2,066,000
Net cash provided from operating activities	44,182,000	90,741,000
Investing Activities:
Property additions	(763,641,000)	(365,261,000)
Distribution of restricted cash		50,000,000
Cost of removal, net of salvage	(1,217,000)	(4,339,000)
Change in construction payables	57,283,000	31,949,000
Capital grant proceeds	6,146,000	91,650,000
Other investing activities	(9,690,000)	(2,217,000)
Net cash used for investing activities	(711,119,000)	(198,218,000)
Proceeds --
Capital contributions from parent company	277,633,000	100,878,000
Interest-bearing refundable deposit related to asset sale	150,000,000
Senior notes issuances	400,000,000
Other long-term debt issuances		75,000,000
Redemptions --
Capital leases	(633,000)	(705,000)
Other long-term debt	(165,000,000)	(130,000,000)
Payment of preferred and preference stock dividends	(866,000)	(866,000)
Payment of common stock dividends	(53,400,000)	(37,750,000)
Other financing activities	998,000	(134,000)
Net cash provided from (used for) financing activities	608,732,000	6,423,000
Net Change in Cash and Cash Equivalents	(58,205,000)	(101,054,000)
Cash and Cash Equivalents at Beginning of Period	211,585,000	160,779,000
Cash and Cash Equivalents at End of Period	153,380,000	59,725,000
Cash paid (received) during the period for --
Interest (net capitalized for 2012 and 2011, respectively)	16,603,000	9,505,000
Income taxes, net	(7,756,000)	(32,648,000)
Noncash transactions - accrued property additions at end of period	193,184,000	70,772,000
Southern Power [Member]
Operating Activities:
Consolidated net income	75,918,000	82,344,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	71,834,000	65,877,000
Deferred income taxes	58,921,000	12,315,000
Other, net	1,927,000	3,590,000
Convertible investment tax credits	1,750,000	62,298,000
Deferred revenues	(16,431,000)	(23,776,000)
Mark-to-market adjustments	(3,847,000)	853,000
Changes in certain current assets and liabilities --
-Receivables	(30,101,000)	(19,276,000)
-Fossil fuel stock	(3,301,000)	41,000
-Materials and supplies	(7,761,000)	(4,431,000)
-Prepaid income taxes	(32,804,000)	1,282,000
-Other current assets	(377,000)	1,810,000
-Accounts payable	(494,000)	3,079,000
-Accrued taxes	13,295,000	7,737,000
-Accrued interest	409,000	50,000
-Other current liabilities	(195,000)	(497,000)
Net cash provided from operating activities	128,743,000	193,296,000
Investing Activities:
Plant acquisition	(86,500,000)
Property additions	(67,846,000)	(162,004,000)
Change in construction payables	(1,168,000)	(14,231,000)
Payments pursuant to long-term service agreements	(36,316,000)	(24,874,000)
Other investing activities	153,000	(3,212,000)
Net cash used for investing activities	(191,677,000)	(204,321,000)
Financing Activities:
Increase (decrease) in notes payable, net	107,147,000	(68,941,000)
Proceeds --
Capital contributions from parent company	490,000	120,574,000
Other long-term debt issuances	3,590,000
Redemptions --
Other long-term debt	(650,000)	(3,116,000)
Payment of common stock dividends	(63,500,000)	(45,600,000)
Other financing activities	2,746,000	146,000
Net cash provided from (used for) financing activities	49,823,000	3,063,000
Net Change in Cash and Cash Equivalents	(13,111,000)	(7,962,000)
Cash and Cash Equivalents at Beginning of Period	16,943,000	14,204,000
Cash and Cash Equivalents at End of Period	3,832,000	6,242,000
Cash paid (received) during the period for --
Interest (net capitalized for 2012 and 2011, respectively)	21,461,000	37,413,000
Income taxes, net	13,708,000	(31,142,000)
Noncash transactions - accrued property additions at end of period	$ 46,922,000	$ 21,077,000

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Acquisitions

6 Months Ended

Jun. 30, 2012

Business Combinations [Abstract]

ACQUISITIONS

(I) ACQUISITIONS

Apex Nevada Solar, LLC Acquisition

On June 29, 2012, Southern Power and Turner Renewable Energy, Inc., through a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Apex Nevada Solar, LLC (Apex) from Sun Edison, LLC, the original developer of the project. Apex constructed and owns a 20-MW solar photovoltaic facility in North Las Vegas, Nevada. Commercial operation of the solar facility was declared by Apex on July 21, 2012. The output of the plant is contracted under a PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that began in 2012 and expires in 2037. This PPA will be accounted for as an operating lease. The acquisition is in accordance with Southern Power’s overall growth strategy.

Southern Power’s acquisition of Apex included cash consideration of $102 million, of which $86.5 million was paid at closing. The remaining $15.5 million will be paid upon achievement of certain milestones. Due to the proximity of the closing date to June 30, 2012, there has not been sufficient time to complete the final allocation of the purchase price to individual assets. As of June 30, 2012, the entire purchase price is reflected in CWIP on Southern Power’s Condensed Balance Sheet herein.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	874,796,883

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Segment and Related Information

6 Months Ended

Jun. 30, 2012

Segment and Related Information [Abstract]

SEGMENT AND RELATED INFORMATION

(J) SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $106 million and $218 million for the three and six months ended June 30, 2012, respectively, and $71 million and $154 million for the three and six months ended June 30, 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 June 30, 2012:
Operating revenues	$	3,989	$	286	$	(109)		$	4,166	$	35	$	(20)	$	4,181
Segment net income (loss)(a)		549		47		—			596		27		—		623
Six Months Ended June 30, 2012:
Operating revenues	$	7,438	$	539	$	(222)		$	7,755	$	73	$	(43)	$	7,785
Segment net income (loss)(a)		888		76		—			964		28		(1)		991
Total assets at June 30, 2012	$	56,726	$	3,785	$	(126)		$	60,385	$	1,132	$	(620)	$	60,897
Three Months Ended June 30, 2011:
Operating revenues	$	4,291	$	305	$	(93)		$	4,503	$	38	$	(20)	$	4,521
Segment net income (loss)(a)		559		44		—			603		1		—		604
Six Months Ended June 30, 2011:
Operating revenues	$	8,101	$	587	$	(191)		$	8,497	$	76	$	(40)	$	8,533
Segment net income (loss)(a)		943		82		—			1,025		2		(1)		1,026
Total assets at December 31, 2011	$	54,622	$	3,581	$	(127	)	$	58,076	$	1,592	$	(401)	$	59,267

(a) 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 June 30, 2012	$	3,597	$	415	$	154	$	4,166
Three Months Ended June 30, 2011		3,842		507		154		4,503
Six Months Ended June 30, 2012	$	6,689	$	764	$	302	$	7,755
Six Months Ended June 30, 2011		7,238		956		303		8,497

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Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Net cash paid for capitalized interest	$ 41,000	$ 35,000
Alabama Power [Member]
Net cash paid for capitalized interest	3,000	5,000
Georgia Power [Member]
Net cash paid for capitalized interest	11,000	17,000
Gulf Power [Member]
Net cash paid for capitalized interest	1,185	1,856
Mississippi Power [Member]
Interest paid	29,433	12,050
Net cash paid for capitalized interest	12,476	2,572
Southern Power [Member]
Net cash paid for capitalized interest	$ 12,941	$ 8,855

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Stockholder's Equity

6 Months Ended

Jun. 30, 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 June 30, 2012	Three Months Ended June 30, 2011	Six Months Ended June 30, 2012	Six Months Ended June 30, 2011
	(in millions)
As reported shares	872	855	870	851
Effect of options and performance share award units	8	7	9	7
Diluted shares	880	862	879	858

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for both the three months and six months ended June 30, 2012 and 2011.

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	—	—	991	—	991
Other comprehensive income (loss)	—	—	(1)	—	(1)
Stock issued	9,697	—	395	—	395
Cash dividends on common stock	—	—	(837)	—	(837)
Other	—	(26)	(2)	—	(2)
Balance at June 30, 2012	875,361	(565)	$18,124	$707	$18,831
Balance at December 31, 2010	843,814	(474)	$16,202	$707	$16,909
Net income after dividends on preferred and preference stock	—	—	1,026	—	1,026
Other comprehensive income (loss)	—	—	8	—	8
Stock issued	14,337	—	533	—	533
Cash dividends on common stock	—	—	(787)	—	(787)
Other	—	(25)	—	—	—
Balance at June 30, 2011	858,151	(499)	$16,982	$707	$17,689

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Fair Value Measurements

6 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

(C) FAIR VALUE MEASUREMENTS

As of June 30, 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 June 30, 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		—		12		—		12
Nuclear decommissioning trusts (a)		450		784		—		1,234
Cash equivalents and restricted cash		512		—		—		512
Other investments		1		53		15		69
Total	$	963	$	873	$	15	$	1,851
Liabilities:
Energy-related derivatives	$	—	$	194	$	—	$	194
Interest rate derivatives		—		28		—		28
Foreign currency derivatives		—		2		—		2
Total	$	—	$	224	$	—	$	224
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Nuclear decommissioning trusts: (b )
Domestic equity		274		60		—		334
Foreign equity (d )		25		49		—		74
U.S. Treasury and government agency securities		—		23		—		23
Corporate bonds		—		101		—		101
Mortgage and asset backed securities		—		25		—		25
Other		—		12		—		12
Total	$	299	$	273	$	—	$	572
Liabilities:
Energy-related derivatives	$	—	$	35	$	—	$	35
Interest rate derivatives		—		28		—		28
Total	$	—	$	63	$	—	$	63

	Fair Value Measurements Using
As of June 30, 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	$	—	$	17	$	—	$	17
Nuclear decommissioning trusts: (b) (c)
Domestic equity		151		1		—		152
Foreign equity (d)		—		102		—		102
U.S. Treasury and government agency securities		—		45		—		45
Municipal bonds		—		103		—		103
Corporate bonds		—		120		—		120
Mortgage and asset backed securities		—		118		—		118
Other		—		24		—		24
Cash equivalents		149		—		—		149
Total	$	300	$	530	$	—	$	830
Liabilities:
Energy-related derivatives	$	—	$	75	$	—	$	75
Gulf Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents		15		—		—		15
Total	$	15	$	2	$	—	$	17
Liabilities:
Energy-related derivatives	$	—	$	39	$	—	$	39
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents		146		—		—		146
Total	$	146	$	1	$	—	$	147
Liabilities:
Energy-related derivatives	$	—	$	38	$	—	$	38
Foreign currency derivatives		—		2		—		2
Total	$	—	$	40	$	—	$	40
Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	7

(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 payables related to the securities lending program. As of June 30, 2012, approximately $38 million of the fair market value of Georgia Power’s nuclear decommissioning trust funds’ securities were on loan and pledged to creditors under the funds’ managers’ securities lending program.

(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 June 30, 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 June 30, 2012:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	8	None	Daily	1 to 3 days
Other — commingled funds		73	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		91	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		512	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Other — commingled funds		49	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		91	None	Daily	15 days
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds		8	None	Daily	1 to 3 days
Other — commingled funds		24	None	Daily	Not applicable
Cash equivalents:
Money market funds		149	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds		15	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds		146	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 and six months ended June 30, 2012, the change in fair value of the funds, which includes reinvested interest and dividends and excludes the Funds’ expenses, is recorded in the regulatory liability and was a decrease of $22 million and an increase of $64 million, respectively, for Southern Company, a decrease of $16 million and an increase of $33 million, respectively, for Alabama Power, and a decrease of $6 million and an increase of $31 million, respectively, 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 June 30, 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	$21,451	$23,477
Alabama Power	$  6,130	$  6,893
Georgia Power	$  9,856	$10,703
Gulf Power	$  1,246	$  1,384
Mississippi Power	$  1,576	$  1,690
Southern Power	$  1,306	$  1,416

The fair values are primarily 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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Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2012

Retirement Benefits [Abstract]

Pension Plans and Postretirement Plans

Pension Plans	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended June 30, 2012
Service cost	$   49	$ 11	$ 15	$   3	$ 3
Interest cost	99	24	36	4	4
Expected return on plan assets	(146)	(41)	(55)	(7)	(6)
Net amortization	31	7	11	2	1
Net cost (income)	$   33	$   1	$7	$   2	$ 2
Six Months Ended June 30, 2012
Service cost	$   99	$ 22	$ 30	$   5	$  5
Interest cost	197	47	71	8	9
Expected return on plan assets	(291)	(81)	(110)	(13)	(12)
Net amortization	62	15	22	3	2
Net cost (income)	$  67	$   3	$ 13	$   3	$  4
Three Months Ended June 30, 2011
Service cost	$   46	$ 10	$ 15	$  2	$  2
Interest cost	97	24	36	5	5
Expected return on plan assets	(152)	(43)	(58)	(7)	(6)
Net amortization	13	4	4	—	—
Net cost (income)	$    4	$  (5)	$ (3)	$—	$  1
Six Months Ended June 30, 2011
Service cost	$    92	$  21	$  29	$  4	$  4
Interest cost	195	48	72	9	9
Expected return on plan assets	(304)	(86)	(117)	(14)	(12)
Net amortization	26	7	9	1	1
Net cost (income)	$     9	$ (10)	$  (7)	$ —	$  2

Postretirement Benefits	Southern Company				Alabama Power				Georgia Power				Gulf Power				Mississippi Power
	(in millions)
Three Months Ended June 30, 2012
Service cost		$	6			$	2			$	2			$	1			$	1
Interest cost			21				6				10				1				1
Expected return on plan assets			(15	)			(6	)			(7	)			(1	)			(1	)
Net amortization			5				1				2				—				—
Net cost (income)		$	17			$	3			$	7			$	1			$	1
Six Months Ended June 30, 2012
Service cost		$	11			$	3			$	3			$	1			$	1
Interest cost			42				11				19				2				2
Expected return on plan assets			(30	)			(12	)			(14	)			(1	)			(1	)
Net amortization			10				3				5				—				—
Net cost (income)		$	33			$	5			$	13			$	2			$	2
Three Months Ended June 30, 2011
Service cost		$	5			$	2			$	2			$	1			$	1
Interest cost			23				6				10				1				1
Expected return on plan assets			(16	)			(7	)			(7	)			(1	)			(1	)
Net amortization			5				1				2				—				—
Net cost (income)		$	17			$	2			$	7			$	1			$	1
Six Months Ended June 30, 2011
Service cost		$	10			$	3			$	4			$	1			$	1
Interest cost			46				12				20				2				2
Expected return on plan assets			(32	)			(13	)			(15	)			(1	)			(1	)
Net amortization			10				3				5				—				—
Net cost (income)		$	34			$	5			$	14			$	2			$	2

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Fair Value Measurements (Policies)

6 Months Ended

Jun. 30, 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 June 30, 2012, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu		Longest Hedge Date		Longest Non-Hedge Date
	(in millions)
Southern Company		242		2017		2017
Alabama Power		43		2017		—
Georgia Power		96		2017		—
Gulf Power		51		2017		—
Mississippi Power		34		2017		—
Southern Power		18		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 8 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 3 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 1 million mmBtu for Mississippi Power, and 2 million mmBtu for Southern Power.

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending June 30, 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 June 30, 2012, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received		Interest Rate Paid		Hedge Maturity Date		Fair Value Gain (Loss) June 30, 2012
	(in millions)								(in millions)
Cash flow hedges of forecasted transactions
Alabama Power	$	300		3-month LIBOR		2.90%(a)		December 2022	$(28)
Fair value hedges of existing debt
Southern Company		350		4.15%		3-month LIBOR  + 1.96%(a)		May 2014	12
Total	$	650							$(16)

(a) 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 June 30, 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 June 30, 2013	Total Deferred Gains (Losses) Amortized Through
	(in millions)
Southern Company	$(17)	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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Effective Tax Rate and Unrecognized Tax Benefits

6 Months Ended

Jun. 30, 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 is typically lower than the statutory rate due to its employee stock plans’ dividend deduction and non-taxable AFUDC equity.

Southern Company’s effective tax rate was 34.1% for the six months ended June 30, 2012 compared to 35.4% for the corresponding period in 2011. The decrease was primarily related to state income tax credits. See “Unrecognized Tax Benefits” herein for additional information.

Alabama Power

Alabama Power’s effective tax rate was 38.9% for the six months ended June 30, 2012 compared to 38.5% 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 34.2% for the six months ended June 30, 2012 compared to 34.8% for the corresponding period in 2011. The decrease was primarily related to state income tax credits, partially offset by a decrease in non-taxable AFUDC equity. See “Unrecognized Tax Benefits” herein for additional information.

Gulf Power

Gulf Power’s effective tax rate was 36.6% for the six months ended June 30, 2012 compared to 35.9% for the corresponding period in 2011. The increase was primarily due to a decrease in non-taxable AFUDC equity.

Mississippi Power

Mississippi Power’s effective tax rate was 25.2% for the six months ended June 30, 2012 compared to 32.6% for the corresponding period in 2011. The decrease was primarily due to an increase in non-taxable AFUDC equity related to the Kemper IGCC construction.

Southern Power

Southern Power’s effective tax rate was 35.9% for the six months ended June 30, 2012 compared to 35.3% for the corresponding period in 2011. The increase was due to less tax benefits from convertible investment tax credits associated with qualifying construction activity.

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		4			2			2			1			—			—
Tax positions from prior periods		(23	)		(3	)		(19	)		(1	)		(1	)		(2	)
Reductions due to settlements		(5	)		(2	)		(4	)		(1	)		—			1
Reductions due to expired statute of limitations		(3	)		—			(3	)		—			—			—
Balance as of June 30, 2012	$	93		$	29		$	23		$	2		$	4		$	2

The tax positions from current periods relate primarily to state income 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 primarily relate to state income tax credits. The 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 June 30, 2012						As of December 31, 2011
	Georgia Power		Other Registrants		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	3	$	4	$	38	$	69
Tax positions not impacting the effective tax rate		20		33		55		51
Balance of unrecognized tax benefits	$	23	$	37	$	93	$	120

The tax positions impacting the effective tax rate primarily relate to state income 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		(6	)		(2	)		(9	)
Interest accrued during the period		—			—			—
Balance as of June 30, 2012	$	—		$	1		$	1

All of the registrants classify interest on tax uncertainties as interest expense. The interest reclassified due to settlements is primarily associated with state income tax credits and 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. In August 2011, the IRS issued a revenue procedure, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for transmission and distribution property. 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. In December 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 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

6 Months Ended

Jun. 30, 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 June 30, 2012, including expiration dates:

	Expires					Executable Term Loans		Due Within  One Year(a)
Company	2012	2013	2014 and Beyond(b)	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	37	101	1,150	1,288	1,288	51	—	51	52
Georgia Power	—	—	1,750	1,750	1,745	—	—	—	—
Gulf Power	20	60	195	275	275	45	—	45	35
Mississippi Power	41	95	165	301	301	25	41	66	70
Southern Power	—	—	500	500	500	—	—	—	—
Other	—	50	—	50	50	25	—	25	—
Total	$98	$306	$4,760	$5,164	$5,159	$146	$  41	$187	$157

(a) Reflects facilities expiring on or before June 30, 2013.

(b) All remaining Gulf Power and Mississippi Power credit agreements in this column expire in 2014.

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Retirement Benefits

6 Months Ended

Jun. 30, 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 and six months ended June 30, 2012 and 2011 were as follows:

Pension Plans	Southern Company	Alabama Power	Georgia Power	Gulf Power	Mississippi   Power
	(in millions)
Three Months Ended June 30, 2012
Service cost	$   49	$ 11	$ 15	$   3	$ 3
Interest cost	99	24	36	4	4
Expected return on plan assets	(146)	(41)	(55)	(7)	(6)
Net amortization	31	7	11	2	1
Net cost (income)	$   33	$   1	$7	$   2	$ 2
Six Months Ended June 30, 2012
Service cost	$   99	$ 22	$ 30	$   5	$  5
Interest cost	197	47	71	8	9
Expected return on plan assets	(291)	(81)	(110)	(13)	(12)
Net amortization	62	15	22	3	2
Net cost (income)	$  67	$   3	$ 13	$   3	$  4
Three Months Ended June 30, 2011
Service cost	$   46	$ 10	$ 15	$  2	$  2
Interest cost	97	24	36	5	5
Expected return on plan assets	(152)	(43)	(58)	(7)	(6)
Net amortization	13	4	4	—	—
Net cost (income)	$    4	$  (5)	$ (3)	$—	$  1
Six Months Ended June 30, 2011
Service cost	$    92	$  21	$  29	$  4	$  4
Interest cost	195	48	72	9	9
Expected return on plan assets	(304)	(86)	(117)	(14)	(12)
Net amortization	26	7	9	1	1
Net cost (income)	$     9	$ (10)	$  (7)	$ —	$  2

Postretirement Benefits	Southern Company				Alabama Power				Georgia Power				Gulf Power				Mississippi Power
	(in millions)
Three Months Ended June 30, 2012
Service cost		$	6			$	2			$	2			$	1			$	1
Interest cost			21				6				10				1				1
Expected return on plan assets			(15	)			(6	)			(7	)			(1	)			(1	)
Net amortization			5				1				2				—				—
Net cost (income)		$	17			$	3			$	7			$	1			$	1
Six Months Ended June 30, 2012
Service cost		$	11			$	3			$	3			$	1			$	1
Interest cost			42				11				19				2				2
Expected return on plan assets			(30	)			(12	)			(14	)			(1	)			(1	)
Net amortization			10				3				5				—				—
Net cost (income)		$	33			$	5			$	13			$	2			$	2
Three Months Ended June 30, 2011
Service cost		$	5			$	2			$	2			$	1			$	1
Interest cost			23				6				10				1				1
Expected return on plan assets			(16	)			(7	)			(7	)			(1	)			(1	)
Net amortization			5				1				2				—				—
Net cost (income)		$	17			$	2			$	7			$	1			$	1
Six Months Ended June 30, 2011
Service cost		$	10			$	3			$	4			$	1			$	1
Interest cost			46				12				20				2				2
Expected return on plan assets			(32	)			(13	)			(15	)			(1	)			(1	)
Net amortization			10				3				5				—				—
Net cost (income)		$	34			$	5			$	14			$	2			$	2

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Derivatives

6 Months Ended

Jun. 30, 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 June 30, 2012, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu		Longest Hedge Date		Longest Non-Hedge Date
	(in millions)
Southern Company		242		2017		2017
Alabama Power		43		2017		—
Georgia Power		96		2017		—
Gulf Power		51		2017		—
Mississippi Power		34		2017		—
Southern Power		18		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 8 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 3 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 1 million mmBtu for Mississippi Power, and 2 million mmBtu for Southern Power.

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending June 30, 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 June 30, 2012, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received		Interest Rate Paid		Hedge Maturity Date		Fair Value Gain (Loss) June 30, 2012
	(in millions)								(in millions)
Cash flow hedges of forecasted transactions
Alabama Power	$	300		3-month LIBOR		2.90%(a)		December 2022	$(28)
Fair value hedges of existing debt
Southern Company		350		4.15%		3-month LIBOR  + 1.96%(a)		May 2014	12
Total	$	650							$(16)

(a) 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 June 30, 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 June 30, 2013	Total Deferred Gains (Losses) Amortized Through
	(in millions)
Southern Company	$(17)	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 June 30, 2012, the following foreign currency derivatives were outstanding:

	Notional Amount	Forward Rate	Hedge Maturity Date	Fair Value Gain (Loss) June 30, 2012
	(in millions)			(in millions)
Fair value hedges of firm commitments
Mississippi Power	EUR6.3	1.3850 Dollars per Euro(a)	Various through March 2014	$(1)
Derivatives not designated as hedges
Mississippi Power	EUR18.1	1.3186 Dollars per Euro (a)	N/A	(1)
Total	EUR24.4			$(2)

(a) Weighted Average

Derivative Financial Statement Presentation and Amounts

At June 30, 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 June 30, 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	$	14	$	1	$	13	$	—	$	—
Other deferred charges and assets		9		2		4		2		1
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	3	$	17	$	2	$	1		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		6		—		—		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	12	$	—	$	—	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	$	1	$	—	$	—	$	—	$	—	$	1
Total asset derivatives	$	36	$	3	$	17	$	2	$	1	$	1

Liability Derivatives at June 30, 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	$123	$26	$  52	$20	$25
Other deferred credits and liabilities	64	9	23	19	13
Total derivatives designated as hedging instruments for regulatory purposes	$187	$35	$75	$39	$38	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities	$    1	$—	$  —	$  —	$  —	$1
Interest rate derivatives:
Liabilities from risk management activities	28	28	—	—	—	—
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$  30	$28	$—	$—	$1	$1
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$    6	$—	$  —	$—	$—	$6
Foreign currency derivatives:
Liabilities from risk management activities	1	—	—	—	1	—
Total derivatives not designated as hedging instruments	$    7	$—	$  —	$  —	$  1	$6
Total liability derivatives	$224	$63	$75	$39	$40	$7

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

At June 30, 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		$(123)		$(26)		$(52)		$(20)		$(25)
Other regulatory assets, deferred		(64)		(9)		(23)		(19)		(13)
Other regulatory liabilities, current		14		1		13		—		—
Other regulatory liabilities, deferred		9		2		—		2		1
Other deferred credits and liabilities (a)		—		—		4		—		—
Total energy-related derivative gains (losses)		$(164)		$(32)		$(58)		$(37)		$(37)

(a) Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

For the three and six months ended June 30, 2012 and June 30, 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 and six months ended June 30, 2012 and June 30, 2011, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were immaterial and were offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there was no impact on Southern Company’s or Mississippi Power’s statements of income.

For the three months ended June 30, 2012 and 2011, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

Derivatives in Cash Flow	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
Interest rate derivatives	$    (18)	$    —	Interest expense, net of amounts capitalized	$            (4)	$            (1)
Alabama Power
Interest rate derivatives	$    (18)	$    —	Interest expense, net of amounts capitalized	$            —	$      3
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (1)	$            (1)
Southern Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (3)	$            (3)

For the six months ended June 30, 2012 and 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 Hedging	Gain (Loss) Recognized in OCI on Derivative		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Relationships	(Effective Portion)		Statements of Income Location	Amount
	2012	2011		2012	2011
	(in millions)			(in millions)
Southern Company
Energy-related derivatives	$    —	$       1	Fuel	$            —	$            —
Interest rate derivatives	(12)	4	Interest expense, net of amounts capitalized	(7)	(6)
Total	$    (12)	$         5		$            (7)	$            (6)
Alabama Power
Interest rate derivatives	$    (11)	$         4	Interest expense, net of amounts capitalized	$          —	$            3
Georgia Power
Interest rate derivatives	$    —	$    —	Interest expense, net of amounts capitalized	$            (2)	$            (2)
Mississippi Power
Interest rate derivatives	$    (1)	$    —	Interest expense, net of amounts capitalized	$            —	$            —
Southern Power
Energy-related derivatives	$    —	$       1	Fuel	$            —	$            —
Interest rate derivatives	—	—	Interest expense, net of amounts capitalized	(5)	(6)
Total	$    —	$       1		$            (5)	$            (6)

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

For the three and six months ended June 30, 2012, the net unrealized pre-tax gains from energy-related derivatives not designated as hedging instruments on Southern Company’s and Southern Power’s statements of income were $10 million and $4 million, respectively. For the three and six months ended June 30, 2011, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.

For the three and six months ended June 30, 2012, the pre-tax effects of foreign currency derivatives not designated as hedging instruments were recorded as regulatory assets and liabilities and were immaterial for Southern Company and Mississippi Power.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 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	$27	$6	$8	$6	$5	$2

At June 30, 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 $27 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 1) (USD $) Share data in Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Number of Common shares Issued [Member]	Jun. 30, 2011 Number of Common shares Issued [Member]	Jun. 30, 2012 Number of Common shares Treasury [Member]	Jun. 30, 2011 Number of Common shares Treasury [Member]	Jun. 30, 2012 Common Stockholders' Equity [Member]	Jun. 30, 2011 Common Stockholders' Equity [Member]	Jun. 30, 2012 Preferred and Preference Stock of Subsidiaries [Member]	Dec. 31, 2011 Preferred and Preference Stock of Subsidiaries [Member]	Jun. 30, 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	623,000,000	604,000,000	991,000,000	1,026,000,000					991,000,000	1,026,000,000
Other comprehensive income (loss)	(7,000,000)	4,000,000	(1,000,000)	8,000,000					(1,000,000)	8,000,000
Stock issued, shares					9,697	14,337
Stock issued			395,000,000	533,000,000					395,000,000	533,000,000
Cash dividends on common stock			(837,000,000)	(787,000,000)					(837,000,000)	(787,000,000)
Other			(2,000,000)						(2,000,000)
Other Share							(26)	(25)
Ending Balance	$ 18,831,000,000	$ 17,689,000,000	$ 18,831,000,000	$ 17,689,000,000					$ 18,124,000,000	$ 16,982,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000	$ 707,000,000
Ending Balance, Shares					(875,361)	(858,151)	(565)	(499)

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Stockholder's Equity (Tables)

6 Months Ended

Jun. 30, 2012

Stockholders' Equity [Abstract]

Earnings per Share

	Three Months Ended June 30, 2012	Three Months Ended June 30, 2011	Six Months Ended June 30, 2012	Six Months Ended June 30, 2011
	(in millions)
As reported shares	872	855	870	851
Effect of options and performance share award units	8	7	9	7
Diluted shares	880	862	879	858

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	—	—	991	—	991
Other comprehensive income (loss)	—	—	(1)	—	(1)
Stock issued	9,697	—	395	—	395
Cash dividends on common stock	—	—	(837)	—	(837)
Other	—	(26)	(2)	—	(2)
Balance at June 30, 2012	875,361	(565)	$18,124	$707	$18,831
Balance at December 31, 2010	843,814	(474)	$16,202	$707	$16,909
Net income after dividends on preferred and preference stock	—	—	1,026	—	1,026
Other comprehensive income (loss)	—	—	8	—	8
Stock issued	14,337	—	533	—	533
Cash dividends on common stock	—	—	(787)	—	(787)
Other	—	(25)	—	—	—
Balance at June 30, 2011	858,151	(499)	$16,982	$707	$17,689

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Segment and Related Information (Tables)

6 Months Ended

Jun. 30, 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 June 30, 2012:
Operating revenues	$	3,989	$	286	$	(109)		$	4,166	$	35	$	(20)	$	4,181
Segment net income (loss)(a)		549		47		—			596		27		—		623
Six Months Ended June 30, 2012:
Operating revenues	$	7,438	$	539	$	(222)		$	7,755	$	73	$	(43)	$	7,785
Segment net income (loss)(a)		888		76		—			964		28		(1)		991
Total assets at June 30, 2012	$	56,726	$	3,785	$	(126)		$	60,385	$	1,132	$	(620)	$	60,897
Three Months Ended June 30, 2011:
Operating revenues	$	4,291	$	305	$	(93)		$	4,503	$	38	$	(20)	$	4,521
Segment net income (loss)(a)		559		44		—			603		1		—		604
Six Months Ended June 30, 2011:
Operating revenues	$	8,101	$	587	$	(191)		$	8,497	$	76	$	(40)	$	8,533
Segment net income (loss)(a)		943		82		—			1,025		2		(1)		1,026
Total assets at December 31, 2011	$	54,622	$	3,581	$	(127	)	$	58,076	$	1,592	$	(401)	$	59,267

(a) 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 June 30, 2012	$	3,597	$	415	$	154	$	4,166
Three Months Ended June 30, 2011		3,842		507		154		4,503
Six Months Ended June 30, 2012	$	6,689	$	764	$	302	$	7,755
Six Months Ended June 30, 2011		7,238		956		303		8,497

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Derivatives (Details 1) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	$ 36
Liability Derivatives	224
Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(164)
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	(123)
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	(64)
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	14
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	9
Alabama Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	3
Liability Derivatives	63
Alabama Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(32)
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	(26)
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	(9)
Alabama Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, current [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	1
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	2
Georgia Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	17
Liability Derivatives	75
Georgia Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(58)
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	4
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	(52)
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	(23)
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	13
Gulf Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	2
Liability Derivatives	39
Gulf Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(37)
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	(20)
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	(19)
Gulf Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	2
Mississippi Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	40
Mississippi Power [Member] | Energy-related derivatives [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	(37)
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	(25)
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	(13)
Mississippi Power [Member] | Energy-related derivatives [Member] | Other regulatory liabilities, deferred [Member]
Pre-tax effect of unrealized derivative gains (losses)
Regulatory hedge unrealized gain (loss) recognized on balance sheet	1
Southern Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	7
Cash Flow and Fair Value Hedging [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	12
Liability Derivatives	30
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	1
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	6
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	28
Cash Flow and Fair Value Hedging [Member] | Foreign currency derivatives [Member] | Liabilities from risk management activities [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	1
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	28
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	28
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	1
Cash Flow and Fair Value Hedging [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
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	1
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	1
Hedging Instruments for Regulatory Purposes [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	23
Liability Derivatives	187
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	14
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	9
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	123
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	64
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	3
Liability Derivatives	35
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy-related derivatives [Member] | Other Current Assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Hedging Instruments for Regulatory Purposes [Member] | 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	2
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	26
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	9
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	17
Liability Derivatives	75
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	13
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	4
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	52
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	23
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	2
Liability Derivatives	39
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy-related derivatives [Member] | Other deferred charges and assets [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	2
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	20
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	19
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member]
Fair value of energy-related derivatives and interest rate derivatives
Asset Derivatives	1
Liability Derivatives	38
Hedging Instruments for Regulatory Purposes [Member] | Mississippi 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] | 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	25
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	13
Not Designated as Hedging Instrument [Member]
Fair value of energy-related derivatives and interest rate derivatives
Liability Derivatives	7
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	6
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
Liability 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
Liability Derivatives	6
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	$ 6

XML

Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Current Assets:
Cash and cash equivalents	$ 659,000,000	$ 1,315,000,000
Restricted cash and cash equivalents	192,000,000	8,000,000
Receivables --
Customer accounts receivable	1,164,000,000	1,074,000,000
Unbilled revenues	497,000,000	376,000,000
Under recovered regulatory clause revenues	20,000,000	143,000,000
Other accounts and notes receivable	261,000,000	282,000,000
Accumulated provision for uncollectible accounts	(23,000,000)	(26,000,000)
Fossil fuel stock, at average cost	1,672,000,000	1,367,000,000
Materials and supplies, at average cost	919,000,000	903,000,000
Vacation pay	161,000,000	160,000,000
Prepaid expenses	577,000,000	385,000,000
Other regulatory assets, current	208,000,000	239,000,000
Other current assets	66,000,000	46,000,000
Total current assets	6,373,000,000	6,272,000,000
Property, Plant, and Equipment:
In service	61,577,000,000	59,744,000,000
Less accumulated provision for depreciation	21,616,000,000	21,154,000,000
Plant in service, net of depreciation	39,961,000,000	38,590,000,000
Other utility plant, net	53,000,000	55,000,000
Nuclear fuel, at amortized cost	807,000,000	774,000,000
Construction work in progress	5,745,000,000	5,591,000,000
Total property, plant, and equipment	46,566,000,000	45,010,000,000
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,235,000,000	1,207,000,000
Leveraged leases	660,000,000	649,000,000
Miscellaneous property and investments	260,000,000	262,000,000
Total other property and investments	2,155,000,000	2,118,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,390,000,000	1,365,000,000
Unamortized debt issuance expense	157,000,000	156,000,000
Unamortized loss on reacquired debt	288,000,000	285,000,000
Deferred under recovered regulatory clause revenues	29,000,000	48,000,000
Other regulatory assets, deferred	3,484,000,000	3,532,000,000
Other deferred charges and assets	455,000,000	481,000,000
Total deferred charges and other assets	5,803,000,000	5,867,000,000
Total Assets	60,897,000,000	59,267,000,000
Current Liabilities:
Securities due within one year	2,075,000,000	1,717,000,000
Interest-bearing refundable deposit related to asset sale	150,000,000
Notes payable	453,000,000	859,000,000
Accounts payable	1,253,000,000	1,553,000,000
Customer deposits	363,000,000	347,000,000
Accrued taxes --
Accrued income taxes	17,000,000	13,000,000
Unrecognized tax benefits	6,000,000	22,000,000
Other accrued taxes	337,000,000	425,000,000
Accrued interest	237,000,000	226,000,000
Accrued vacation pay	204,000,000	205,000,000
Accrued compensation	246,000,000	450,000,000
Liabilities from risk management activities	160,000,000	209,000,000
Other regulatory liabilities, current	144,000,000	125,000,000
Other current liabilities	443,000,000	426,000,000
Total current liabilities	6,088,000,000	6,577,000,000
Long-term Debt	19,459,000,000	18,647,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	9,352,000,000	8,809,000,000
Deferred credits related to income taxes	216,000,000	224,000,000
Accumulated deferred investment tax credits	704,000,000	611,000,000
Employee benefit obligations	2,409,000,000	2,442,000,000
Asset retirement obligations	1,385,000,000	1,321,000,000
Other cost of removal obligations	1,195,000,000	1,165,000,000
Other regulatory liabilities, deferred	295,000,000	297,000,000
Other deferred credits and liabilities	588,000,000	514,000,000
Total deferred credits and other liabilities	16,144,000,000	15,383,000,000
Total Liabilities	41,691,000,000	40,607,000,000
Redeemable Preferred Stock of Subsidiaries	375,000,000	375,000,000
Common Stockholders' Equity:
Common stock	4,377,000,000	4,328,000,000
Paid-in capital	4,755,000,000	4,410,000,000
Treasury, at cost	(18,000,000)	(17,000,000)
Retained earnings	9,122,000,000	8,968,000,000
Accumulated other comprehensive loss	(112,000,000)	(111,000,000)
Total common stockholders' equity	18,124,000,000	17,578,000,000
Preferred and Preference Stock of Subsidiaries	707,000,000	707,000,000
Total Stockholders' Equity	18,831,000,000	18,285,000,000
Total Liabilities and Stockholders' Equity	60,897,000,000	59,267,000,000
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	78,000,000	344,000,000
Restricted cash and cash equivalents		1,000,000
Receivables --
Customer accounts receivable	368,000,000	332,000,000
Unbilled revenues	160,000,000	126,000,000
Under recovered regulatory clause revenues	16,000,000
Other accounts and notes receivable	34,000,000	35,000,000
Affiliated companies	57,000,000	79,000,000
Accumulated provision for uncollectible accounts	(9,000,000)	(10,000,000)
Fossil fuel stock, at average cost	469,000,000	344,000,000
Materials and supplies, at average cost	380,000,000	375,000,000
Vacation pay	59,000,000	59,000,000
Prepaid expenses	135,000,000	74,000,000
Other regulatory assets, current	32,000,000	44,000,000
Other current assets	8,000,000	11,000,000
Total current assets	1,787,000,000	1,814,000,000
Property, Plant, and Equipment:
In service	21,110,000,000	20,809,000,000
Less accumulated provision for depreciation	7,562,000,000	7,344,000,000
Plant in service, net of depreciation	13,548,000,000	13,465,000,000
Nuclear fuel, at amortized cost	347,000,000	330,000,000
Construction work in progress	390,000,000	374,000,000
Total property, plant, and equipment	14,285,000,000	14,169,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	61,000,000	62,000,000
Nuclear decommissioning trusts, at fair value	571,000,000	540,000,000
Miscellaneous property and investments	73,000,000	73,000,000
Total other property and investments	705,000,000	675,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	529,000,000	532,000,000
Prepaid pension costs	74,000,000	59,000,000
Deferred under recovered regulatory clause revenues	29,000,000	48,000,000
Other regulatory assets, deferred	1,001,000,000	994,000,000
Other deferred charges and assets	144,000,000	186,000,000
Total deferred charges and other assets	1,777,000,000	1,819,000,000
Total Assets	18,554,000,000	18,477,000,000
Current Liabilities:
Securities due within one year	500,000,000	500,000,000
Affiliated	176,000,000	203,000,000
Accounts payable	196,000,000	322,000,000
Customer deposits	86,000,000	85,000,000
Accrued taxes --
Accrued income taxes	99,000,000	32,000,000
Other accrued taxes	80,000,000	34,000,000
Accrued interest	65,000,000	63,000,000
Accrued vacation pay	48,000,000	48,000,000
Accrued compensation	51,000,000	95,000,000
Liabilities from risk management activities	54,000,000	54,000,000
Other regulatory liabilities, current	3,000,000	18,000,000
Other current liabilities	40,000,000	38,000,000
Total current liabilities	1,398,000,000	1,492,000,000
Long-term Debt	5,630,000,000	5,632,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,319,000,000	3,257,000,000
Deferred credits related to income taxes	81,000,000	83,000,000
Accumulated deferred investment tax credits	145,000,000	149,000,000
Employee benefit obligations	339,000,000	343,000,000
Asset retirement obligations	571,000,000	553,000,000
Other cost of removal obligations	736,000,000	703,000,000
Other regulatory liabilities, deferred	165,000,000	156,000,000
Other deferred credits and liabilities	84,000,000	82,000,000
Total deferred credits and other liabilities	5,440,000,000	5,326,000,000
Total Liabilities	12,468,000,000	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	2,207,000,000	2,182,000,000
Retained earnings	1,997,000,000	1,956,000,000
Accumulated other comprehensive loss	(25,000,000)	(18,000,000)
Total common stockholders' equity	5,401,000,000	5,342,000,000
Total Liabilities and Stockholders' Equity	18,554,000,000	18,477,000,000
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	188,000,000	13,000,000
Restricted cash and cash equivalents	185,000,000
Receivables --
Customer accounts receivable	596,000,000	571,000,000
Unbilled revenues	244,000,000	172,000,000
Under recovered regulatory clause revenues		137,000,000
Joint owner accounts receivable	45,000,000	87,000,000
Other accounts and notes receivable	98,000,000	61,000,000
Affiliated companies	55,000,000	26,000,000
Accumulated provision for uncollectible accounts	(12,000,000)	(13,000,000)
Fossil fuel stock, at average cost	870,000,000	723,000,000
Materials and supplies, at average cost	391,000,000	406,000,000
Vacation pay	84,000,000	82,000,000
Prepaid income taxes	140,000,000	71,000,000
Other regulatory assets, current	93,000,000	108,000,000
Other current assets	81,000,000	106,000,000
Total current assets	3,058,000,000	2,550,000,000
Property, Plant, and Equipment:
In service	28,549,000,000	27,804,000,000
Less accumulated provision for depreciation	10,395,000,000	10,296,000,000
Plant in service, net of depreciation	18,154,000,000	17,508,000,000
Other utility plant, net	53,000,000	55,000,000
Nuclear fuel, at amortized cost	460,000,000	443,000,000
Construction work in progress	3,055,000,000	3,274,000,000
Total property, plant, and equipment	21,722,000,000	21,280,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	61,000,000	63,000,000
Nuclear decommissioning trusts, at fair value	665,000,000	667,000,000
Miscellaneous property and investments	44,000,000	44,000,000
Total other property and investments	770,000,000	774,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	757,000,000	756,000,000
Other regulatory assets, deferred	1,550,000,000	1,604,000,000
Other deferred charges and assets	221,000,000	187,000,000
Total deferred charges and other assets	2,528,000,000	2,547,000,000
Total Assets	28,078,000,000	27,151,000,000
Current Liabilities:
Securities due within one year	1,340,000,000	455,000,000
Notes payable	2,000,000	515,000,000
Affiliated	357,000,000	337,000,000
Accounts payable	451,000,000	686,000,000
Customer deposits	227,000,000	213,000,000
Accrued taxes --
Accrued income taxes	110,000,000	36,000,000
Other accrued taxes	175,000,000	304,000,000
Accrued interest	108,000,000	92,000,000
Accrued vacation pay	60,000,000	60,000,000
Accrued compensation	67,000,000	125,000,000
Liabilities from risk management activities	52,000,000	68,000,000
Other regulatory liabilities, current	79,000,000	65,000,000
Nuclear decommissioning trust securities lending collateral	8,000,000	32,000,000
Other current liabilities	197,000,000	153,000,000
Total current liabilities	3,233,000,000	3,141,000,000
Long-term Debt	8,570,000,000	8,018,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,608,000,000	4,388,000,000
Deferred credits related to income taxes	118,000,000	122,000,000
Accumulated deferred investment tax credits	214,000,000	220,000,000
Employee benefit obligations	892,000,000	905,000,000
Asset retirement obligations	759,000,000	734,000,000
Other cost of removal obligations	97,000,000	110,000,000
Other deferred credits and liabilities	255,000,000	224,000,000
Total deferred credits and other liabilities	6,943,000,000	6,703,000,000
Total Liabilities	18,746,000,000	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	5,557,000,000	5,522,000,000
Retained earnings	3,119,000,000	3,112,000,000
Accumulated other comprehensive loss	(8,000,000)	(9,000,000)
Total common stockholders' equity	9,066,000,000	9,023,000,000
Total Liabilities and Stockholders' Equity	28,078,000,000	27,151,000,000
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	21,163,000	17,328,000
Receivables --
Customer accounts receivable	83,682,000	72,754,000
Unbilled revenues	57,575,000	49,921,000
Under recovered regulatory clause revenues	4,070,000	5,530,000
Other accounts and notes receivable	10,819,000	13,350,000
Affiliated companies	15,189,000	14,844,000
Accumulated provision for uncollectible accounts	(1,463,000)	(1,962,000)
Fossil fuel stock, at average cost	143,588,000	147,567,000
Materials and supplies, at average cost	53,881,000	49,781,000
Prepaid expenses	71,492,000	28,327,000
Other regulatory assets, current	35,670,000	35,849,000
Other current assets	1,523,000	2,051,000
Total current assets	497,189,000	435,340,000
Property, Plant, and Equipment:
In service	4,130,575,000	3,846,446,000
Less accumulated provision for depreciation	1,154,842,000	1,124,291,000
Plant in service, net of depreciation	2,975,733,000	2,722,155,000
Construction work in progress	158,639,000	287,173,000
Total property, plant, and equipment	3,134,372,000	3,009,328,000
Other Property and Investments:
Total other property and investments	16,377,000	16,394,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	50,696,000	48,210,000
Other regulatory assets, deferred	332,325,000	323,116,000
Other deferred charges and assets	27,567,000	39,493,000
Total deferred charges and other assets	410,588,000	410,819,000
Total Assets	4,058,526,000	3,871,881,000
Current Liabilities:
Notes payable	116,907,000	114,507,000
Affiliated	58,897,000	54,874,000
Accounts payable	50,348,000	63,265,000
Customer deposits	36,028,000	35,779,000
Accrued taxes --
Accrued income taxes	68,000	1,362,000
Other accrued taxes	20,147,000	12,114,000
Accrued interest	11,911,000	14,018,000
Accrued compensation	8,245,000	14,485,000
Liabilities from risk management activities	20,485,000	22,786,000
Other regulatory liabilities, current	56,999,000	35,639,000
Other current liabilities	23,880,000	22,916,000
Total current liabilities	403,915,000	391,745,000
Long-term Debt	1,245,567,000	1,235,447,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	559,600,000	458,978,000
Accumulated deferred investment tax credits	6,084,000	6,760,000
Employee benefit obligations	109,200,000	109,740,000
Other cost of removal obligations	212,981,000	214,598,000
Other regulatory liabilities, deferred	47,229,000	44,843,000
Other deferred credits and liabilities	209,965,000	186,824,000
Total deferred credits and other liabilities	1,145,059,000	1,021,743,000
Total Liabilities	2,794,541,000	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	545,733,000	542,709,000
Retained earnings	229,062,000	231,333,000
Accumulated other comprehensive loss	(1,868,000)	(2,154,000)
Total common stockholders' equity	1,165,987,000	1,124,948,000
Total Liabilities and Stockholders' Equity	4,058,526,000	3,871,881,000
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	153,380,000	211,585,000
Receivables --
Customer accounts receivable	37,632,000	32,551,000
Unbilled revenues	36,060,000	27,239,000
Other accounts and notes receivable	5,072,000	7,080,000
Affiliated companies	25,497,000	23,078,000
Accumulated provision for uncollectible accounts	(306,000)	(547,000)
Fossil fuel stock, at average cost	172,970,000	140,173,000
Materials and supplies, at average cost	30,576,000	30,787,000
Prepaid income taxes	192,067,000	37,793,000
Other regulatory assets, current	65,251,000	69,201,000
Other current assets	6,230,000	8,881,000
Total current assets	724,429,000	587,821,000
Property, Plant, and Equipment:
In service	2,956,019,000	2,902,240,000
Less accumulated provision for depreciation	1,052,399,000	1,019,251,000
Plant in service, net of depreciation	1,903,620,000	1,882,989,000
Construction work in progress	1,699,239,000	955,135,000
Total property, plant, and equipment	3,602,859,000	2,838,124,000
Other Property and Investments:
Total other property and investments	5,970,000	6,520,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	47,979,000	25,009,000
Other regulatory assets, deferred	195,721,000	185,694,000
Other deferred charges and assets	37,640,000	28,674,000
Total deferred charges and other assets	281,340,000	239,377,000
Total Assets	4,614,598,000	3,671,842,000
Current Liabilities:
Securities due within one year	165,000,000	240,633,000
Interest-bearing refundable deposit related to asset sale	150,000,000
Affiliated	62,007,000	62,650,000
Accounts payable	228,506,000	168,309,000
Customer deposits	14,190,000	13,658,000
Accrued taxes --
Accrued income taxes	3,803,000	3,813,000
Other accrued taxes	37,327,000	53,825,000
Accrued interest	20,095,000	12,750,000
Accrued compensation	8,887,000	15,889,000
Liabilities from risk management activities	26,699,000	54,127,000
Other regulatory liabilities, current	5,553,000	5,779,000
Over recovered regulatory clause liabilities	76,373,000	60,502,000
Other current liabilities	21,913,000	17,533,000
Total current liabilities	820,353,000	709,468,000
Long-term Debt	1,410,660,000	1,103,596,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	377,763,000	270,397,000
Deferred credits related to income taxes	10,536,000	11,058,000
Accumulated deferred investment tax credits	206,607,000	109,761,000
Employee benefit obligations	162,266,000	161,065,000
Other cost of removal obligations	135,540,000	126,424,000
Other regulatory liabilities, deferred	64,710,000	60,848,000
Other deferred credits and liabilities	57,181,000	37,228,000
Total deferred credits and other liabilities	1,014,603,000	776,781,000
Total Liabilities	3,245,616,000	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	975,198,000	694,855,000
Retained earnings	332,450,000	325,568,000
Accumulated other comprehensive loss	(9,137,000)	(8,897,000)
Total common stockholders' equity	1,336,202,000	1,049,217,000
Total Liabilities and Stockholders' Equity	4,614,598,000	3,671,842,000
Southern Power [Member]
Current Assets:
Cash and cash equivalents	3,832,000	16,943,000
Receivables --
Customer accounts receivable	74,413,000	59,360,000
Other accounts and notes receivable	2,792,000	2,122,000
Affiliated companies	52,796,000	36,508,000
Fossil fuel stock, at average cost	16,339,000	13,038,000
Materials and supplies, at average cost	45,700,000	37,603,000
Prepaid service agreements - current	59,784,000	28,621,000
Prepaid income taxes	43,720,000	5,192,000
Prepaid expenses	4,390,000	4,645,000
Assets from risk management activities	393,000	177,000
Total current assets	304,159,000	204,209,000
Property, Plant, and Equipment:
In service	3,602,377,000	3,167,840,000
Less accumulated provision for depreciation	710,351,000	652,087,000
Plant in service, net of depreciation	2,892,026,000	2,515,753,000
Construction work in progress	407,289,000	666,280,000
Total property, plant, and equipment	3,299,315,000	3,182,033,000
Other Property and Investments:
Goodwill	1,839,000	1,839,000
Other intangible assets, net of amortization of $1,867 and $1,476 at June 30, 2012 and December 31, 2011, respectively	47,253,000	47,644,000
Total other property and investments	49,092,000	49,483,000
Deferred Charges and Other Assets:
Prepaid long-term service agreements	100,971,000	115,838,000
Other deferred charges and assets -- affiliated	5,259,000	3,029,000
Other deferred charges and assets	26,637,000	26,385,000
Total deferred charges and other assets	132,867,000	145,252,000
Total Assets	3,785,433,000	3,580,977,000
Current Liabilities:
Securities due within one year		555,000
Notes payable	289,241,000	179,520,000
Affiliated	60,378,000	63,609,000
Accounts payable	46,360,000	44,321,000
Accrued taxes --
Accrued income taxes	5,473,000	2,548,000
Other accrued taxes	10,526,000	2,158,000
Accrued interest	22,284,000	21,874,000
Liabilities from risk management activities	6,645,000	9,651,000
Other current liabilities	18,940,000	7,401,000
Total current liabilities	459,847,000	331,637,000
Long-term Debt	1,303,691,000	1,302,758,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	382,832,000	319,790,000
Deferred convertible investment tax credits	131,696,000	125,065,000
Deferred capacity revenues -- affiliated	8,389,000	20,637,000
Other deferred credits and liabilities -- affiliated	3,147,000	3,618,000
Other deferred credits and liabilities	4,743,000	4,965,000
Total deferred credits and other liabilities	530,807,000	474,075,000
Total Liabilities	2,294,345,000	2,108,470,000
Redeemable Noncontrolling Interest	6,644,000	3,825,000
Common Stockholders' Equity:
Paid-in capital	1,028,701,000	1,028,210,000
Retained earnings	459,719,000	447,301,000
Accumulated other comprehensive loss	(3,976,000)	(6,829,000)
Total common stockholders' equity	1,484,444,000	1,468,682,000
Total Liabilities and Stockholders' Equity	$ 3,785,433,000	$ 3,580,977,000

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Contingencies and Regulatory Matters

6 Months Ended

Jun. 30, 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.

Insurance Recovery

Mirant Corporation (Mirant) was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and other countries. Mirant was a wholly-owned subsidiary of Southern Company until its initial public offering in 2000. In 2001, Southern Company completed a spin-off to its stockholders of its remaining ownership, and Mirant became an independent corporate entity.

In 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In 2005, Mirant, as a debtor in possession, and the unsecured creditors’ committee filed a complaint against Southern Company. Later in 2005, this complaint was transferred to MC Asset Recovery, LLC (MC Asset Recovery) as part of Mirant’s plan of reorganization. In 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve this action. The settlement included an agreement where Southern Company paid MC Asset Recovery $202 million. Southern Company filed an insurance claim in 2009 to recover a portion of this settlement and received a nontaxable $25 million payment from its insurance provider on June 14, 2012. Additionally, legal fees related to this insurance settlement totaled approximately $6 million. The net reduction to expense for this insurance settlement was approximately $19 million.

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. In March 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). 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. In May 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 June 30, 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. In September 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, in November 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. In November 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 June 30, 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 PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. The feasibility study/presumptive remedy document was originally filed with TCEQ in 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, in March 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. In July 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 were received and credited to the Georgia Power accounts where the original costs were charged and were 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 June 30, 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 has begun and is expected to be operational 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 2012. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power

Rate CNP

See Note 3 to the financial statements of Southern Company and Alabama Power under “Retail Regulatory Matters  — Alabama Power — Rate CNP” and “Retail Regulatory Matters — Rate CNP,” respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power’s recovery of retail costs through Rate Certificated New Plant Power Purchase Agreement (Rate CNP) and Rate Certificated New Plant Environmental (Rate CNP Environmental). Alabama Power’s under recovered Rate CNP balance as of June 30, 2012 was $2 million as compared to $6 million at December 31, 2011. Alabama Power’s under recovered Rate CNP Environmental balance as of June 30, 2012 was $26 million as compared to $11 million at December 31, 2011. These under recovered balances at June 30, 2012 are included in deferred under recovered regulatory clause revenues on Southern Company’s and Alabama Power’s Condensed Balance Sheets herein. For Rate CNP, this classification is based on an estimate, which includes such factors as purchased power capacity and energy demand. For Rate CNP Environmental, this classification is based on an estimate, which includes such factors as costs to comply with environmental mandates and energy demand. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered retail costs.

Natural Disaster Cost Recovery

See Note 3 to the financial statements of Southern Company and Alabama Power under “Retail Regulatory Matters  — Alabama Power — Natural Disaster Reserve” and “Retail Regulatory Matters — Natural Disaster Reserve,” respectively, in Item 8 of the Form 10-K for additional information regarding natural disaster cost recovery. At June 30, 2012, the NDR had an accumulated balance of $105 million, which is included in Southern Company’s and Alabama Power’s Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in Southern Company’s and Alabama Power’s Condensed Statements of Income herein.

Georgia Power

Fuel Cost Recovery

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

On June 21, 2012, the Georgia PSC approved a decrease in Georgia Power’s fuel cost recovery rates of 19%, which reduced annual billings by $567 million effective June 1, 2012. The decrease in fuel costs resulted from lower natural gas prices as a result of increased natural gas supplies.

As of June 30, 2012, Georgia Power had a total over recovered fuel cost balance of approximately $99 million compared to an under recovered balance of $137 million at December 31, 2011. The over recovered fuel costs at June 30, 2012 are included in other current liabilities and 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.

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. On July 11, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitioners’ motion to stay the effectiveness of the COLs. Georgia Power has intervened in 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 June 30, 2012, approximately $64 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, Contractor) 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 Contractor 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. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and Georgia Power (on behalf of the Owners) are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate to 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 by the NRC. The Owners and the Contractor have begun negotiations regarding these issues, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Through correspondence sent to the Owners, the Contractor has provided its proposed adjustment to the contract price and has initiated the formal dispute resolution process. The Contractor’s estimated adjustment attributable to Georgia Power (based on Georgia Power’s ownership interest regarding these issues) is approximately $425 million (in 2008 dollars) with respect to these issues. 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. While the formal dispute resolution process has been initiated, Georgia Power expects negotiations with the Contractor to continue over the next several months with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Georgia Power intends to vigorously defend its positions. If these costs ultimately are imposed upon the Owners, Georgia Power would seek an amendment to the certified cost of Plant Vogtle Units 3 and 4, if necessary. In connection with these negotiations, the Owners are evaluating whether maintaining the currently scheduled commercial operation dates of 2016 and 2017 remains in the best interest of their customers. Additional claims by the Contractor 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. During a routine inspection in April 2012, the NRC identified that certain details of the rebar construction in the Plant Vogtle Unit 3 nuclear island were not consistent with the DCD. In May 2012, Southern Nuclear received an official notice of violation relating to these findings from the NRC. The design changes were determined to have minimal safety significance and, on August 1, 2012, Southern Nuclear filed a license amendment request with the NRC to clarify that the nuclear island concrete and rebar construction will conform to NRC requirements. Various inspection and other issues are expected to arise from time to time as construction proceeds, which may result in additional license amendments or require other resolution.

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.

Plant McDonough Unit 1 was retired on February 29, 2012. Georgia Power placed Plant McDonough-Atkinson Unit 5 into service on April 26, 2012. Plant McDonough-Atkinson Unit 6 is scheduled to be placed into service in November 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. On July 17, 2012, the Florida PSC denied Gulf Power’s motion and reaffirmed its earlier decision.

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.

On June 19, 2012, the Florida PSC approved a decrease in Gulf Power’s fuel rates of 7.8%, which will reduce annual billings by approximately $58.8 million effective July 2, 2012.

Over recovered fuel costs at June 30, 2012 totaled $41.6 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 June 30, 2012 totaled $7.9 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.

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. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, excluding AFUDC, and it is scheduled for completion in December 2015. Gulf Power’s portion of the cost is expected to be recovered through the environmental cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.

Over recovered environmental costs at June 30, 2012 totaled $3.6 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.

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 June 30, 2012 totaled $1.6 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. An order granting the suspension of the 2011 PEP lookback was signed by the Mississippi PSC on May 8, 2012. 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 February 14, 2012, Mississippi Power submitted its 2012 ECO Plan filing, which proposed a 0.3% increase in annual revenues for Mississippi Power. In compliance with the CPCN to construct a scrubber on Plant Daniel Units 1 and 2, Mississippi Power revised the 2012 ECO Plan filing to exclude scrubber expenditures from rate base, which resulted in a 0.16% decrease in annual revenues. On June 22, 2012, the 2012 ECO Plan filing, including the proposed rate decrease, was approved by the Mississippi PSC, effective on June 29, 2012.

On April 3, 2012, the Mississippi PSC approved Mississippi Power’s request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On May 3, 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power’s portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power’s portion of the cost is expected to be recovered through the ECO Plan. As of June 30, 2012, total project expenditures were $82.0 million, with Mississippi Power’s portion being $41.0 million. The ultimate outcome of this matter cannot be determined at this time.

Certificated New Plant

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 and “Integrated Coal Gasification Combined Cycle” herein for additional information.

On May 23, 2012, the Mississippi Public Utilities Staff signed a joint stipulation with Mississippi Power to establish a new rate schedule for Certificated New Plant-A (CNP-A), a proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. An amended and restated stipulation was subsequently executed and filed on June 1, 2012. On June 14, 2012, Mississippi Power submitted to the Mississippi PSC a proposed supplemental compliance filing to establish the new CNP-A rate schedule and a stipulated rate increase based upon the revenue request of between $55.3 million and $58.6 million to recover financing costs over the remainder of 2012.

On June 22, 2012, the Mississippi PSC denied the proposed CNP-A rate schedule and the 2012 rate recovery filings submitted by Mississippi Power, pending a final ruling from the Mississippi Supreme Court regarding the motion for stay and notice of appeal filed by the Sierra Club on April 26, 2012 relating to the Mississippi PSC’s issuance of the CPCN for the Kemper IGCC. On July 9, 2012, Mississippi Power appealed the Mississippi PSC’s June 22, 2012 decision to the Mississippi Supreme Court and requested interim rates under bond of $55.3 million while the Mississippi Supreme Court decides Mississippi Power’s appeal of the Mississippi PSC’s June 22, 2012 decision. On July 31, 2012, the Mississippi Supreme Court denied Mississippi Power’s request for interim rates under bond. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery.

At June 30, 2012, the amount of over recovered retail fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $55.5 million compared to $42.4 million at December 31, 2011. Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At June 30, 2012, the amount of over recovered wholesale MRA and MB fuel costs included in Mississippi Power’s Condensed Balance Sheets herein was $17.4 million and $2.4 million, respectively, compared to $14.3 million and $2.2 million, respectively, at December 31, 2011. In addition, at June 30, 2012 and December 31, 2011, the amount of over recovered MRA emissions allowance cost included in Mississippi Power’s Condensed Balance Sheets herein was $1.0 million and $1.7 million, respectively. 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, any changes in the billing factors will not have a significant effect on Mississippi Power’s revenues or net income, but will affect 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. 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. In February 2011, the Chancery Court issued a judgment affirming the 2010 MPSC Order and, in March 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. 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 18, 2012, Mississippi Power’s motion to join the appeal was approved.

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 (CO ₂) 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 and certain general exceptions, including change of law, force majeure, and beneficial capital), (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 Kemper IGCC). The current cost estimate of the Kemper IGCC is $2.88 billion, including a $72 million contingency.

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, 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 Kemper IGCC 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 has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site in Kemper County. The estimated capital cost of the mine is approximately $245 million, of which $99.9 million has been incurred through June 30, 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. Due to the fact that Liberty Fuels conducts all of its activities on behalf of Mississippi Power, Liberty Fuels qualifies as a variable interest entity for which Mississippi Power is the primary beneficiary. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Consistent with the requirements of consolidation accounting, Liberty Fuels is consolidated in the financial statements of Mississippi Power and accordingly the asset retirement cost and the ARO have been recorded in Mississippi Power’s financial statements. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.

In December 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. In April 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 June 30, 2012, Mississippi Power received or accrued tax benefits totaling $197 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC. Based on current tax laws and regulations in effect, Mississippi Power expects to receive substantially all of the tax credits accrued through June 30, 2012 by June 30, 2013.

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. 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 June 29, 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA extended its option to purchase until December 31, 2012 and reduced its purchase

commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC, subject to approval by the Mississippi PSC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.

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 is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody’s or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA’s ability to request a refund, the deposit has been presented as a current liability in Mississippi Power’s Condensed Balance Sheet herein and as financing proceeds in Mississippi Power’s Condensed Statement of Cash Flows herein.

As of June 30, 2012, Mississippi Power had spent a total of $1.7 billion on the Kemper IGCC including the cost of the lignite mine and equipment, the CO ₂ pipeline facilities, and regulatory filing costs. Of this total, $1.6 billion was included in CWIP (which is net of $245.3 million of CCPI2 grant funds), $29.0 million was recorded in other regulatory assets, $2.6 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 and “Retail Regulatory Matters – Certificated New Plant” herein 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

Introduction (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
Introduction [Abstract]
Expected potential impairment loss on abandonment of the project	$ 90

XML

Effective Tax Rate and Unrecognized Tax Benefits (Details 1) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011
Impact on effective tax rate
Tax positions impacting the effective tax rate	$ 38	$ 69
Tax positions not impacting the effective tax rate	55	51
Balance of unrecognized tax benefits	93	120
Accrued interest for unrecognized tax benefits
Interest accrued as of December 31, 2011	10
Interest reclassified due to settlements	(9)
Interest accrued during the period
Balance as of June 30, 2012	1
Georgia Power [Member]
Impact on effective tax rate
Tax positions impacting the effective tax rate	3
Tax positions not impacting the effective tax rate	20
Balance of unrecognized tax benefits	23	47
Accrued interest for unrecognized tax benefits
Interest accrued as of December 31, 2011	6
Interest reclassified due to settlements	(6)
Interest accrued during the period
Other Registrants [Member]
Impact on effective tax rate
Tax positions impacting the effective tax rate	4
Tax positions not impacting the effective tax rate	33
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	(2)
Interest accrued during the period
Balance as of June 30, 2012	$ 1

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

Assets and liabilities measured at fair value on a recurring basis

	Fair Value Measurements Using
As of June 30, 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		—		12		—		12
Nuclear decommissioning trusts (a)		450		784		—		1,234
Cash equivalents and restricted cash		512		—		—		512
Other investments		1		53		15		69
Total	$	963	$	873	$	15	$	1,851
Liabilities:
Energy-related derivatives	$	—	$	194	$	—	$	194
Interest rate derivatives		—		28		—		28
Foreign currency derivatives		—		2		—		2
Total	$	—	$	224	$	—	$	224
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Nuclear decommissioning trusts: (b )
Domestic equity		274		60		—		334
Foreign equity (d )		25		49		—		74
U.S. Treasury and government agency securities		—		23		—		23
Corporate bonds		—		101		—		101
Mortgage and asset backed securities		—		25		—		25
Other		—		12		—		12
Total	$	299	$	273	$	—	$	572
Liabilities:
Energy-related derivatives	$	—	$	35	$	—	$	35
Interest rate derivatives		—		28		—		28
Total	$	—	$	63	$	—	$	63

	Fair Value Measurements Using
As of June 30, 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	$	—	$	17	$	—	$	17
Nuclear decommissioning trusts: (b) (c)
Domestic equity		151		1		—		152
Foreign equity (d)		—		102		—		102
U.S. Treasury and government agency securities		—		45		—		45
Municipal bonds		—		103		—		103
Corporate bonds		—		120		—		120
Mortgage and asset backed securities		—		118		—		118
Other		—		24		—		24
Cash equivalents		149		—		—		149
Total	$	300	$	530	$	—	$	830
Liabilities:
Energy-related derivatives	$	—	$	75	$	—	$	75
Gulf Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents		15		—		—		15
Total	$	15	$	2	$	—	$	17
Liabilities:
Energy-related derivatives	$	—	$	39	$	—	$	39
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents		146		—		—		146
Total	$	146	$	1	$	—	$	147
Liabilities:
Energy-related derivatives	$	—	$	38	$	—	$	38
Foreign currency derivatives		—		2		—		2
Total	$	—	$	40	$	—	$	40
Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	7

(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 payables related to the securities lending program. As of June 30, 2012, approximately $38 million of the fair market value of Georgia Power’s nuclear decommissioning trust funds’ securities were on loan and pledged to creditors under the funds’ managers’ securities lending program.

(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 June 30, 2012:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds — commingled funds	$	8	None	Daily	1 to 3 days
Other — commingled funds		73	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		91	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		512	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Other — commingled funds		49	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance		91	None	Daily	15 days
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds — commingled funds		8	None	Daily	1 to 3 days
Other — commingled funds		24	None	Daily	Not applicable
Cash equivalents:
Money market funds		149	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds		15	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds		146	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	$21,451	$23,477
Alabama Power	$  6,130	$  6,893
Georgia Power	$  9,856	$10,703
Gulf Power	$  1,246	$  1,384
Mississippi Power	$  1,576	$  1,690
Southern Power	$  1,306	$  1,416