SOUTHERN COMPANY

Third Quarter 2009 vs. Third Quarter 2008

Year-to-Date 2009 vs. Year-to-Date 2008

(change in millions)

(% change)

(change in millions)

(% change)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2009

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

For the transition period from to


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

1-3164	Alabama Power Company	63-0004250
	(An Alabama Corporation)
	600 North 18^th Street
	Birmingham, Alabama 35291
	(205) 257-1000

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

0-2429	Gulf Power Company	59-0276810
	(A Florida Corporation)
	One Energy Place
	Pensacola, Florida 32520
	(850) 444-6111

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

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

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

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

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


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

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


	Description of	Shares Outstanding
Registrant	Common Stock	at September 30, 2009
The Southern Company	Par Value $5 Per Share		800,211,378
Alabama Power Company	Par Value $40 Per Share		28,850,000
Georgia Power Company	Without Par Value		9,261,500
Gulf Power Company	Without Par Value		3,142,717
Mississippi Power Company	Without Par Value		1,121,000
Southern Power Company	Par Value $0.01 Per Share		1,000

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

DEFINITIONS


Term		Meaning
2007 Retail Rate Plan		Georgia Power’s retail rate plan for the years 2008 through 2010
Alabama Power		Alabama Power Company
Clean Air Act		Clean Air Act Amendments of 1990
DOE		U.S. Department of Energy
Duke Energy		Duke Energy Corporation
ECO Plan		Mississippi Power’s Environmental Compliance Overview Plan
EPA		U.S. Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Inc.
Form 10-K		Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2008 and, with respect to Southern Company, the subsequently revised audited financial statements included in the Current Report on Form 8-K filed May 8, 2009
Georgia Power		Georgia Power Company
Gulf Power		Gulf Power Company
IGCC		Integrated coal gasification combined cycle
IIC		Intercompany Interchange Contract
Internal Revenue Code		Internal Revenue Code of 1986, as amended
IRS		Internal Revenue Service
KWH		Kilowatt-hour
LIBOR		London Interbank Offered Rate
Mirant		Mirant Corporation
Mississippi Power		Mississippi Power Company
mmBtu		Million British thermal unit
Moody’s		Moody’s Investors Service
MW		Megawatt
MWH		Megawatt-hour
NRC		Nuclear Regulatory Commission
NSR		New Source Review
OCI		Other Comprehensive Income
PEP		Performance Evaluation Plan
Power Pool		The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA		Power Purchase Agreement
PSC		Public Service Commission
Rate ECR		Alabama Power’s energy cost recovery rate mechanism
registrants		Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
SCS		Southern Company Services, Inc.
SEC		Securities and Exchange Commission
Southern Company		The Southern Company
Southern Company system		Southern Company, the traditional operating companies, Southern Power, and other subsidiaries

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, retail return on equity projections, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impacts of adoption of new accounting rules, potential exemptions from ad valorem taxation of the Kemper IGCC project, unrecognized tax benefits related to leveraged lease transactions, impact of the American Recovery and Reinvestment Act of 2009, 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 change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•

current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, IRS audits, and Mirant matters;

•

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, 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;

•

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 storm restoration cost recovery;

•

regulatory approvals related to the potential Plant Vogtle expansion, including Georgia PSC and NRC approvals;

•

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 neighboring utilities and other wholesale customers;

•

the direct or indirect effect on Southern Company’s business resulting from terrorist incidents and the threat of terrorist incidents;

•

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

•

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 an avian or other influenza, or other similar occurrences;

•

the direct or indirect effects on Southern Company’s business resulting from incidents similar to the August 2003 power outage in the Northeast;

•

the effect of accounting pronouncements issued periodically by standard setting bodies; and

•

other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.

Each registrant expressly disclaims any obligation to update any forward-looking statements.

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	3,997,659		$	4,478,292		$	10,355,330		$	10,933,784
Wholesale revenues		519,122			774,847			1,408,286			1,880,311
Other electric revenues		139,869			142,459			391,070			413,811
Other revenues		24,832			30,901			78,267			96,690

Total operating revenues		4,681,482			5,426,499			12,232,953			13,324,596

Operating Expenses:
Fuel		1,733,527			2,152,828			4,588,932			5,226,845
Purchased power		166,791			378,259			407,623			668,423
Other operations and maintenance		820,889			908,404			2,523,184			2,720,219
MC Asset Recovery litigation settlement		—			—			202,000			—
Depreciation and amortization		332,117			367,014			1,099,216			1,069,644
Taxes other than income taxes		212,882			215,298			620,851			602,612

Total operating expenses		3,266,206			4,021,803			9,441,806			10,287,743

Operating Income		1,415,276			1,404,696			2,791,147			3,036,853
Other Income and (Expense):
Allowance for equity funds used during construction		51,061			35,541			141,173			111,612
Interest income		6,013			9,744			17,791			20,737
Equity in income (losses) of unconsolidated subsidiaries		(34	)		4,704			(330	)		6,129
Leveraged lease income (losses)		6,578			6,343			24,695			(53,611	)
Gain on disposition of lease termination		—			—			26,300			—
Loss on extinguishment of debt		—			—			(17,184	)		—
Interest expense, net of amounts capitalized		(226,345	)		(219,066	)		(684,902	)		(665,123	)
Other income (expense), net		(10,432	)		(10,816	)		(26,963	)		(14,385	)

Total other income and (expense)		(173,159	)		(173,550	)		(519,420	)		(594,641	)

Earnings Before Income Taxes		1,242,117			1,231,146			2,271,727			2,442,212
Income taxes		435,947			434,515			828,833			837,605

Consolidated Net Income		806,170			796,631			1,442,894			1,604,607
Dividends on Preferred and Preference Stock of Subsidiaries		16,195			16,195			48,585			48,585

Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	789,975		$	780,436		$	1,394,309		$	1,556,022

Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.99		$	1.01		$	1.77		$	2.02
Diluted EPS	$	0.99		$	1.00		$	1.76		$	2.01
Average number of shares of common stock outstanding (in thousands)
Basic		798,418			772,622			789,675			769,298
Diluted		800,178			776,903			791,259			773,451
Cash dividends paid per share of common stock	$	0.4375		$	0.4200		$	1.2950		$	1.2425

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2009			2008
	(in thousands)
Operating Activities:
Consolidated net income	$	1,442,894		$	1,604,607
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		1,310,854			1,265,696
Deferred income taxes and investment tax credits		(14,565	)		46,006
Deferred revenues		(40,781	)		94,924
Allowance for equity funds used during construction		(141,173	)		(111,612	)
Equity in income (losses) of unconsolidated subsidiaries		330			(6,129	)
Leveraged lease income (losses)		(24,695	)		53,611
Gain on disposition of lease termination		(26,300	)		—
Loss on extinguishment of debt		17,184			—
Pension, postretirement, and other employee benefits		42,775			75,965
Stock option expense		20,850			17,730
Hedge settlements		(16,167	)		17,289
Other, net		10,036			(56,200	)
Changes in certain current assets and liabilities —
-Receivables		319,286			(522,004	)
-Fossil fuel stock		(361,520	)		(112,328	)
-Materials and supplies		(40,811	)		(25,347	)
-Other current assets		(50,977	)		(33,896	)
-Accounts payable		(210,459	)		(45,079	)
-Accrued taxes		238,988			409,684
-Accrued compensation		(273,349	)		(86,436	)
-Other current liabilities		157,384			49,651

Net cash provided from operating activities		2,359,784			2,636,132

Investing Activities:
Property additions		(3,179,009	)		(2,860,118	)
Investment in restricted cash from pollution control revenue bonds		(49,528	)		(5,454	)
Distribution of restricted cash from pollution control revenue bonds		90,088			46,782
Nuclear decommissioning trust fund purchases		(1,066,688	)		(581,171	)
Nuclear decommissioning trust fund sales		1,019,401			574,291
Proceeds from property sales		339,911			5,718
Cost of removal, net of salvage		(85,022	)		(74,714	)
Change in construction payables		110,265			(8,703	)
Other investing activities		(35,766	)		(76,402	)

Net cash used for investing activities		(2,856,348	)		(2,979,771	)

Financing Activities:
Increase in notes payable, net		118,124			62,302
Proceeds —
Long-term debt issuances		2,216,010			2,416,035
Common stock issuances		668,529			381,200
Redemptions —
Long-term debt		(1,229,484	)		(769,789	)
Redeemable preferred stock		—			(125,000	)
Payment of common stock dividends		(1,018,928	)		(954,438	)
Payment of dividends on preferred and preference stock of subsidiaries		(48,675	)		(49,497	)
Other financing activities		(18,732	)		(11,705	)

Net cash provided from financing activities		686,844			949,108

Net Change in Cash and Cash Equivalents		190,280			605,469
Cash and Cash Equivalents at Beginning of Period		416,581			200,550

Cash and Cash Equivalents at End of Period	$	606,861		$	806,019

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $59,849 and $54,404 capitalized for 2009 and 2008, respectively)	$	589,919		$	575,597
Income taxes (net of refunds)	$	644,541		$	489,600

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	606,861		$	416,581
Restricted cash and cash equivalents		66,403			102,537
Receivables —
Customer accounts receivable		1,234,810			1,053,674
Unbilled revenues		394,815			320,439
Under recovered regulatory clause revenues		416,805			646,318
Other accounts and notes receivable		270,348			301,028
Accumulated provision for uncollectible accounts		(29,044	)		(26,326	)
Fossil fuel stock, at average cost		1,373,037			1,018,314
Materials and supplies, at average cost		795,622			756,746
Vacation pay		135,061			140,283
Prepaid expenses		372,951			301,570
Other regulatory assets, current		193,710			275,424
Other current assets		50,554			51,044

Total current assets		5,881,933			5,357,632

Property, Plant, and Equipment:
In service		52,326,502			50,618,219
Less accumulated depreciation		18,985,998			18,285,800

Plant in service, net of depreciation		33,340,504			32,332,419
Nuclear fuel, at amortized cost		536,191			510,274
Construction work in progress		4,265,084			3,035,795

Total property, plant, and equipment		38,141,779			35,878,488

Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,060,161			864,396
Leveraged leases		606,165			897,338
Miscellaneous property and investments		228,594			226,757

Total other property and investments		1,894,920			1,988,491

Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,033,025			972,781
Unamortized debt issuance expense		209,607			207,763
Unamortized loss on reacquired debt		260,077			270,919
Deferred under recovered regulatory clause revenues		317,780			606,483
Other regulatory assets, deferred		2,404,534			2,636,217
Other deferred charges and assets		380,552			428,432

Total deferred charges and other assets		4,605,575			5,122,595

Total Assets	$	50,524,207		$	48,347,206

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

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


	At September 30,			At December 31,
Liabilities and Stockholders’ Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	412,295		$	616,415
Notes payable		1,064,694			953,437
Accounts payable		1,158,560			1,249,694
Customer deposits		325,035			302,495
Accrued taxes —
Accrued income taxes		176,299			195,922
Unrecognized tax benefits		160,649			131,641
Other accrued taxes		423,540			396,206
Accrued interest		227,821			195,500
Accrued vacation pay		168,955			178,519
Accrued compensation		191,139			446,718
Liabilities from risk management activities		147,464			260,977
Other regulatory liabilities, current		422,199			78,360
Other current liabilities		297,364			220,351

Total current liabilities		5,176,014			5,226,235

Long-term Debt		18,010,235			16,816,438

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		6,350,882			6,080,104
Deferred credits related to income taxes		257,581			259,156
Accumulated deferred investment tax credits		435,785			455,398
Employee benefit obligations		2,023,883			2,057,424
Asset retirement obligations		1,235,309			1,182,769
Other cost of removal obligations		1,048,279			1,320,558
Other regulatory liabilities, deferred		241,160			261,970
Other deferred credits and liabilities		301,167			329,534

Total deferred credits and other liabilities		11,894,046			11,946,913

Total Liabilities		35,080,295			33,989,586

Redeemable Preferred Stock of Subsidiaries		374,496			374,496

Stockholders’ Equity:
Common Stockholders’ Equity:
Common stock, par value $5 per share —
Authorized — 1 billion shares
Issued — September 30, 2009: 800,693,706 Shares;
— December 31, 2008: 777,615,751 Shares
Treasury — September 30, 2009: 482,328 Shares;
— December 31, 2008: 423,477 Shares
Par value		4,003,446			3,888,041
Paid-in capital		2,469,185			1,892,802
Treasury, at cost		(14,042	)		(12,279	)
Retained earnings		7,987,893			7,611,977
Accumulated other comprehensive loss		(84,433	)		(104,784	)

Total Common Stockholders’ Equity		14,362,049			13,275,757
Preferred and Preference Stock of Subsidiaries		707,367			707,367

Total Stockholders’ Equity		15,069,416			13,983,124

Total Liabilities and Stockholders’ Equity	$	50,524,207		$	48,347,206

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Consolidated Net Income	$	806,170		$	796,631		$	1,442,894		$	1,604,607
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1,356), $11,996, $(2,338), and $579, respectively		(2,151	)		18,603			(3,815	)		690
Reclassification adjustment for amounts included in net income, net of tax of $4,610, $1,730, $13,073, and $5,879, respectively		7,339			2,709			20,807			9,217
Marketable securities:
Change in fair value, net of tax of $(1,056), $163, $239, and $(2,293), respectively		(1,359	)		86			2,310			(3,940	)
Reclassification adjustment for amounts included in net income, net of tax of $-, $3, $-, and $3, respectively		—			4			—			4
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $222, $237, $665, and $773, respectively		350			376			1,049			1,258

Total other comprehensive income (loss)		4,179			21,778			20,351			7,229

Dividends on preferred and preference stock of subsidiaries		(16,195	)		(16,195	)		(48,585	)		(48,585	)

Comprehensive Income	$	794,154		$	802,214		$	1,414,660		$	1,563,251

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

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

THIRD QUARTER 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008

OVERVIEW

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

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Southern Company in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Southern Company’s third quarter 2009 net income after dividends on preferred and preference stock of subsidiaries was $790.0 million ($0.99 per share) compared to $780.4 million ($1.01 per share) for the corresponding period in 2008. The increase for the third quarter 2009 when compared to the corresponding period in 2008 was primarily the result of an increase in revenues from customer charges at Alabama Power, increased recognition of environmental compliance cost recovery revenues at Georgia Power in accordance with its 2007 Retail Rate Plan, lower operations and maintenance expenses, amortization of the regulatory liability related to other cost of removal obligations at Georgia Power, and an increase in allowance for equity funds used during construction (AFUDC), which is not taxable. The increase for the third quarter 2009 was partially offset by a decrease in revenues from lower KWH demand by industrial customers, a decrease in revenues from market-response rates to large commercial and industrial customers, and unfavorable weather as compared to the corresponding period in 2008.

Southern Company’s year-to-date 2009 net income after dividends on preferred and preference stock of subsidiaries was $1.39 billion ($1.77 per share) compared to $1.56 billion ($2.02 per share) for the corresponding period in 2008. The decrease for year-to-date 2009 when compared to the corresponding period in 2008 was primarily the result of a litigation settlement with MC Asset Recovery, LLC (MC Asset Recovery), a decrease in revenues from lower KWH demand by residential and industrial customers, a decrease in revenues from market-response rates to large commercial and industrial customers, unfavorable weather, higher depreciation and amortization, and higher interest expense. The decrease for year-to-date 2009 was partially offset by an increase in revenues from customer charges at Alabama Power, increased recognition of environmental compliance cost recovery revenues at Georgia Power in accordance with its 2007 Retail Rate Plan, lower operations and maintenance expenses, an increase in AFUDC, which is not taxable, a 2008 charge related to tax treatment of leveraged lease investments, and a gain on the early termination of two international leveraged lease investments.

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

Retail Revenues

In the third quarter 2009, retail revenues were $4.00 billion compared to $4.48 billion for the corresponding period in 2008.

For year-to-date 2009, retail revenues were $10.36 billion compared to $10.93 billion for the corresponding period in 2008.

Details of the change to retail revenues are as follows:


	Third Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	4,478.3					$	10,933.8
Estimated change in —
Rates and pricing		4.5			0.1			92.3			0.8
Sales growth (decline)		(54.1	)		(1.2	)		(195.3	)		(1.8	)
Weather		(39.6	)		(0.9	)		(35.2	)		(0.3	)
Fuel and other cost recovery		(391.4	)		(8.7	)		(440.3	)		(4.0	)

Retail – current year	$	3,997.7			(10.7	)%	$	10,355.3			(5.3	)%

Revenues associated with changes in rates and pricing increased in the third quarter and for year-to-date 2009 when compared to the corresponding periods in 2008 primarily as a result of an increase in revenues from customer charges at Alabama Power and increased recognition of environmental compliance cost recovery revenues at Georgia Power in accordance with its 2007 Retail Rate Plan, partially offset by a decrease in revenues from market-response rates to large commercial and industrial customers.

Revenues attributable to changes in sales declined in the third quarter and for year-to-date 2009 when compared to the corresponding periods in 2008 due to decreases in weather-adjusted retail KWH sales of 3.4% and 5.3%, respectively, resulting primarily from recessionary economic conditions. For the third quarter 2009, weather-adjusted residential KWH sales remained flat, weather-adjusted commercial KWH sales decreased 2.1%, and weather-adjusted industrial KWH sales decreased 9.3%. For year-to-date 2009, weather-adjusted residential KWH sales remained flat, weather-adjusted commercial KWH sales decreased 1.3%, and weather-adjusted industrial KWH sales decreased 14.6%. Reduced demand in the primary metals, fabricated metal, chemical, and textiles sectors, as well as reduced demand in the stone, clay, and glass sector, contributed most significantly to the decreases in weather-adjusted industrial KWH sales in the third quarter and for year-to-date 2009 when compared to the corresponding periods in 2008. While weather-adjusted industrial KWH sales for the third quarter 2009 decreased 9.3% when compared to the corresponding period in 2008, weather-adjusted industrial KWH sales increased 12.0% when compared to the second quarter 2009.

Revenues resulting from changes in weather decreased in the third quarter and for year-to-date 2009 as a result of unfavorable weather when compared to the corresponding periods in 2008.

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 in the third quarter and for year-to-date 2009 when compared to the corresponding periods in 2008. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues

In the third quarter 2009, wholesale revenues were $519.1 million compared to $774.8 million for the corresponding period in 2008. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $258.8 million in the third quarter 2009 when compared to the corresponding period in 2008. Excluding wholesale fuel revenues, wholesale revenues increased $3.1 million in the third quarter 2009 when compared to the corresponding period in 2008. The increase was primarily the result of additional revenues associated with a new PPA at Southern Power’s Plant Franklin Unit 3 which began in January 2009.

For year-to-date 2009, wholesale revenues were $1.41 billion compared to $1.88 billion for the corresponding period in 2008. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $484.8 million for year-to-date 2009 when compared to the corresponding period in 2008. Excluding wholesale fuel revenues, wholesale revenues increased $12.8 million for year-to-date 2009 when compared to the corresponding period in 2008. The increase was primarily the result of additional revenues associated with a new PPA at Southern Power’s Plant Franklin Unit 3 which began in January 2009, partially offset by fewer short-term opportunity sales due to lower energy prices and reduced margins on short-term opportunity sales when compared to the corresponding period in 2008.

Short-term opportunity sales are made at market-based rates that generally provide a margin above Southern Company’s variable cost to produce the energy.

Other Electric Revenues

In the third quarter 2009, other electric revenues were $139.9 million compared to $142.5 million for the corresponding period in 2008. The decrease when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, other electric revenues were $391.1 million compared to $413.8 million for the corresponding period in 2008. The decrease was primarily the result of a $39.6 million decrease in co-generation revenues due to lower gas prices and a decline in sales volume, partially offset by a $7.3 million increase in customer fees. Revenues from co-generation are generally offset by related expenses and do not affect net income.

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

Other Revenues

In the third quarter 2009, other revenues were $24.8 million compared to $30.9 million for the corresponding period in 2008. The decrease was primarily the result of a $5.9 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers as a result of increased competition in the industry when compared to the corresponding period in 2008.

For year-to-date 2009, other revenues were $78.3 million compared to $96.7 million for the corresponding period in 2008. The decrease was primarily the result of an $18.0 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers as a result of increased competition in the industry when compared to the corresponding period in 2008.

Fuel and Purchased Power Expenses


	Third Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Third Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	(419.3	)		(19.5	)	$	(637.9	)		(12.2	)
Purchased power		(211.5	)		(55.9	)		(260.8	)		(39.0	)

Total fuel and purchased power expenses	$	(630.8	)				$	(898.7	)

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

In the third quarter 2009, fuel and purchased power expenses were $1.90 billion compared to $2.53 billion for the corresponding period in 2008. The decrease was primarily the result of a $317.9 million net decrease related to total KWHs generated and purchased and a $312.9 million net decrease in the average cost of fuel and purchased power when compared to the corresponding period in 2008. The net decrease in the average cost of fuel and purchased power for the third quarter 2009 resulted primarily from lower gas prices and a significant increase in hydro generation due to increased rainfall when compared to the corresponding period in 2008.

For year-to-date 2009, fuel and purchased power expenses were $5.00 billion compared to $5.90 billion for the corresponding period in 2008. The decrease was primarily the result of a $602.8 million net decrease related to total KWHs generated and purchased and a $295.9 million net decrease in the average cost of fuel and purchased power when compared to the corresponding period in 2008. The net decrease in the average cost of fuel and purchased power for year-to-date 2009 resulted primarily from lower gas prices and a significant increase in hydro generation due to increased rainfall when compared to the corresponding period in 2008.

Fuel expenses at the traditional operating companies are generally offset by fuel revenues and do not affect net income. See FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters – Retail Fuel Cost Recovery” herein for additional information. Fuel expenses incurred under Southern Power’s PPAs are generally the responsibility of the counterparties and do not significantly affect net income.

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

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


	Third Quarter		Third Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2009		2008		Change			2009		2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		3.42		3.96		(13.6	)		3.39		3.46		(2.0	)
Purchased power		8.00		9.70		(17.5	)		6.20		9.02		(31.3	)

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

Other Operations and Maintenance Expenses

In the third quarter 2009, other operations and maintenance expenses were $820.9 million compared to $908.4 million for the corresponding period in 2008. The decrease was primarily the result of a $32.7 million decrease in fossil, hydro, and nuclear expenses mainly due to less planned spending on outages and maintenance, as well as other cost containment activities, which were the result of efforts to offset the effects of the recessionary economy; a $16.1 million decrease in transmission and distribution expenses mainly due to lower maintenance expenses; a $9.6 million decrease in expenses related to customer service and sales; a $4.3 million decrease in expenses related to lower sales and fewer subscribers at SouthernLINC Wireless; and a $4.1 million decrease in administrative and general expenses mainly due to a decrease in accrued expenses for the litigation and workers’ compensation reserve.

For year-to-date 2009, other operations and maintenance expenses were $2.52 billion compared to $2.72 billion for the corresponding period in 2008. The decrease was primarily the result of an $80.0 million decrease in fossil, hydro, and nuclear expenses mainly due to less planned spending on outages and maintenance, as well as other cost containment activities, which were the result of efforts to offset the effects of the recessionary economy; a $57.1 million decrease in transmission and distribution expenses mainly due to lower maintenance expenses, as well as other cost containment activities; a $16.5 million decrease in expenses related to customer service and sales; a $14.4 million decrease in expenses related to lower sales and fewer subscribers at SouthernLINC Wireless; and a $13.9 million decrease in expenses related to lower litigation costs resulting from the litigation settlement with MC Asset Recovery in the first quarter 2009, as well as the fourth quarter 2008 settlement with the IRS regarding several leveraged lease investments. See Note (B) to the Condensed Financial Statements under “Mirant Matters – MC Asset Recovery Litigation” and “Income Tax Matters – Leveraged Leases” herein for additional information. Partially offsetting the year-to-date 2009 decrease was a $15.8 million increase in administration and general expenses largely related to the $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition program at Georgia Power under which 579 employees elected to resign their positions effective March 31, 2009. Through the third quarter 2009, approximately two-thirds of the $29.4 million charge was offset by lower salary and employee benefits costs, and the remaining one-third will be offset during the fourth quarter 2009. This charge is not expected to have a material impact on Southern Company financial statements for the year ending December 31, 2009.

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MC Asset Recovery Litigation Settlement

N/M – Not Meaningful

In the first quarter 2009, Southern Company entered into a litigation settlement agreement with MC Asset Recovery which resulted in a charge of $202.0 million. See Note (B) to the Condensed Financial Statements under “Mirant Matters – MC Asset Recovery Litigation” herein for additional information.

Depreciation and Amortization

In the third quarter 2009, depreciation and amortization was $332.1 million compared to $367.0 million for the corresponding period in 2008. The decrease was primarily the result of $54.0 million of amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC, partially offset by an increase in plant in service related to environmental, transmission, and distribution projects at Georgia Power.

For year-to-date 2009, depreciation and amortization was $1.10 billion compared to $1.07 billion for the corresponding period in 2008. The increase was primarily the result of an increase in plant in service related to environmental, transmission, and distribution projects at Alabama Power and Georgia Power and the completion of Southern Power’s Plant Franklin Unit 3 in June 2008, as well as an increase in depreciation rates at Southern Power. The increase was partially offset by $54.0 million of amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC.

See FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters – Retail Rate Matters” herein for additional information regarding the Georgia PSC order.

Taxes Other Than Income Taxes

In the third quarter 2009, taxes other than income taxes were $212.9 million compared to $215.3 million for the corresponding period in 2008. The decrease when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, taxes other than income taxes were $620.9 million compared to $602.6 million for the corresponding period in 2008. The increase was primarily the result of increases in state and municipal public utility license tax bases at Alabama Power and increases in franchise fees at Gulf Power. Increases in franchise fees are associated with increases in revenues from retail energy sales.

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Allowance for Equity Funds Used During Construction

In the third quarter 2009, AFUDC was $51.1 million compared to $35.5 million for the corresponding period in 2008.

For year-to-date 2009, AFUDC was $141.2 million compared to $111.6 million for the corresponding period in 2008.

The third quarter and year-to-date 2009 increases were primarily the result of additional investments in environmental projects at Alabama Power and Gulf Power, as well as additional investments in transmission and distribution projects at Alabama Power.

Leveraged Lease Income (Losses)

In the third quarter 2009, leveraged lease income (losses) was $6.6 million compared to $6.3 million for the corresponding period in 2008. The increase when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, leveraged lease income (losses) was $24.7 million compared to $(53.6) million for the corresponding period in 2008. Southern Company has several leveraged lease investments in international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The year-to-date 2009 increase was primarily the result of the 2008 application of certain accounting standards related to leveraged leases, including a second quarter 2008 after tax charge of $51.2 million. See Note (B) to the Condensed Financial Statements under “Income Tax Matters – Leveraged Leases” herein for additional information.

Gain on Disposition of Lease Termination

N/M — Not Meaningful

In the second quarter 2009, Southern Company terminated two international leveraged lease investments early, which resulted in a gain of $26.3 million.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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Loss on Extinguishment of Debt

N/M — Not Meaningful

In the second quarter 2009, Southern Company terminated two international leveraged lease investments early. The proceeds from the terminations were required to be used to extinguish all debt related to leveraged lease investments, a portion of which had make-whole redemption provisions which resulted in a loss of $17.2 million.

Interest Expense, Net of Amounts Capitalized

In the third quarter 2009, interest expense, net of amounts capitalized was $226.3 million compared to $219.1 million for the corresponding period in 2008. The increase when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, interest expense, net of amounts capitalized was $684.9 million compared to $665.1 million for the corresponding period in 2008. The increase in expense was primarily the result of an $83.0 million increase associated with $1.30 billion in additional debt outstanding at September 30, 2009 compared to September 30, 2008. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Southern Company in Item 7 of the Form 10-K and herein for additional information. Partially offsetting this increase was a $44.3 million decrease related to lower average interest rates on existing variable rate debt, including the impact of hedges, a $13.4 million decrease related to other interest charges, and $5.5 million of additional capitalized interest when compared to the corresponding period in 2008.

Other Income (Expense), Net

In the third quarter 2009, other income (expense), net was $(10.4) million compared to $(10.8) million for the corresponding period in 2008. The decrease in expense when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, other income (expense), net was $(27.0) million compared to $(14.4) million for the corresponding period in 2008. The increase in expense was primarily the result of the first quarter 2008 recognition of a $6.4 million fee received for participating in an asset auction and a $6.0 million gain on the sale of an undeveloped tract of land to the Orlando Utilities Commission.

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

Income Taxes

In the third quarter 2009, income taxes were $435.9 million compared to $434.5 million for the corresponding period in 2008. The increase was primarily the result of higher pre-tax earnings, largely offset by the third quarter 2009 increase in AFUDC, which is not taxable. See Note (G) to the Condensed Financial Statements under “Effective Tax Rate” herein for details regarding the impact of AFUDC on the effective tax rate.

For year-to-date 2009, income taxes were $828.8 million compared to $837.6 million for the corresponding period in 2008. The decrease was primarily the result of lower pre-tax earnings, lower tax expense associated with the early termination of one of the international leveraged lease investments and the extinguishment of the associated debt discussed previously under “Gain on Disposition of Lease Termination” and “Loss on Extinguishment of Debt,” and the year-to-date increase in AFUDC, which is not taxable. Partially offsetting this decrease was the $202.0 million charge resulting from the litigation settlement with MC Asset Recovery in the first quarter 2009, which has not been deducted for tax purposes. See Note (G) to the Condensed Financial Statements under “Effective Tax Rate” herein for details regarding the impact of the early lease termination, AFUDC, and the MC Asset Recovery litigation settlement on the effective tax rate.

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 recovery of prudently incurred costs during a time of increasing costs and 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 area. 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 in the Southeast, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Recessionary conditions have negatively impacted sales for the traditional operating companies and have negatively impacted wholesale capacity revenues at Southern Power. The current economic recession is expected to continue to have a negative impact on energy sales, particularly to industrial and commercial customers. The timing and extent of the economic recovery 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 Company in Item 7 of the Form 10-K.

Environmental Matters

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Carbon Dioxide Litigation – New York Case” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters – Carbon Dioxide Litigation - New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Carbon Dioxide Litigation – Kivalina Case” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Environmental Statutes and Regulations – Air Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Southern Company’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Environmental Statutes and Regulations – Water Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

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

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 information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.

In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Southern Company’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and State PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

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

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past several years, the traditional operating companies have experienced higher than expected fuel costs for coal, natural gas, and uranium. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power of approximately $697 million at September 30, 2009. During the third quarter 2009, Alabama Power and Mississippi Power collected all previously under recovered fuel costs and, as of September 30, 2009, have a total over recovered fuel balance of $66 million. The total under recovered fuel costs included in the balance sheets of the traditional operating companies at December 31, 2008 was $1.2 billion. Operating revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes to the billing factors will have no significant effect on Southern Company’s revenues or net income but will affect cash flow. The traditional operating companies continuously monitor the under or over recovered fuel cost balance. 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 “Alabama Power Retail Regulatory Matters,” “Georgia Power Retail Regulatory Matters,” and “Gulf Power Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

On March 10, 2009, the Georgia PSC granted Georgia Power’s request to delay its fuel case filing until September 4, 2009 and, on August 27, 2009, the Georgia PSC approved an additional delay in the filing date to no later than December 15, 2009 (with new rates to be effective April 1, 2010).

Retail Rate Matters

Under the 2007 Retail Rate Plan, Georgia Power’s earnings are evaluated against a retail return on equity (ROE) range of 10.25% to 12.25%. In connection with the 2007 Retail Rate Plan, the Georgia PSC ordered that Georgia Power file its next general base rate case by July 1, 2010; however, the 2007 Retail Rate Plan provided that Georgia Power may file for a general base rate increase in the event its projected retail ROE falls below 10.25%.

The economic recession has significantly reduced Georgia Power’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. Despite stringent efforts to reduce expenses, current projections indicate Georgia Power’s retail ROE will be less than 10.25% in both 2009 and 2010. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations.

On August 27, 2009, the Georgia PSC approved the accounting order. Under the terms of the accounting order, if Georgia Power does not file for a retail base rate increase in 2009, Georgia Power will be entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009. Through September 30, 2009, Georgia Power has amortized $54 million of the regulatory liability. In addition, Georgia Power will be entitled to amortize up to two-thirds of the regulatory liability ($216 million) in 2010. In the event Georgia Power files for a retail base rate increase prior to July 1, 2010, then the amortization of the regulatory liability in 2010 would be reduced by one-sixth for each month that such rate case is filed prior to July 1, 2010.

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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Furthermore, the amortization of the regulatory liability is limited to only the amount that would allow Georgia Power to earn a retail ROE not more than 9.75% in 2009 and 10.15% in 2010. In addition, Georgia Power may not file for a base rate increase prior to July 1, 2010 unless economic conditions beyond its control continue to reduce Georgia Power’s projected retail ROE and in no event unless Georgia Power’s projected retail ROE for 2009 or 2010 is less than 9.25% after taking into consideration amortization of the regulatory liability.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Southern Company. Southern Company estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $225 million and $275 million. On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Southern Company continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Construction Projects

Integrated Coal Gasification Combined Cycle

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

On May 11, 2009, Mississippi Power received notification from the IRS formally certifying the Internal Revenue Code Section 48A tax credits of $133 million to Mississippi Power. The utilization of these credits is dependent upon meeting the certification requirements for the Kemper IGCC, including an in-service date no later than May 2014.

On April 6, 2009, the Governor of the State of Mississippi signed into law a bill that will provide an ad valorem tax exemption for a portion of the assessed value of all property utilized in certain electric generating facilities with integrated gasification process facilities. This tax exemption, which may not exceed 50% of the total value of the project, is for projects with a capital investment from private sources of $1 billion or more. Mississippi Power expects the Kemper IGCC, including the gasification portion, to be a qualifying project under the law.

On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures. The Mississippi PSC’s determination of prudence for Mississippi Power’s pre-construction costs is scheduled to occur by May 2010. As of September 30, 2009, Mississippi Power had spent a total of $64.5 million associated with Mississippi Power’s generation resource planning, evaluation, and screening activities, including regulatory filing costs. Costs incurred for the nine months ended September 30, 2009 totaled $22.2 million as compared to $18.1 million for the nine months ended September 30, 2008. Of the total $64.5 million, $59.8 million was deferred in other regulatory assets, $3.9 million was related to land purchases capitalized, and $0.8 million was previously expensed.

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

Several motions were filed by intervenors, most of which were procedural in nature and sought to stay or delay the timely and orderly administration of the docket. In addition to these procedural motions, a motion was filed by the Attorney General for the State of Mississippi which questioned whether the Mississippi PSC had authority to approve the gasification portion of the Kemper IGCC. On June 5, 2009, all of these motions were denied by the Mississippi PSC.

On June 5, 2009, the Mississippi PSC issued an order initiating an evaluation of the Kemper IGCC and establishing a two-phase procedural schedule. During Phase I, the Mississippi PSC will determine if a need exists for new generating resources. Hearings for Phase I were held in October 2009, and a decision is expected in November 2009. If it is determined a need exists in Phase I, the appropriate resource to fill the need as well as the cost recovery of that resource through application of the State of Mississippi’s Baseload Act of 2008 will be determined during Phase II. Hearings regarding Phase II issues are scheduled for February 2010 with a decision by May 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Mississippi Base Load Construction Legislation” of Southern Company in Item 7 of the Form 10-K for information regarding the Baseload Act of 2008.

On September 15, 2009, South Mississippi Electric Power Association (SMEPA) signed a non-binding letter of intent to explore the acquisition of an interest in the Kemper IGCC. Mississippi Power and SMEPA are evaluating a combination of a joint ownership arrangement and a PPA which would provide SMEPA with up to 20% of the capacity and associated energy output from the Kemper IGCC.

The ultimate outcome of these matters cannot now be determined.

Nuclear

See Note (B) to the Condensed Financial Statements under “Construction Projects – Nuclear” herein for information regarding the potential expansion of Plant Vogtle.

On March 17, 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 at an in-service cost of $6.4 billion. In addition, the Georgia PSC voted to approve inclusion of the related construction work in progress accounts in rate base and to recover financing costs during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.5 billion.

On April 21, 2009, the Governor of the State of Georgia signed into law the Georgia Nuclear Energy Financing Act that will allow Georgia Power to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period. The cost recovery provisions will become effective January 1, 2011.

On June 15, 2009, an environmental group filed a petition in the Superior Court of Fulton County, Georgia seeking review of the Georgia PSC’s certification order and challenging the constitutionality of the Georgia Nuclear Energy Financing Act. Georgia Power believes there is no meritorious basis for this petition and intends to vigorously defend against the requested actions. The ultimate outcome of this matter cannot be determined at this time.

On August 26, 2009, the NRC issued the Early Site Permit and Limited Work Authorization for Plant Vogtle Units 3 and 4. Excavation for the new units is in progress.

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

On August 27, 2009, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors and expressing concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. Georgia Power is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible delays in the AP1000 design certification schedule, including those addressed by the NRC in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units 3 and 4. The ultimate outcome of this matter cannot be determined at this time.

On August 31, 2009, Georgia Power filed with the Georgia PSC its first semi-annual construction monitoring report for Plant Vogtle Units 3 and 4 for the period ended June 30, 2009 which did not include any change to the estimated construction cost as certified by the Georgia PSC in March 2009. The Georgia PSC will conduct hearings between November 2009 and January 2010 in review of this report and is scheduled to render its decision on February 18, 2010. The ultimate outcome of this matter cannot be determined at this time.

There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds. The ultimate outcome of these matters cannot now be determined.

Nuclear Relicensing

The NRC operating licenses for Plant Vogtle Units 1 and 2 were scheduled to expire in January 2027 and February 2029, respectively. In June 2007, Georgia Power filed an application with the NRC to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. On June 3, 2009, the NRC approved the extension of the licenses as requested.

Other Matters

Southern Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury 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 emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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 accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Unbilled Revenues.

New Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Southern Company is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Southern Company and its subsidiaries have maintained adequate access to capital without drawing on any committed bank credit arrangements used to support commercial paper programs and variable rate pollution control revenue bonds. 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. Market rates for committed credit have increased, and Southern Company and its subsidiaries have been and expect to continue to be subject to higher costs as existing facilities are replaced or renewed. Total committed credit fees for Southern Company and its subsidiaries currently average less than ¹/2 of 1% per year. Southern Company’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Southern Company experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Southern Company’s investments in pension and nuclear decommissioning trust funds remained stable during the third quarter 2009. Southern Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Southern Company does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.

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

For the first nine months of 2009, net cash provided from operating activities totaled $2.4 billion, a decrease of $276 million from the corresponding period in 2008. Significant changes in operating cash flow for the first nine months of 2009 as compared to the corresponding period in 2008 include a reduction to net income as previously discussed and increased levels of coal inventory of $249 million. These uses of funds were partially offset by increased cash inflows as a result of higher fuel cost recovery rates included in customer billings. Net cash used for investing activities totaled $2.9 billion for the first nine months of 2009 as compared to $3.0 billion for the corresponding period in 2008. While the cash outflows in each of these periods were primarily related to property additions to utility plant, the decrease in the current period as compared to the corresponding period in 2008 was primarily due to approximately $340 million in cash received from the early termination of two leveraged lease investments. For the first nine months of 2009, net cash provided from financing activities totaled $687 million as compared to $949 million for the corresponding period in 2008. The funds available from financing activities were primarily attributable to cash inflows from short-term borrowings, the issuance of new long-term debt, and common stock issuances, partially offset by cash outflows for repayments of long-term debt and dividend payments.

Significant balance sheet changes for the first nine months of 2009 include an increase of $2.3 billion in total property, plant, and equipment for the installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other significant changes include an increase in long-term debt, excluding amounts due within one year, of $1.2 billion used primarily for construction expenditures and general corporate purposes and $1.1 billion of additional equity.

The market price of Southern Company’s common stock at September 30, 2009 was $31.67 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $17.95 per share, representing a market-to-book ratio of 176%, compared to $37.00, $17.08, and 217%, respectively, at the end of 2008. The dividend for the third quarter 2009 was $0.4375 per share compared to $0.42 per share in the third quarter 2008.

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 its construction programs 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 $412 million will be required through September 30, 2010 to fund maturities of long-term debt. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants 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; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of Southern Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2009, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. The traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes

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

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 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.

Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities), to meet liquidity needs. At September 30, 2009, Southern Company and its subsidiaries had approximately $607 million of cash and cash equivalents and approximately $4.7 billion of unused credit arrangements with banks, of which $99 million expire in 2009, $1.4 billion expire in 2010, $25 million expire in 2011, and $3.2 billion expire in 2012. Approximately $84 million of the credit facilities expiring in 2009 and 2010 allow for the execution of term loans for an additional two-year period, and $512 million contain provisions allowing one-year term loans. At September 30, 2009, approximately $1.6 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds and such credit facilities also serve as liquidity support for the commercial paper programs. See Note 6 to the financial statements of Southern Company under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. The traditional operating companies may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of each of the traditional operating companies. At September 30, 2009, the Southern Company system had outstanding commercial paper of $1.1 billion. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

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

Credit Rating Risk

Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $422 million. At September 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.1 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.

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

On September 2, 2009, Moody’s affirmed the credit ratings of Southern Company’s senior unsecured notes and commercial paper of A3/P-1, respectively, and revised the rating outlook for Southern Company to negative. On October 6, 2009, Standard and Poor’s affirmed the credit ratings of Southern Company’s senior unsecured notes and commercial paper of A-/A-1, respectively, and maintained a stable rating outlook. On September 4, 2009, Fitch affirmed Southern Company’s long-term and commercial paper credit ratings of A/F1, respectively, and maintained its stable rating outlook.

Market Price Risk

Southern Company’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Company 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, the traditional operating companies continue to have limited exposure to market volatility in interest rates, 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, during 2009, Southern Power is exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. 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. To mitigate residual risks relative to movements in gas prices, Southern Company’s subsidiaries may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. As such, the traditional operating companies have no material change in market risk exposure when compared with the December 31, 2008 reporting period.

The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:


	Third Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(302	)	$	(285	)
Contracts realized or settled		131			318
Current period changes^(a)		8			(196	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(163	)	$	(163	)

(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 months and nine months ended September 30, 2009 were an increase of $139 million and $122 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At September 30, 2009, Southern Company had a net hedge volume of 154 million mmBtu (includes location basis of 2 million mmBtu) with a weighted average contract cost approximately $1.09 per mmBtu above market prices, compared to 173 million mmBtu (includes location basis of 2 million mmBtu) at June 30, 2009 with a weighted average contract cost approximately $1.78 per mmBtu above market prices and compared to 149 million mmBtu at December 31, 2008 with a weighted average contract cost

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

approximately $1.97 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the traditional operating companies’ fuel cost recovery clauses.

At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:


Asset (Liability) Derivatives	September 30, 2009			December 31, 2008
	(in millions)
Regulatory hedges	$	(167	)	$	(288	)
Cash flow hedges		(1	)		(1	)
Not designated		5			4

Total fair value	$	(163	)	$	(285	)

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 designated as cash flow hedges are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Total net unrealized pre-tax gains recognized in the statements of income for the three months and nine months ended September 30, 2009 for energy-related derivative contracts that are not hedges were $2 million and $1 million, respectively. The total net unrealized gain recognized in the statements of income for the three months ended September 30, 2008 was $7 million and was not material for the nine months ended September 30, 2008. See Note (E) to the Condensed Financial Statements herein for further details of these gains (losses).

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:


	September 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(163	)		(123	)		(40	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(163	)	$	(123	)	$	(40	)	$	—

Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Southern Company in Item 7 and Notes 1 and 6 to the financial statements of Southern Company under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.

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

Financing Activities

In the first nine months of 2009, Southern Company issued $350 million of Series 2009A 4.15% Senior Notes due May 15, 2014, and its subsidiaries issued $1.3 billion of senior notes and incurred obligations of $600 million related to the issuance of pollution control revenue bonds. Southern Company also issued 17 million shares of common stock for $501 million through the Southern Investment Plan, Dividend Reinvestment Plan, and employee and director stock plans. In addition, Southern Company issued 6 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $167 million, net of $1.7 million in fees and commissions. The proceeds were primarily used to fund ongoing construction projects, to repay short-term and long-term indebtedness, and for general corporate purposes.

In July 2009, Gulf Power entered into a forward starting interest rate swap to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swap is $50 million, and the swap has been designated as a cash flow hedge.

In July 2009, Southern Company used a portion of the cash received from the early termination of two leveraged lease investments to extinguish $252.7 million of debt which included all debt related to leveraged lease investments and to pay make-whole redemption premiums of $17.2 million associated with such debt.

In August 2009, Georgia Power redeemed its $55 million of Series D 5.50% Senior Insured Quarterly Notes due November 15, 2017.

In August 2009, Georgia Power’s $125 million Series V 4.10% Senior Notes due August 15, 2009 matured.

In August 2009, Alabama Power’s $250 million Series BB Floating Rate Senior Notes due August 25, 2009 matured.

Subsequent to September 30, 2009, Southern Company issued $300 million of Series 2009B Floating Rate Senior Notes due October 21, 2011. The proceeds were used to repay short-term indebtedness and other general corporate purposes.

Subsequent to September 30, 2009, Georgia Power and Gulf Power entered into forward starting interest rate swaps to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amounts of the swaps totaled $200 million and $50 million, respectively, and the swaps have been designated as cash flow hedges.

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.

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 Notes 1 and 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Financial Instruments” in Item 8 of the Form 10-K. Also, see Note (E) 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 conducted an evaluation under the supervision and with the participation of Southern 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 this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.

(b) Changes in internal controls over financial reporting.

There have been no changes in Southern Company’s internal control over financial reporting (as such term is defined in Sections 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the third quarter 2009 that have materially affected or are reasonably likely to materially affect Southern Company’s internal control over financial reporting.

Item 4T. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures.

As of the end of the period covered by this quarterly report, 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 over financial reporting.

There have been no changes in 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 Sections 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the third quarter 2009 that have materially affected or are reasonably likely to materially affect Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	1,342,665		$	1,559,034		$	3,520,408		$	3,741,074
Wholesale revenues, non-affiliates		170,573			196,381			483,180			536,392
Wholesale revenues, affiliates		34,042			60,583			170,887			240,696
Other revenues		44,876			49,084			123,963			153,412

Total operating revenues		1,592,156			1,865,082			4,298,438			4,671,574

Operating Expenses:
Fuel		506,376			651,673			1,437,095			1,628,170
Purchased power, non-affiliates		42,915			104,238			84,582			153,907
Purchased power, affiliates		73,966			121,651			172,096			286,147
Other operations and maintenance		272,118			300,967			827,275			917,060
Depreciation and amortization		136,784			132,410			406,687			387,677
Taxes other than income taxes		77,353			76,200			239,673			227,585

Total operating expenses		1,109,512			1,387,139			3,167,408			3,600,546

Operating Income		482,644			477,943			1,131,030			1,071,028
Other Income and (Expense):
Allowance for equity funds used during construction		21,053			11,730			56,931			32,269
Interest income		4,419			4,794			12,689			13,694
Interest expense, net of amounts capitalized		(75,817	)		(71,165	)		(224,792	)		(209,787	)
Other income (expense), net		(6,714	)		(5,732	)		(17,577	)		(19,661	)

Total other income and (expense)		(57,059	)		(60,373	)		(172,749	)		(183,485	)

Earnings Before Income Taxes		425,585			417,570			958,281			887,543
Income taxes		154,050			156,109			344,416			323,335

Net Income		271,535			261,461			613,865			564,208
Dividends on Preferred and Preference Stock		9,866			9,866			29,598			29,598

Net Income After Dividends on Preferred and Preference Stock	$	261,669		$	251,595		$	584,267		$	534,610

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2009			2008		2009			2008
	(in thousands)					(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	261,669		$	251,595	$	584,267		$	534,610
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(187), $50, $(1,773), and $(989), respectively		(307	)		83		(2,916	)		(1,627	)
Reclassification adjustment for amounts included in net income, net of tax of $1,217, $82, $3,456, and $710, respectively		2,002			135		5,685			1,168

Total other comprehensive income (loss)		1,695			218		2,769			(459	)

Comprehensive Income	$	263,364		$	251,813	$	587,036		$	534,151

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

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	613,865		$	564,208
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		474,250			451,182
Deferred income taxes and investment tax credits, net		(32,333	)		109,459
Allowance for equity funds used during construction		(56,931	)		(32,269	)
Pension, postretirement, and other employee benefits		(2,955	)		(133	)
Stock option expense		3,475			2,822
Tax benefit of stock options		79			641
Other, net		25,223			22,717
Changes in certain current assets and liabilities —
-Receivables		232,890			(92,774	)
-Fossil fuel stock		(20,609	)		(61,753	)
-Materials and supplies		(22,783	)		(19,915	)
-Other current assets		(43,436	)		(33,840	)
-Accounts payable		(197,357	)		(62,186	)
-Accrued taxes		168,493			92,749
-Accrued compensation		(46,583	)		(27,786	)
-Other current liabilities		70,111			22,248

Net cash provided from operating activities		1,165,399			935,370

Investing Activities:
Property additions		(896,913	)		(1,024,668	)
Investment in restricted cash from pollution control revenue bonds		(340	)		(5,454	)
Distribution of restricted cash from pollution control revenue bonds		39,866			24,585
Nuclear decommissioning trust fund purchases		(177,639	)		(218,606	)
Nuclear decommissioning trust fund sales		177,639			218,606
Cost of removal, net of salvage		(21,419	)		(33,579	)
Other investing activities		10,342			(26,839	)

Net cash used for investing activities		(868,464	)		(1,065,955	)

Financing Activities:
Increase (decrease) in notes payable, net		(24,995	)		94,891
Proceeds —
Common stock issued to parent		135,000			225,000
Capital contributions from parent company		17,177			15,095
Gross excess tax benefit of stock options		173			1,226
Pollution control revenue bonds		53,000			131,100
Senior notes issuances		500,000			600,000
Redemptions —
Preferred stock		—			(125,000	)
Pollution control revenue bonds		—			(11,100	)
Senior notes		(250,000	)		(250,000	)
Payment of preferred and preference stock dividends		(29,602	)		(31,024	)
Payment of common stock dividends		(392,100	)		(368,475	)
Other financing activities		(2,647	)		(6,467	)

Net cash provided from financing activities		6,006			275,246

Net Change in Cash and Cash Equivalents		302,941			144,661
Cash and Cash Equivalents at Beginning of Period		28,181			73,616

Cash and Cash Equivalents at End of Period	$	331,122		$	218,277

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $23,813 and $14,649 capitalized for 2009 and 2008, respectively)	$	190,014		$	183,218
Income taxes (net of refunds)	$	274,486		$	197,907

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

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	331,122		$	28,181
Restricted cash and cash equivalents		40,554			80,079
Receivables —
Customer accounts receivable		422,926			350,410
Unbilled revenues		122,056			98,921
Under recovered regulatory clause revenues		31,949			153,899
Other accounts and notes receivable		30,210			44,645
Affiliated companies		58,844			70,612
Accumulated provision for uncollectible accounts		(9,891	)		(8,882	)
Fossil fuel stock, at average cost		337,873			322,089
Materials and supplies, at average cost		326,964			305,880
Vacation pay		52,949			52,577
Prepaid expenses		130,487			88,219
Other regulatory assets, current		42,121			74,825
Other current assets		14,726			12,915

Total current assets		1,932,890			1,674,370

Property, Plant, and Equipment:
In service		18,078,745			17,635,129
Less accumulated provision for depreciation		6,516,289			6,259,720

Plant in service, net of depreciation		11,562,456			11,375,409
Nuclear fuel, at amortized cost		231,110			231,862
Construction work in progress		1,474,821			1,092,516

Total property, plant, and equipment		13,268,387			12,699,787

Other Property and Investments:
Equity investments in unconsolidated subsidiaries		58,469			50,912
Nuclear decommissioning trusts, at fair value		465,208			403,966
Miscellaneous property and investments		68,488			62,782

Total other property and investments		592,165			517,660

Deferred Charges and Other Assets:
Deferred charges related to income taxes		390,240			362,596
Prepaid pension costs		197,172			166,334
Deferred under recovered regulatory clause revenues		—			180,874
Other regulatory assets, deferred		690,530			732,367
Other deferred charges and assets		198,898			202,018

Total deferred charges and other assets		1,476,840			1,644,189

Total Assets	$	17,270,282		$	16,536,006

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

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	—		$	250,079
Notes payable		—			24,995
Accounts payable —
Affiliated		166,865			178,708
Other		210,348			358,176
Customer deposits		85,242			77,205
Accrued taxes —
Accrued income taxes		95,262			18,299
Other accrued taxes		96,857			30,372
Accrued interest		69,985			56,375
Accrued vacation pay		44,217			44,217
Accrued compensation		54,687			91,856
Liabilities from risk management activities		48,780			83,873
Other regulatory liabilities, current		56,616			3,462
Other current liabilities		40,140			50,315

Total current liabilities		968,999			1,267,932

Long-term Debt		6,156,960			5,604,791

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,281,537			2,243,117
Deferred credits related to income taxes		88,961			90,083
Accumulated deferred investment tax credits		166,683			172,638
Employee benefit obligations		417,991			396,923
Asset retirement obligations		483,465			461,284
Other cost of removal obligations		667,655			634,792
Other regulatory liabilities, deferred		112,111			79,151
Other deferred credits and liabilities		35,654			45,857

Total deferred credits and other liabilities		4,254,057			4,123,845

Total Liabilities		11,380,016			10,996,568

Redeemable Preferred Stock		341,716			341,716

Preference Stock		343,412			343,412

Common Stockholder’s Equity:
Common stock, par value $40 per share —
Authorized - 40,000,000 shares
Outstanding - September 30, 2009: 28,850,000 shares
- December 31, 2008: 25,475,000 shares		1,154,000			1,019,000
Paid-in capital		2,112,359			2,091,462
Retained earnings		1,945,959			1,753,797
Accumulated other comprehensive loss		(7,180	)		(9,949	)

Total common stockholder’s equity		5,205,138			4,854,310

Total Liabilities and Stockholder’s Equity	$	17,270,282		$	16,536,006

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

ALABAMA POWER COMPANY

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

THIRD QUARTER 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Alabama Power’s primary business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, 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. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge Alabama Power for the foreseeable future.

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

RESULTS OF OPERATIONS

Net Income

Alabama Power’s financial performance remained stable in the third quarter 2009 despite the continued challenges of a recessionary economy. Alabama Power’s net income after dividends on preferred and preference stock for the third quarter 2009 was $261.7 million compared to $251.6 million for the corresponding period in 2008. The increase was primarily due to the corrective rate package providing for adjustments associated with customer charges to certain existing rate structures effective in January 2009, a decrease in other operations and maintenance expense, and an increase in allowance for equity funds used during construction (AFUDC). The increase was partially offset by an overall decline in base revenues attributable to a decline in KWH sales, resulting from a recessionary economy and unfavorable weather conditions.

Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2009 was $584.3 million compared to $534.6 million for the corresponding period in 2008. The increase was primarily due to a decrease in other operations and maintenance expense, an increase in AFUDC, and an overall increase in base revenues resulting from a corrective rate package that began in January 2009, offset by a decline in KWH sales resulting from a recessionary economy and unfavorable weather conditions.

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

Retail Revenues

In the third quarter 2009, retail revenues were $1.34 billion compared to $1.56 billion for the corresponding period in 2008. For year-to-date 2009, retail revenues were $3.52 billion compared to $3.74 billion for the corresponding period in 2008.

Details of the change to retail revenues are as follows:


	Third Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	1,559.0					$	3,741.1
Estimated change in —
Rates and pricing		36.7			2.4			127.1			3.4
Sales growth (decline)		(30.6	)		(2.0	)		(103.5	)		(2.8	)
Weather		(17.1	)		(1.1	)		(14.4	)		(0.4	)
Fuel and other cost recovery		(205.3	)		(13.2	)		(229.9	)		(6.1	)

Retail – current year	$	1,342.7			(13.9	)%	$	3,520.4			(5.9	)%

Revenues associated with changes in rates and pricing increased in the third quarter 2009 and year-to-date 2009 when compared to the corresponding periods in 2008 primarily due to the corrective rate package increase effective January 2009, which mainly provided for adjustments associated with customer charges to certain existing rate structures. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales declined in the third quarter 2009 when compared to the corresponding period in 2008 due to a recessionary economy. Industrial KWH energy sales decreased 11.9% due to a decline in demand across all industrial segments, most significantly in the chemical, forest products, and primary metal sectors. The weather-adjusted residential KWH energy sales decline was not material. Weather-adjusted commercial KWH energy sales decreased 3.2% due to a decline in customer demand resulting from a recessionary economy.

For year-to-date 2009, revenues attributable to changes in sales declined due to a recessionary economy when compared to the corresponding period in 2008. Industrial KWH energy sales decreased 19.2% due to a decline in demand across all industrial segments, most significantly in the chemical, forest products, and primary metal sectors. Weather-adjusted residential and commercial KWH energy sales decreased 1.5% and 2.3%, respectively, driven by a decline in customer demand.

Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2009 due to unfavorable weather conditions compared to the corresponding period in 2008.

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

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008 primarily due to decreases in fuel costs. 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 natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not impact net income.

Wholesale Revenues – Non-Affiliates

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

In the third quarter 2009, wholesale revenues from non-affiliates were $170.6 million compared to $196.4 million for the corresponding period in 2008. The decrease was due to a 9.1% reduction in the price of energy and a 4.4% decrease in KWH sales primarily caused by the recessionary economy.

For year-to-date 2009, wholesale revenues from non-affiliates were $483.2 million compared to $536.4 million for the corresponding period in 2008. The decrease was due to a 6.6% reduction in the price of energy and a 3.6% decrease in KWH sales primarily caused by the recessionary economy.

Wholesale Revenues – Affiliates

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

In the third quarter 2009, wholesale revenues from affiliates were $34.0 million compared to $60.6 million for the corresponding period in 2008. The decrease was due to a 60.4% decrease in fuel prices, partially offset by a 41.8% increase in KWH sales.

For year-to-date 2009, wholesale revenues from affiliates were $170.9 million compared to $240.7 million for the corresponding period in 2008. The decrease was due to a 41.0% decrease in fuel prices, partially offset by a 20.4% increase in KWH sales.

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

Other Revenues

In the third quarter 2009, the decrease in other revenues when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, other revenues were $124.0 million compared to $153.4 million for the corresponding period in 2008. The decrease was primarily due to a $39.6 million decrease in revenues from gas-fueled co-generation steam facilities resulting from lower gas prices and a decline in sales volume, partially offset by a $7.3 million increase in customer charges related to late fees.

Co-generation steam fuel revenues do not have a significant impact on earnings since they are generally offset by fuel expenses.

Fuel and Purchased Power Expenses


	Third Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Third Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	(145.3	)		(22.3	)	$	(191.1	)		(11.7	)
Purchased power – non-affiliates		(61.3	)		(58.8	)		(69.3	)		(45.0	)
Purchased power – affiliates		(47.7	)		(39.2	)		(114.0	)		(39.9	)

Total fuel and purchased power expenses	$	(254.3	)				$	(374.4	)

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

In the third quarter 2009, total fuel and purchased power expenses were $623.3 million compared to $877.6 million for the corresponding period in 2008. The decrease was primarily due to a $145.7 million decrease in the cost of energy primarily resulting from a decrease in the average cost of purchased power and natural gas and $108.6 million decrease related to total KWHs generated and purchased.

For year-to-date 2009, total fuel and purchased power expenses were $1.69 billion compared to $2.07 billion for the corresponding period in 2008. The decrease was primarily due to a $262.1 million decrease related to total KWHs generated and purchased and a $112.3 million decrease in the cost of energy primarily resulting from a decrease in the average cost of purchased power and natural gas.

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

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

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


	Third Quarter		Third Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2009		2008		Change			2009		2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		2.80		3.29		(14.9	)		2.83		2.88		(1.7	)
Purchased power		6.45		9.21		(30.0	)		6.23		7.95		(21.6	)

In the third quarter 2009, fuel expense was $506.4 million compared to $651.7 million for the corresponding period in 2008. The decrease was primarily due to a 40.8% and 8.2% decrease in the average cost of KWHs generated by natural gas and coal, respectively. Lower natural gas prices and an increase in hydro generation resulted in a decrease in the KWHs generated by coal and an increase in the KWHs generated by natural gas.

For year-to-date 2009, fuel expense was $1.44 billion compared to $1.63 billion for the corresponding period in 2008. The decrease was primarily related a 39.3% decrease in the average cost of KWHs generated by natural gas and a 10.1% increase the average cost of KWHs generated by coal. Lower natural gas prices and an increase in hydro generation resulted in a decrease in the KWHs generated by coal and an increase in the KWHs generated by natural gas.

Non-Affiliates

In the third quarter 2009, purchased power from non-affiliates was $42.9 million compared to $104.2 million for the corresponding period in 2008. The decrease was primarily related to a 58.0% volume decrease in the KWHs purchased primarily caused by reduced demand due to the recessionary economy.

For year-to-date 2009, purchased power from non-affiliates was $84.6 million compared to $153.9 million for the corresponding period in 2008. The decrease was related to a 26.7% decrease in KWHs purchased primarily caused by reduced demand due to the recessionary economy and a 25.0% decrease in price.

Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and availability of Southern Company system generation.

Affiliates

In the third quarter 2009, purchased power from affiliates was $74.0 million compared to $121.7 million for the corresponding period in 2008. The decrease was related to a 22.0% decrease in the amount of energy purchased and a 22.0% decrease in price.

For year-to-date 2009, purchased power from affiliates was $172.1 million compared to $286.1 million for the corresponding period in 2008. The decrease was related to a 28.6% decrease in the amount of energy purchased and a 15.8% decrease in price.

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

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

Other Operations and Maintenance Expenses

In the third quarter 2009, other operations and maintenance expenses were $272.1 million compared to $301.0 million for the corresponding period in 2008. The decrease was a result of a $7.0 million decrease in transmission and distribution expenses related to a reduction in overhead line clearing costs and labor, a $6.8 million decrease in nuclear expense related to a reduction in contract labor and material expenses, a $4.6 million decrease in steam power expense related to fewer scheduled outages, a $3.9 million decrease in administrative and general expenses related to a reduction in the injuries and damages reserve, partially offset by an increase in affiliated service company expenses, and a $2.1 million decrease in customer service expenses.

For year-to-date 2009, other operations and maintenance expenses were $827.3 million compared to $917.1 million for the corresponding period in 2008. The decrease was a result of a $46.4 million decrease in steam power expense related to reduction in contract labor and fewer scheduled outages, a $22.0 million decrease in transmission and distribution expenses related to a reduction in overhead line clearing and labor, and an $11.0 million decrease in administrative and general expenses related to reductions in the injuries and damages reserve, and post retirement medical expense, partially offset by an increase in pension expenses.

Depreciation and Amortization

In the third quarter 2009, the increase in depreciation and amortization when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, depreciation and amortization was $406.7 million compared to $387.7 million for the corresponding period in 2008. The increase was the result of an increase in property, plant, and equipment primarily related to environmental mandates and transmission and distribution projects.

On June 25, 2009, Alabama Power submitted an offer of settlement and stipulation to the FERC relating to the 2008 depreciation study that was filed in October 2008. The settlement offer withdraws the requests for authorization to use updated depreciation rates. In lieu of the new rates, Alabama Power will use those depreciation rates employed prior and up to January 1, 2009 that were previously approved by the FERC. On September 30, 2009, the FERC issued an order approving the settlement offer.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Depreciation and Amortization” of Alabama Power in Item 7 of the Form 10-K for additional information.

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

Taxes Other Than Income Taxes

In the third quarter 2009, the increase in taxes other than income taxes when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, taxes other than income taxes were $239.7 million compared to $227.6 million for the corresponding period in 2008. The increase was primarily due to increases in state and municipal public utility license tax bases.

Allowance for Equity Funds Used During Construction

In the third quarter 2009, AFUDC was $21.1 million compared to $11.7 million for the corresponding period in 2008. For year-to-date 2009, AFUDC was $56.9 million compared to $32.3 million for the corresponding period in 2008. These increases were primarily due to increases in the amount of construction work in progress at generating facilities related to environmental mandates.

Interest Expense, Net of Amounts Capitalized

In the third quarter 2009, the increase in interest expense, net of amounts capitalized when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, interest expense, net of amounts capitalized was $224.8 million compared to $209.8 million for the corresponding period in 2008. The increase was primarily due to the issuance of additional long-term debt, partially offset by additional capitalized interest. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” herein for additional information.

Income Taxes

In the third quarter 2009, income taxes were $154.1 million compared to $156.1 million for the corresponding period in 2008. The decrease was primarily due to the increase in non-taxable AFUDC and the manufacturer’s deduction, partially offset by higher pre-tax income and actualization of the 2008 income tax return.

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

For year-to-date 2009, income taxes were $344.4 million compared to $323.3 million for the corresponding period in 2008. The increase was primarily due to higher pre-tax income, partially offset by the increase in non-taxable AFUDC.

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 recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power’s service area. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial and commercial customers. The timing and extent of the economic recovery 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 Alabama Power in Item 7 of the Form 10-K.

Environmental Matters

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Carbon Dioxide Litigation – New York Case” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

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

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Carbon Dioxide Litigation – Kivalina Case” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Environmental Statutes and Regulations – Air Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Alabama Power’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Environmental Statutes and Regulations – Water Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, 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 information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA

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

published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.

In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Alabama Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Alabama PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail 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 over recovered fuel costs as of September 30, 2009 totaled $54.9 million as compared to under recovered fuel costs of $305.8 million at December 31, 2008. These over recovered fuel costs at September 30, 2009 are included in other regulatory liabilities, current on Alabama Power’s Condensed Balance Sheets herein. This classification is based on an

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

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 return of the over recovered fuel costs.

On June 2, 2009, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor from 3.983 cents per KWH to 3.733 cents per KWH for billings beginning June 9, 2009 through October 8, 2010, which will have no significant effect on Alabama Power’s revenues or net income, but will decrease annual cash flow. Thereafter, the Rate ECR factor will be 5.910 cents per KWH, absent a contrary order by the Alabama PSC. Rate ECR revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Alabama Power will be allowed to include a carrying charge associated with under recovered fuel costs in the fuel expense calculation. When the Rate ECR factor results in an over recovered position, Alabama Power will accrue interest on any such over recovered balance at the same rate used to derive the carrying cost.

Natural Disaster Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Cost Recovery” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery. At September 30, 2009, Alabama Power had accumulated a balance of $34.0 million in the target reserve for future storms, which is included in the Condensed Balance Sheets herein under “Other Regulatory Liabilities.”

Steam Service

On February 5, 2009, the Alabama PSC granted a Certificate of Abandonment of Steam Service in the downtown area of the City of Birmingham. The order allows Alabama Power to discontinue steam service by the earlier of three years from May 14, 2008 or when it has no remaining steam service customers. Currently, Alabama Power has contractual obligations to provide steam service until 2013. Impacts related to the abandonment of steam service are recognized in operating income and are not material to the earnings of Alabama Power.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Alabama Power. Alabama Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $75 million and $90 million. On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $65 million relates to Alabama Power, under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Alabama Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

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 opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury 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 emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Alabama Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Alabama Power’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Alabama Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. 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 Unbilled Revenues.

New Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Alabama Power is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Alabama Power’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Alabama Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. 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. Market rates for committed credit have increased, and Alabama Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees currently average less than ¹/4 of 1% per year for Alabama Power. Alabama Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Alabama Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Alabama Power’s investments in pension and nuclear decommissioning trust funds remained stable during the third quarter 2009. Alabama Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012. The projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Alabama Power does not expect any changes to the funding obligations to the nuclear decommissioning trust at this time.

Net cash provided from operating activities totaled $1.2 billion for the first nine months of 2009, compared to $935.4 million for the corresponding period in 2008. The $230.0 million increase in cash provided from operating activities was primarily due to an increase in net income, as previously discussed, and a decrease in receivables attributable to collections of under recovered regulatory clauses. Net cash used for investing activities totaled $868.5 million for the first nine months of 2009, compared to $1.1 billion for the corresponding period in 2008. The $197.5 million decrease was primarily due to a decline in gross property additions related to steam generation equipment and purchases of nuclear fuel, partially offset by increased construction of distribution facilities. Net cash provided from financing activities totaled $6.0 million for the first nine months of 2009, compared to $275.2 million for the corresponding period in 2008. The $269.2 million decrease was primarily due to fewer issuances of securities and a decrease of notes payable, partially offset by fewer redemptions of securities in the first nine months of 2009 as compared to the first nine months of 2008. Fluctuations in cash flow from financing activities vary from year-to-year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2009 include an increase of $302.9 million in cash and cash equivalents, an increase of $443.6 million in gross plant primarily due to increases in environmental mandates and transmission and distribution projects, and an increase of $382.3 million in construction work in progress. Long-term debt increased $552.2 million.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. There are no maturities of long-term debt required

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

through September 30, 2010. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants 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; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Recently, Alabama Power has primarily utilized funds from operating cash flows, unsecured debt, common stock, preferred stock, and preference stock. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Alabama Power in Item 7 of the Form 10-K for additional information.

Alabama Power’s current liabilities sometimes exceed current assets because of Alabama Power’s debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Alabama Power had at September 30, 2009 cash and cash equivalents of approximately $331 million, unused committed lines of credit of approximately $1.3 billion, and commercial paper programs. The credit facilities provide liquidity support to Alabama Power’s commercial paper borrowings and $582 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Of the unused credit facilities, $20 million will expire in 2009, $461 million will expire in 2010, $25 million will expire in 2011, and $765 million will expire in 2012. Of the facilities that expire in 2009 and 2010, $372 million allow for one-year term loans. Alabama Power expects to renew its credit facilities, as needed, prior to expiration. See Note 6 to the financial statements of Alabama Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and other Southern Company subsidiaries. At September 30, 2009, Alabama Power had no commercial paper outstanding and no outstanding borrowings under its committed lines of credit. 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 BBB- and/or Baa3 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $11 million. At September 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $318 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or

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

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 has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation, 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. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:


	Third Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(91.5	)	$	(91.9	)
Contracts realized or settled		41.6			105.5
Current period changes^(a)		2.9			(60.6	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(47.0	)	$	(47.0	)

(a)

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

The increases in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2009 were $44 million and $45 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At September 30, 2009, Alabama Power had a net hedge volume of 40 million mmBtu with a weighted average contract cost approximately $1.17 per mmBtu above market prices, compared to 49 million mmBtu at June 30, 2009 with a weighted average contract cost approximately $1.89 per mmBtu above market prices and compared to 45 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $2.12 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the fuel cost recovery clauses.

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

At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:


	September 30,			December 31,
Asset (Liability) Derivatives	2009			2008
	(in millions)
Regulatory hedges	$	(47.0	)	$	(91.9	)
Cash flow hedges		—			—
Not designated		—			—

Total fair value	$	(47.0	)	$	(91.9	)

Energy-related derivative contracts which are designated as regulatory hedges relate to Alabama Power’s fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, 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.

Unrealized pre-tax gains and losses recognized in income for the three months and nine months ended September 30, 2009 and 2008 for energy-related derivative contracts that are not hedges were not material.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:


	September 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(47.0	)		(40.3	)		(6.7	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(47.0	)	$	(40.3	)	$	(6.7	)	$	—

Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Alabama Power in Item 7 and Notes 1 and 6 to the financial statements of Alabama Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.

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

Financing Activities

In March 2009, Alabama Power issued $500 million of Series 2009A 6.00% Senior Notes due March 1, 2039. The proceeds were used to repay short-term indebtedness and for other general corporate purposes, including Alabama Power’s continuous construction program.

In June 2009, Alabama Power incurred obligations related to the issuance of $53 million of The Industrial Development Board of the City of Mobile Pollution Control Revenue Bonds (Alabama Power Barry Plant Project), First Series 2009. The proceeds were used to fund pollution control and environmental improvement facilities at Plant Barry.

In July 2009, Alabama Power issued 3,375,000 shares of common stock to Southern Company at $40 a share ($135 million aggregate purchase price). The proceeds were used for general corporate purposes.

In August 2009, Alabama Power’s $250 million Series BB Floating Rate Senior Notes due August 25, 2009 matured.

Subsequent to September 30, 2009, Alabama Power issued 1,687,500 shares of common stock to Southern Company at $40 a share ($67.5 million aggregate purchase price). The proceeds were used for general corporate purposes.

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.

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	2,093,503		$	2,317,817		$	5,368,123		$	5,723,577
Wholesale revenues, non-affiliates		108,521			148,933			301,077			443,901
Wholesale revenues, affiliates		53,687			106,659			98,520			252,733
Other revenues		71,477			70,836			199,623			200,043

Total operating revenues		2,327,188			2,644,245			5,967,343			6,620,254

Operating Expenses:
Fuel		830,283			859,778			2,083,662			2,181,000
Purchased power, non-affiliates		86,450			192,293			219,220			358,047
Purchased power, affiliates		158,864			247,845			528,505			748,622
Other operations and maintenance		358,821			379,314			1,102,876			1,139,910
Depreciation and amortization		122,740			162,325			464,931			472,137
Taxes other than income taxes		86,620			91,587			243,876			242,358

Total operating expenses		1,643,778			1,933,142			4,643,070			5,142,074

Operating Income		683,410			711,103			1,324,273			1,478,180
Other Income and (Expense):
Allowance for equity funds used during construction		23,200			20,887			66,267			72,625
Interest income		611			1,416			1,644			3,253
Interest expense, net of amounts capitalized		(95,309	)		(86,201	)		(293,124	)		(256,266	)
Other income (expense), net		(4,127	)		(3,671	)		(8,316	)		(5,593	)

Total other income and (expense)		(75,625	)		(67,569	)		(233,529	)		(185,981	)

Earnings Before Income Taxes		607,785			643,534			1,090,744			1,292,199
Income taxes		215,720			237,358			378,030			453,438

Net Income		392,065			406,176			712,714			838,761
Dividends on Preferred and Preference Stock		4,345			4,345			13,036			13,036

Net Income After Dividends on Preferred and Preference Stock	$	387,720		$	401,831		$	699,678		$	825,725

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	387,720		$	401,831		$	699,678		$	825,725
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(430), $(874), $(156), and $(890), respectively		(682	)		(1,386	)		(247	)		(1,410	)
Reclassification adjustment for amounts included in net income, net of tax of $2,350, $574, $6,520, and $1,269, respectively		3,725			911			10,336			2,012

Total other comprehensive income (loss)		3,043			(475	)		10,089			602

Comprehensive Income	$	390,763		$	401,356		$	709,767		$	826,327

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

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	712,714		$	838,761
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		566,741			561,986
Deferred income taxes and investment tax credits		111,035			97,752
Deferred revenues		(37,210	)		96,521
Deferred expenses		(39,570	)		(26,325	)
Allowance for equity funds used during construction		(66,267	)		(72,625	)
Pension, postretirement, and other employee benefits		16,713			35,067
Hedge settlements		(16,167	)		(20,486	)
Insurance cash surrender value		22,381			(73	)
Other, net		21,131			(14,926	)
Changes in certain current assets and liabilities —
-Receivables		3,648			(284,992	)
-Fossil fuel stock		(245,777	)		5,302
-Prepaid income taxes		(20,694	)		5,185
-Other current assets		505			(19,982	)
-Accounts payable		40,719			(51,661	)
-Accrued taxes		131,432			151,112
-Accrued compensation		(105,097	)		(18,839	)
-Other current liabilities		35,575			30,285

Net cash provided from operating activities		1,131,812			1,312,062

Investing Activities:
Property additions		(1,778,030	)		(1,419,885	)
Distribution of restricted cash from pollution control revenue bonds		22,077			22,197
Nuclear decommissioning trust fund purchases		(889,049	)		(362,565	)
Nuclear decommissioning trust fund sales		841,763			355,685
Nuclear decommissioning trust securities lending collateral		43,824			—
Cost of removal, net of salvage		(41,709	)		(29,798	)
Change in construction payables, net of joint owner portion		45,828			(22,264	)
Other investing activities		7,519			(30,543	)

Net cash used for investing activities		(1,747,777	)		(1,487,173	)

Financing Activities:
Increase (decrease) in notes payable, net		(103,634	)		172,789
Proceeds —
Capital contributions from parent company		923,840			259,750
Pollution control revenue bonds issuances		416,510			94,935
Senior notes issuances		500,000			500,000
Other long-term debt issuances		1,100			300,000
Redemptions —
Pollution control revenue bonds		(327,310	)		(118,555	)
Senior notes		(332,841	)		(122,427	)
Payment of preferred and preference stock dividends		(13,121	)		(12,668	)
Payment of common stock dividends		(554,175	)		(540,900	)
Other financing activities		(12,674	)		(9,357	)

Net cash provided from financing activities		497,695			523,567

Net Change in Cash and Cash Equivalents		(118,270	)		348,456
Cash and Cash Equivalents at Beginning of Period		132,739			15,392

Cash and Cash Equivalents at End of Period	$	14,469		$	363,848

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $28,443 and $30,112 capitalized for 2009 and 2008, respectively)	$	239,290		$	216,572
Income taxes (net of refunds)	$	115,436		$	228,792

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

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	14,469		$	132,739
Restricted cash and cash equivalents		4,729			22,381
Receivables —
Customer accounts receivable		618,710			554,219
Unbilled revenues		186,742			147,978
Under recovered regulatory clause revenues		352,978			338,780
Joint owner accounts receivable		64,690			43,858
Other accounts and notes receivable		56,068			54,041
Affiliated companies		9,103			13,091
Accumulated provision for uncollectible accounts		(13,927	)		(10,732	)
Fossil fuel stock, at average cost		730,535			484,757
Materials and supplies, at average cost		364,685			356,537
Vacation pay		65,898			71,217
Prepaid income taxes		130,682			65,987
Other regulatory assets, current		89,596			118,961
Other current assets		115,782			63,464

Total current assets		2,790,740			2,457,278

Property, Plant, and Equipment:
In service		25,024,035			23,975,262
Less accumulated provision for depreciation		9,426,743			9,101,474

Plant in service, net of depreciation		15,597,292			14,873,788
Nuclear fuel, at amortized cost		305,081			278,412
Construction work in progress		2,044,835			1,434,989

Total property, plant, and equipment		17,947,208			16,587,189

Other Property and Investments:
Equity investments in unconsolidated subsidiaries		64,809			57,163
Nuclear decommissioning trusts, at fair value		594,954			460,430
Miscellaneous property and investments		38,673			40,945

Total other property and investments		698,436			558,538

Deferred Charges and Other Assets:
Deferred charges related to income taxes		594,974			572,528
Deferred under recovered regulatory clause revenues		317,780			425,609
Other regulatory assets, deferred		1,285,487			1,449,352
Other deferred charges and assets		197,428			265,174

Total deferred charges and other assets		2,395,669			2,712,663

Total Assets	$	23,832,053		$	22,315,668

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

GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	253,668		$	280,443
Notes payable		253,461			357,095
Accounts payable —
Affiliated		208,455			260,545
Other		602,484			422,485
Customer deposits		197,539			186,919
Accrued taxes —
Accrued income taxes		148,100			70,916
Unrecognized tax benefits		157,512			128,712
Other accrued taxes		237,638			278,172
Accrued interest		106,454			79,432
Accrued vacation pay		49,248			57,643
Accrued compensation		38,450			135,191
Liabilities from risk management activities		59,287			113,432
Other cost of removal obligations, current		241,866			—
Other regulatory liabilities, current		94,688			60,330
Other current liabilities		127,518			75,846

Total current liabilities		2,776,368			2,507,161

Long-term Debt		7,284,759			7,006,275

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,317,030			3,064,580
Deferred credits related to income taxes		131,869			140,933
Accumulated deferred investment tax credits		245,927			256,218
Employee benefit obligations		898,669			882,965
Asset retirement obligations		716,370			688,019
Other cost of removal obligations		85,792			396,947
Other regulatory liabilities, deferred		42,997			115,865
Other deferred credits and liabilities		103,210			111,505

Total deferred credits and other liabilities		5,541,864			5,657,032

Total Liabilities		15,602,991			15,170,468

Preferred Stock		44,991			44,991

Preference Stock		220,966			220,966

Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - 9,261,500 shares		398,473			398,473
Paid-in capital		4,584,001			3,655,731
Retained earnings		3,003,292			2,857,789
Accumulated other comprehensive loss		(22,661	)		(32,750	)

Total common stockholder’s equity		7,963,105			6,879,243

Total Liabilities and Stockholder’s Equity	$	23,832,053		$	22,315,668

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

GEORGIA POWER COMPANY

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

THIRD QUARTER 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, 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, capital expenditures, and fuel prices. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge Georgia Power for the foreseeable future. Georgia Power is required to file a general rate case by July 1, 2010, which will determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. On August 27, 2009, the Georgia PSC approved an accounting order that will allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations over the 18-month period ending December 31, 2010 in lieu of filing a request for a base rate increase. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC and Georgia PSC Matters – Retail Rate Matters” herein for additional information.

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

RESULTS OF OPERATIONS

Net Income

Georgia Power’s third quarter 2009 net income after dividends on preferred and preference stock was $387.7 million compared to $401.8 million for the corresponding period in 2008. Georgia Power’s year-to-date 2009 net income after dividends on preferred and preference stock was $699.7 million compared to $825.7 million for the corresponding period in 2008. These decreases were primarily due to lower commercial and industrial base revenues resulting from the recessionary economy that were partially offset by cost containment activities and the amortization of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC. Also contributing to the year-to-date 2009 decrease was a charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees resigned from their positions effective March 31, 2009.

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

Retail Revenues

In the third quarter 2009, retail revenues were $2.09 billion compared to $2.32 billion for the corresponding period in 2008. For year-to-date 2009, retail revenues were $5.37 billion compared to $5.72 billion for the corresponding period in 2008.

Details of the change to retail revenues are as follows:


	Third Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	2,317.8					$	5,723.6
Estimated change in —
Rates and pricing		(43.7	)		(1.9	)		(64.2	)		(1.1	)
Sales growth (decline)		(24.9	)		(1.1	)		(87.2	)		(1.5	)
Weather		(17.0	)		(0.7	)		(12.5	)		(0.2	)
Fuel cost recovery		(138.7	)		(6.0	)		(191.6	)		(3.4	)

Retail – current year	$	2,093.5			(9.7	)%	$	5,368.1			(6.2	)%

Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008 due to decreased revenues from market-response rates to large commercial and industrial customers of $101.2 million and $204.6 million for the third quarter and year-to-date 2009, respectively, partially offset by increased recognition of environmental compliance cost recovery revenues of $57.5 million and $140.4 million for the third quarter and year-to-date 2009, respectively, in accordance with the 2007 Retail Rate Plan.

Revenues attributable to changes in sales declined in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008. These decreases were primarily due to the recessionary economy, partially offset by a 0.2% increase in retail customers. Weather-adjusted residential KWH sales increased 0.3%, weather-adjusted commercial KWH sales decreased 1.9%, and weather-adjusted industrial KWH sales decreased 7.9% for the third quarter 2009 when compared to the corresponding period in 2008. Weather-adjusted residential KWH sales increased 0.1%, weather-adjusted commercial KWH sales decreased 1.0%, and weather-adjusted industrial KWH sales decreased 12.2% year-to-date 2009 when compared to the corresponding period in 2008. Weather-adjusted industrial KWH sales decreased due to a broad decline in demand across all industrial segments, most significantly in the chemical, primary metals, textiles, and stone, clay, and glass sectors, for the third quarter and year-to-date 2009.

Revenues resulting from changes in weather decreased in the third quarter and for year-to-date 2009 as a result of unfavorable weather when compared to the corresponding periods in 2008.

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

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased by $138.7 million in the third quarter 2009 and by $191.6 million year-to-date 2009 when compared to the corresponding periods in 2008 due to decreased KWH sales and lower purchased power and natural gas prices, partially offset by higher coal prices. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not impact net income.

Wholesale Revenues – Non-Affiliates

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

In the third quarter 2009, wholesale revenues from non-affiliates were $108.5 million compared to $148.9 million for the corresponding period in 2008. The decrease was due to a 44.9% decrease in KWH sales due to lower demand.

For year-to-date 2009, wholesale revenues from non-affiliates were $301.1 million compared to $443.9 million for the corresponding period in 2008. The decrease was due to a 47.8% decrease in KWH sales due to lower demand.

Wholesale Revenues – Affiliates

In the third quarter 2009, wholesale revenues from affiliates were $53.7 million compared to $106.7 million for the corresponding period in 2008. The decrease was due to lower natural gas prices partially offset by a 29.7% increase in KWH sales.

For year-to-date 2009, wholesale revenues from affiliates were $98.5 million compared to $252.7 million for the corresponding period in 2008. The decrease was due to lower natural gas prices and a 29.9% decrease in KWH sales due to lower demand.

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

Fuel and Purchased Power Expenses


	Third Quarter 2009		Year-to-Date 2009
	vs.		vs.
	Third Quarter 2008		Year-to-Date 2008
	(change in millions)	(% change)	(change in millions)	(% change)
Fuel*	$(29.5)	(3.4)	$(97.4)	(4.5)
Purchased power – non-affiliates	(105.8)	(55.0)	(138.8)	(38.8)
Purchased power – affiliates	(88.9)	(35.9)	(220.1)	(29.4)

Total fuel and purchased power expenses	$(224.2)		$(456.3)

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

In the third quarter 2009, total fuel and purchased power expenses were $1.08 billion compared to $1.30 billion for the corresponding period in 2008. The decrease was due to a $130.1 million decrease related to fewer KWHs generated and purchased and a $94.1 million decrease in the average cost of purchased power, partially offset by an increase in the average cost of fuel.

For year-to-date 2009, total fuel and purchased power expenses were $2.83 billion compared to $3.29 billion for the corresponding period in 2008. The decrease was due to a $263.0 million decrease related to fewer KWHs generated and purchased and a $193.3 million decrease in the average cost of purchased power, partially offset by an increase in the average cost of fuel.

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


	Third Quarter		Third Quarter		Percent							Percent
Average Cost	2009		2008		Change			Year-to-Date 2009		Year-to-Date 2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		3.50		3.32		5.4			3.39		3.07		10.4
Purchased power		6.43		8.87		(27.5	)		6.14		8.39		(26.8	)

In the third quarter 2009, fuel expense was $830.3 million compared to $859.8 million for the corresponding period in 2008. The decrease was due to a decrease of 34.8% in natural gas prices and a decrease of 6.0% in KWHs generated as a result of lower KWH demand, partially offset by an increase of 15.1% in the average cost of coal per KWH generated.

For year-to-date 2009, fuel expense was $2.08 billion compared to $2.18 billion for the corresponding period in 2008. The decrease was due to a decrease of 40.6% in natural gas prices and a decrease of 13.7% in KWHs generated as a result of lower KWH demand, partially offset by an increase of 21.7% in the average cost of coal per KWH generated.

Fuel and purchased power 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 clause. See FUTURE EARNINGS POTENTIAL – “FERC and Georgia PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

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

Non-Affiliates

In the third quarter 2009, purchased power from non-affiliates was $86.5 million compared to $192.3 million for the corresponding period in 2008. The decrease was due to a 28.0% decrease in the average cost of KWH purchased and a 37.5% decrease in the volume of KWHs purchased.

For year-to-date 2009, purchased power from non-affiliates was $219.2 million compared to $358.0 million for the corresponding period in 2008. The decrease was due to a 35.6% decrease in the average cost of KWH purchased and a 4.9% decrease in the volume of KWHs purchased.

Affiliates

In the third quarter 2009, purchased power from affiliates was $158.9 million compared to $247.8 million for the corresponding period in 2008. The decrease was due to a 26.7% decrease in the average cost per KWH purchased and a 4.7% decrease in the volume of KWHs purchased.

For year-to-date 2009, purchased power from affiliates was $528.5 million compared to $748.6 million for the corresponding period in 2008. The decrease was due to a 23.7% decrease in the average cost of KWH purchased partially offset by a 1.6% increase in the volume of KWHs purchased.

Other Operations and Maintenance Expenses

In the third quarter 2009, other operations and maintenance expenses were $358.8 million compared to $379.3 million for the corresponding period in 2008. The decrease was due to a $9.1 million decrease in power generation, a $7.2 million decrease in transmission and distribution, and a decrease of $6.1 million in customer accounting, service, and sales costs, most of which are related to cost containment activities in an effort to offset the effects of the recessionary economy.

For year-to-date 2009, other operations and maintenance expenses were $1.10 billion compared to $1.14 billion for the corresponding period in 2008. The decrease was due to a $24.3 million decrease in power generation, a $25.5 million decrease in transmission and distribution, and a $20.6 million decrease in customer accounting, service, and sales costs primarily due to the cost containment activities described above, partially offset by a $5.7 million increase in uncollectible accounts, a $2.8 million increase in property insurance, and a $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees elected to resign their positions effective March 31, 2009. In the second and third quarters 2009, approximately two-thirds of the $29.4 million charge was offset by lower salary and employee benefits costs, and the other one-third will be offset during the remainder of the year. This charge is not expected to have a material impact on Georgia Power’s financial statements for the year ending December 31, 2009.

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

Depreciation and Amortization

In the third quarter 2009, depreciation and amortization was $122.7 million compared to $162.3 million for the corresponding period in 2008. For year-to-date 2009, depreciation and amortization was $464.9 million compared to $472.1 million for the corresponding period in 2008. These decreases were primarily due to the amortization of $54.0 million of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC, partially offset by increased depreciation due to additional plant in service related to transmission, distribution, and environmental projects.

Allowance for Equity Funds Used During Construction

In the third quarter 2009, the change in allowance for equity funds used during construction (AFUDC) when compared to the corresponding period in 2008 was not material.

For year-to-date 2009, AFUDC was $66.3 million compared to $72.6 million for the corresponding period in 2008. The decrease was due to a decrease in the average cost of construction work in progress balances for year-to-date 2009 compared to the corresponding period in 2008 as a result of projects completed in 2008.

Interest Expense, Net of Amounts Capitalized

In the third quarter 2009, interest expense, net of amounts capitalized was $95.3 million compared to $86.2 million for the corresponding period in 2008. For year-to-date 2009, interest expense, net of amounts capitalized was $293.1 million compared to $256.3 million for the corresponding period in 2008. These increases were primarily due to an increase in long-term debt levels resulting from the issuance of additional senior notes and pollution control bonds in the last 12 months to fund Georgia Power’s ongoing construction program, partially offset by lower average interest rates on existing variable rate debt.

Income Taxes

In the third quarter 2009, income taxes were $215.7 million compared to $237.4 million for the corresponding period in 2008. For year-to-date 2009, income taxes were $378.0 million compared to $453.4 million for the corresponding period in 2008. These decreases were primarily due to lower pre-tax net income.

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

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power’s future earnings potential. The level of Georgia Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include Georgia Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power’s service area. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial and commercial customers. The timing and extent of the economic recovery 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 Georgia Power in Item 7 of the Form 10-K.

Environmental Matters

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and cannot be determined at this time.

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

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Georgia Power’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Georgia Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.

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

energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Georgia Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Georgia PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail 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. In May 2008, the Georgia PSC approved an additional increase of approximately $222 million effective June 2008. On March 10, 2009, the Georgia PSC granted Georgia Power’s request to delay its fuel case filing until September 4, 2009 and, on August 27, 2009, the Georgia PSC approved an additional delay in the filing date to no later than December 15, 2009 (with new rates to be effective April 1, 2010). As of September 30, 2009, Georgia Power had a total under recovered fuel cost balance of approximately $671 million compared to $764 million at December 31, 2008.

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.

Retail Rate Matters

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

On July 21, 2009, the Georgia PSC accepted Georgia Power’s offer to bring a total of 178 MWs of the Block 5 and 6 capacity (which covers small portions of Plants Gaston, McManus, Mitchell, and Wilson) into retail rate base for the remaining life of the assets as existing wholesale contracts expire in 2011-2016. Similar treatment for approximately 78 MWs of Plant Scherer Unit 3 capacity for 2015-2031 was approved on September 15, 2009.

Construction

Nuclear

See Note (B) to the Condensed Financial Statements under “Construction Projects — Nuclear” herein for information regarding the potential expansion of Plant Vogtle.

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

On August 26, 2009, the NRC issued the Early Site Permit and Limited Work Authorization for Plant Vogtle Units 3 and 4. Excavation for the new units is in progress.

Other

On March 17, 2009, the Georgia PSC approved Georgia Power’s request to convert Plant Mitchell from coal-fueled to wood biomass-fueled at an in-service cost of approximately $103 million. The conversion is expected to be completed in 2012. The Georgia PSC also approved Georgia Power’s plan to install additional environmental controls at Plants Branch and Yates.

On August 10, 2009, Georgia Power filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. On September 30, 2009, Georgia Power amended the report. As amended, the report includes a request for an increase in the certified costs to construct Plant McDonough. The Georgia PSC will conduct hearings between December 2009 and February 2010 in review of the amended report and is scheduled to render its decision on March 16, 2010.

Nuclear Relicensing

Legislation

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

granted, of which $51 million relates to Georgia Power, under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Georgia Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Other Matters

Georgia Power is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury 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 emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Georgia Power’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

New Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Georgia Power is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Georgia Power’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Georgia Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper borrowings and variable rate pollution control revenue bonds. 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. Market rates for committed credit have increased, and Georgia Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees at Georgia Power currently average less than ³/₈ of 1% per year. Georgia Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Georgia Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Georgia Power’s investments in pension and nuclear decommissioning trust funds remained stable during the third quarter 2009. Georgia Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time. Georgia Power does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.

Net cash provided from operating activities totaled $1.1 billion for the first nine months of 2009, compared to $1.3 billion for the corresponding period in 2008. The $180.3 million decrease in cash provided from operating activities in the first nine months of 2009 was primarily due to the $126 million decrease in net income, a reduction in deferred environmental revenues of approximately $140 million, and an increase in fuel inventory additions of approximately $251 million, partially offset by reductions in accounts receivable. Net cash used for investing activities totaled $1.7 billion for the first nine months of 2009, compared to $1.5 billion for the corresponding period in 2008. The increase was primarily due to gross property additions to utility plant. Net cash provided from financing activities totaled $497.7 million for the first nine months of 2009, compared to $523.6 million for the corresponding period in 2008. The $25.9 million decrease was primarily due to higher redemptions of long-term debt, partially offset by higher capital contributions from Southern Company in 2009.

Significant balance sheet changes for the first nine months of 2009 include an increase of $1.4 billion in total property, plant, and equipment.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $254 million will be required through September 30, 2010 to fund maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency

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

of construction labor, equipment, and materials; 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

Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Recently, Georgia Power has primarily utilized funds 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.

Georgia Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at September 30, 2009 approximately $14.5 million of cash and cash equivalents and approximately $1.7 billion of unused credit arrangements with banks. 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. Of the unused credit arrangements in place at September 30, 2009, $595 million expire in 2010 and $1.1 billion expire in 2012. Georgia Power expects to renew its credit facilities, as needed, prior to expiration.

Credit arrangements provide liquidity support to Georgia Power’s purchase obligations related to variable rate pollution control revenue bonds and commercial paper borrowings. At September 30, 2009, Georgia Power had $901 million of variable rate pollution control revenue bonds outstanding. Georgia Power may meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At September 30, 2009, Georgia Power had approximately $253 million of commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $35 million. At September 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.2 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

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

On September 2, 2009, Moody’s affirmed the credit ratings of Georgia Power’s senior unsecured notes and commercial paper of A2/P-1, respectively, and revised the rating outlook to negative. On October 6, 2009, Standard and Poor’s affirmed the credit ratings of Georgia Power’s senior unsecured notes and its short-term credit rating of A/A-1, respectively, and maintained its stable rating outlook. On September 4, 2009, Fitch affirmed Georgia Power’s senior unsecured notes and commercial paper ratings of A+/F1, respectively, but revised Georgia Power’s rating outlook to negative.

Market Price Risk

Georgia Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 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, 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. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:


	Third Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(125.4	)	$	(113.2	)
Contracts realized or settled		56.5			130.6
Current period changes^(a)		3.0			(83.3	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(65.9	)	$	(65.9	)

(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 months and nine months ended September 30, 2009 were increases of $60 million and $47 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At September 30, 2009, Georgia Power had a net hedge volume of 68 million mmBtu with a weighted average contract cost approximately $0.96 per mmBtu above market prices, compared to 75 million mmBtu at June 30, 2009 with a weighted average contract cost approximately $1.69 per mmBtu above market prices and compared to 59 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $1.96 per mmBtu above market prices. The natural gas hedge settlements are recovered through the fuel cost recovery mechanism.

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

At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:


	September 30,			December 31,
Asset (Liability) Derivatives	2009			2008
	(in millions)
Regulatory hedges	$	(65.9	)	$	(113.2	)
Not designated		—			—

Total fair value	$	(65.9	)	$	(113.2	)

Energy-related derivative contracts which are designated as 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 the fuel cost recovery mechanism. 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.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:


	September 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(65.9	)		(52.4	)		(13.3	)		(0.2	)
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(65.9	)	$	(52.4	)	$	(13.3	)	$	(0.2	)

Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Georgia Power in Item 7 and Notes 1 and 6 to the financial statements of Georgia Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.

Financing Activities

In February 2009, Georgia Power issued $500 million of Series 2009A 5.95% Senior Notes due February 1, 2039. The proceeds were used to repay at maturity $150 million aggregate principal amount of Series U Floating Rate Senior Notes due February 7, 2009, to repay a portion of short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program. Georgia Power settled $100 million of hedges related to the Series 2009A issuance at a loss of approximately $16 million, and this loss will be amortized to interest expense, in earnings, together with a previously settled loss of approximately $2 million, over 10 years.

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

In July 2009, Georgia Power incurred obligations in connection with the issuance of $154.3 million of variable rate pollution control revenue bonds. The proceeds of the bonds were used to retire $154.3 million of fixed rate pollution control revenue bonds.

In August 2009, Georgia Power’s $125 million Series V 4.10% Senior Notes due August 15, 2009 matured.

In August 2009, Georgia Power redeemed its $55 million of Series D 5.50% Senior Insured Quarterly Notes due November 15, 2017.

In September 2009, Georgia Power incurred obligations in connection with the issuance of variable rate pollution control revenue bonds totaling $262.2 million. The proceeds of $89.2 million of the variable rate pollution control revenue bonds were used to fund the acquisition, construction, installation, and equipping costs of certain solid waste disposal facilities located at Plant Scherer. The proceeds from the remaining $173 million were used to retire Bartow County (Georgia Power Plant Bowen Project) First, Second and Third Series 2007 variable rate pollution control revenue bonds totaling $173 million.

Subsequent to September 30, 2009, Georgia Power entered into forward starting interest rate swaps to mitigate exposure to interest rate changes related to anticipated debt issuances. The total notional amount of the swaps is $200 million, and the swaps have been designated as a cash flow hedge.

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.

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	329,597		$	359,652		$	858,038		$	871,834
Wholesale revenues, non-affiliates		25,752			26,194			70,418			76,902
Wholesale revenues, affiliates		3,661			20,036			19,748			89,500
Other revenues		18,631			15,959			54,816			45,007

Total operating revenues		377,641			421,841			1,003,020			1,083,243

Operating Expenses:
Fuel		163,302			185,003			435,050			501,129
Purchased power, non-affiliates		9,991			14,057			20,480			23,269
Purchased power, affiliates		29,399			41,136			58,020			66,564
Other operations and maintenance		57,422			65,223			194,896			197,428
Depreciation and amortization		23,452			22,295			69,828			66,205
Taxes other than income taxes		26,683			25,088			72,120			66,587

Total operating expenses		310,249			352,802			850,394			921,182

Operating Income		67,392			69,039			152,626			162,061
Other Income and (Expense):
Allowance for equity funds used during construction		6,810			2,673			17,335			6,196
Interest income		129			914			423			2,332
Interest expense, net of amounts capitalized		(9,264	)		(10,491	)		(29,003	)		(32,165	)
Other income (expense), net		(266	)		(355	)		(1,369	)		(1,365	)

Total other income and (expense)		(2,591	)		(7,259	)		(12,614	)		(25,002	)

Earnings Before Income Taxes		64,801			61,780			140,012			137,059
Income taxes		22,042			22,886			45,341			48,542

Net Income		42,759			38,894			94,671			88,517
Dividends on Preference Stock		1,551			1,551			4,652			4,652

Net Income After Dividends on Preference Stock	$	41,208		$	37,343		$	90,019		$	83,865

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2009			2008		2009			2008
	(in thousands)					(in thousands)
Net Income After Dividends on Preference Stock	$	41,208		$	37,343	$	90,019		$	83,865
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(414), $-, $(414), and $(1,077), respectively		(659	)		—		(659	)		(1,715	)
Reclassification adjustment for amounts included in net income, net of tax of $105, $104, $314, and $261, respectively		166			167		500			416

Total other comprehensive income (loss)		(493	)		167		(159	)		(1,299	)

Comprehensive Income	$	40,715		$	37,510	$	89,860		$	82,566

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

GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	94,671		$	88,517
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		74,407			69,926
Deferred income taxes		(2,177	)		24,850
Allowance for equity funds used during construction		(17,335	)		(6,196	)
Pension, postretirement, and other employee benefits		1,123			1,413
Stock option expense		793			656
Tax benefit of stock options		8			200
Hedge settlements		—			(5,220	)
Other, net		(4,017	)		(4,116	)
Changes in certain current assets and liabilities —
-Receivables		40,388			(75,430	)
-Fossil fuel stock		(54,511	)		(26,408	)
-Materials and supplies		(1,411	)		7,135
-Prepaid income taxes		416			(3,929	)
-Property damage cost recovery		10,831			20,038
-Other current assets		2,178			2,371
-Accounts payable		(13,022	)		(2,154	)
-Accrued taxes		14,593			3,825
-Accrued compensation		(7,364	)		(3,063	)
-Other current liabilities		8,627			(2,057	)

Net cash provided from operating activities		148,198			90,358

Investing Activities:
Property additions		(330,776	)		(232,398	)
Investment in restricted cash from pollution control revenue bonds		(49,188	)		—
Distribution of restricted cash from pollution control revenue bonds		28,144			—
Cost of removal, net of salvage		(6,758	)		(5,246	)
Construction payables		(11,721	)		13,830
Other investing activities		(5,445	)		(3,956	)

Net cash used for investing activities		(375,744	)		(227,770	)

Financing Activities:
Increase (decrease) in notes payable, net		(101,589	)		57,813
Proceeds —
Common stock issued to parent		135,000			—
Capital contributions from parent company		3,461			75,304
Gross excess tax benefit of stock options		22			283
Pollution control revenue bonds		130,400			—
Senior notes		140,000			—
Other long-term debt issuances		—			110,000
Redemptions —
Senior notes		(1,033	)		(974	)
Payment of preference stock dividends		(4,652	)		(4,507	)
Payment of common stock dividends		(66,975	)		(61,275	)
Other financing activities		(1,635	)		(2,135	)

Net cash provided from financing activities		232,999			174,509

Net Change in Cash and Cash Equivalents		5,453			37,097
Cash and Cash Equivalents at Beginning of Period		3,443			5,348

Cash and Cash Equivalents at End of Period	$	8,896		$	42,445

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $6,909 and $2,470 capitalized for 2009 and 2008, respectively)	$	29,123		$	27,940
Income taxes (net of refunds)	$	43,423		$	37,353

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

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	8,896		$	3,443
Restricted cash and cash equivalents		21,043			—
Receivables —
Customer accounts receivable		91,613			69,531
Unbilled revenues		57,723			48,742
Under recovered regulatory clause revenues		31,878			98,644
Other accounts and notes receivable		3,897			7,201
Affiliated companies		1,724			8,516
Accumulated provision for uncollectible accounts		(1,896	)		(2,188	)
Fossil fuel stock, at average cost		160,704			108,129
Materials and supplies, at average cost		38,247			36,836
Other regulatory assets, current		22,841			38,908
Prepaid expenses		28,670			20,363
Other current assets		2,043			5,292

Total current assets		467,383			443,417

Property, Plant, and Equipment:
In service		2,890,230			2,785,561
Less accumulated provision for depreciation		1,005,256			971,464

Plant in service, net of depreciation		1,884,974			1,814,097
Construction work in progress		614,808			391,987

Total property, plant, and equipment		2,499,782			2,206,084

Other Property and Investments		15,902			15,918

Deferred Charges and Other Assets:
Deferred charges related to income taxes		35,225			24,220
Other regulatory assets, deferred		169,900			170,836
Other deferred charges and assets		24,698			18,550

Total deferred charges and other assets		229,823			213,606

Total Assets	$	3,212,890		$	2,879,025

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

GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	140,000		$	—
Notes payable		38,341			148,239
Accounts payable —
Affiliated		46,633			50,304
Other		72,379			90,381
Customer deposits		31,463			28,017
Accrued taxes —
Accrued income taxes		11,038			39,983
Other accrued taxes		22,869			11,855
Accrued interest		10,634			8,959
Accrued compensation		8,303			15,667
Other regulatory liabilities, current		19,076			4,602
Liabilities from risk management activities		13,531			26,928
Other current liabilities		20,781			29,047

Total current liabilities		435,048			453,982

Long-term Debt		978,982			849,265

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		296,385			254,354
Accumulated deferred investment tax credits		10,053			11,255
Employee benefit obligations		96,827			97,389
Other cost of removal obligations		189,077			180,325
Other regulatory liabilities, deferred		40,737			28,597
Other deferred credits and liabilities		83,523			83,768

Total deferred credits and other liabilities		716,602			655,688

Total Liabilities		2,130,632			1,958,935

Preference Stock		97,998			97,998

Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - September 30, 2009: 3,142,717 shares
- December 31, 2008: 1,792,717 shares		253,060			118,060
Paid-in capital		515,830			511,547
Retained earnings		220,461			197,417

Accumulated other comprehensive loss		(5,091	)		(4,932	)

Total common stockholder’s equity		984,260			822,092

Total Liabilities and Stockholder’s Equity	$	3,212,890		$	2,879,025

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

GULF POWER COMPANY

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

THIRD QUARTER 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge Gulf Power for the foreseeable future.

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

RESULTS OF OPERATIONS

Net Income

Gulf Power’s net income after dividends on preference stock for the third quarter 2009 was $41.2 million compared to $37.3 million for the corresponding period in 2008. The increase was primarily due to increased allowance for equity funds used during construction (AFUDC), which is non-taxable, decreased other operations and maintenance expenses, and decreased interest expense, net of amounts capitalized, partially offset by unfavorable weather and a decline in sales.

Gulf Power’s net income after dividends on preference stock for year-to-date 2009 was $90.0 million compared to $83.9 million for the corresponding period in 2008. The increase was primarily due to increased AFUDC, which is non-taxable, and decreased interest expense, net of amounts capitalized, partially offset by unfavorable weather and a decline in sales.

Retail Revenues

In the third quarter 2009, retail revenues were $329.6 million compared to $359.7 million for the corresponding period in 2008. For year-to-date 2009, retail revenues were $858.0 million compared to $871.8 million for the corresponding period in 2008.

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

Details of the change to retail revenues are as follows:


	Third Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	359.7					$	871.8
Estimated change in –
Rates and pricing		10.2			2.9			25.5			2.9
Sales growth (decline)		(0.6	)		(0.2	)		(4.1	)		(0.5	)
Weather		(6.0	)		(1.7	)		(8.9	)		(1.0	)
Fuel and other cost recovery		(33.7	)		(9.4	)		(26.3	)		(3.0	)

Retail – current year	$	329.6			(8.4	)%	$	858.0			(1.6	)%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008 primarily due to increased revenue associated with higher projected environmental compliance costs in 2009. Annually, Gulf Power petitions the Florida PSC for recovery of projected costs including any true-up amount from prior periods, and approved rates are implemented each January. These recovery provisions include related expenses and a return on average net investment. See Note 1 to the financial statements of Gulf Power under “Revenues” and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Environmental Remediation” and “Retail Regulatory Matters – Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales declined in the third quarter 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential customers increased 3.3% despite a reduction in the number of customers, primarily due to an increase in per customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 1.4% primarily due to decreased per customer usage and a decrease in the number of customers driven by the recession. KWH energy sales to industrial customers decreased 29.3% as a result of recessionary economic conditions and increased customer co-generation due to the lower cost of natural gas.

Revenues attributable to changes in sales declined year-to-date 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential customers increased 1.5% despite a decrease in the number of customers, primarily due to an increase in per customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 1.1% primarily due to a decrease in per customer usage and a decrease in the number of customers driven by the recession. KWH energy sales to industrial customers decreased 24.2% as a result of recessionary economic conditions and increased customer co-generation due to the lower cost of natural gas.

Revenues attributable to changes in weather decreased in the third quarter and year-to-date 2009 as a result of unfavorable weather when compared to the corresponding periods in 2008.

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008 due to overall decreased customer usage primarily resulting from decreased industrial usage. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and revenues related to the recovery of storm damage restoration costs. Annually, Gulf Power petitions the Florida PSC for recovery of projected fuel and purchased power costs including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material impact on net income. See FUTURE EARNINGS POTENTIAL – “FERC and Florida PSC Matters – Retail Regulatory Matters” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC

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

Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and “Property Damage Reserve” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Storm Damage Cost Recovery” and “Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

Wholesale revenues from non-affiliates will vary depending on the market cost of available energy compared to the cost of Gulf Power and Southern Company system-owned generation, demand for energy within the Southern Company service territory, and availability of Southern Company system generation. Wholesale revenues from non-affiliates are predominantly unit power sales under long-term contracts to other Florida utilities. Revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost.

In the third quarter 2009, wholesale revenues from non-affiliates were $25.8 million compared to $26.2 million for the corresponding period in 2008. The decrease was primarily due to lower energy revenues related to a 7.7% decrease in KWH sales resulting from reduced customer demand primarily caused by the recessionary economy.

For year-to-date 2009, wholesale revenues from non-affiliates were $70.4 million compared to $76.9 million for the corresponding period in 2008. The decrease was primarily due to lower energy revenues related to a 17.1% decrease in KWH sales resulting from reduced customer demand primarily caused by the recessionary economy.

Wholesale Revenues – Affiliates

In the third quarter 2009, wholesale revenues from affiliates were $3.6 million compared to $20.0 million for the corresponding period in 2008. The decrease was due to reduced customer demand resulting in a 63.0% decrease in KWH sales and a 50.6% decrease in price related to lower Power Pool interchange energy rates.

For year-to-date 2009, wholesale revenues from affiliates were $19.7 million compared to $89.5 million for the corresponding period in 2008. The decrease was due to reduced customer demand resulting in a 66.3% decrease in KWH sales and a 34.6% decrease in price related to lower Power Pool interchange energy rates.

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

Other Revenues

In the third quarter 2009, other revenues were $18.6 million compared to $15.9 million for the corresponding period in 2008. For year-to-date 2009, other revenues were $54.8 million compared to $45.0 million for the corresponding period in 2008. These increases were primarily due to other energy services and higher franchise fees. The increased revenues from other energy services did not have a material impact on net income since they were generally offset by associated expenses. Franchise fees have no impact on net income.

Fuel and Purchased Power Expenses


	Third Quarter 2009		Year-to-Date 2009
	vs.		vs.
	Third Quarter 2008		Year-to-Date 2008
	(change in millions)	(% change)	(change in millions)	(% change)
Fuel*	$(21.7)	(11.7)	$(66.1)	(13.2)
Purchased power – non-affiliates	(4.1)	(28.9)	(2.8)	(12.0)
Purchased power – affiliates	(11.7)	(28.5)	(8.5)	(12.8)

Total fuel and purchased power expenses	$(37.5)		$(77.4)

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

In the third quarter 2009, total fuel and purchased power expenses were $202.6 million compared to $240.1 million for the corresponding period in 2008. The net decrease in fuel and purchased power expenses was primarily due to a $24.9 million decrease in the cost of energy primarily resulting from a decrease in the average cost of natural gas and a $12.6 million decrease related to total KWHs generated and purchased.

For year-to-date 2009, total fuel and purchased power expenses were $513.5 million compared to $590.9 million for the corresponding period in 2008. The net decrease in fuel and purchased power expenses was primarily due to a $50.4 million decrease related to total KWHs generated and purchased and a $27.0 million decrease in the cost of energy primarily resulting from a decrease in the average cost of natural gas.

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

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


	Third Quarter		Third Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2009		2008		Change			2009		2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		4.59		4.54		1.1			4.46		4.20		6.2
Purchased power		7.98		13.09		(39.0	)		6.78		11.07		(38.8	)

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

In the third quarter 2009, fuel expense was $163.3 million compared to $185.0 million for the corresponding period in 2008. The decrease was due to a decrease of 42.3% in the average cost of natural gas prices and a decrease of 13.9% in KWHs generated as a result of lower demand, partially offset by an increase of 17.5% in the average cost of coal per KWH generated.

For year-to-date 2009, fuel expense was $435.0 million compared to $501.1 million for the corresponding period in 2008. The decrease was due to a decrease of 39.7% in the average cost of natural gas prices and a decrease of 19.0% in KWHs generated as a result of lower demand, partially offset by an increase of 22.5% in the average cost of coal per KWH generated.

Non-Affiliates

In the third quarter 2009, purchased power from non-affiliates was $9.9 million compared to $14.0 million for the corresponding period in 2008. The decrease was primarily related to a 51.8% decrease in the volume of KWHs purchased, partially offset by a 77.7% increase in average cost per KWH purchased.

For year-to-date 2009, purchased power from non-affiliates was $20.5 million compared to $23.3 million for the corresponding period in 2008. The decrease was primarily related to an 11.2% decrease in the volume of KWHs purchased, partially offset by a 15.3% increase in average cost per KWH purchased.

Energy purchases from non-affiliates will vary depending on the market cost of available energy being lower than the cost of Southern Company system-generated energy, demand for energy within the Southern Company system service territory, and the availability of Southern Company system generation.

Affiliates

In the third quarter 2009, purchased power from affiliates was $29.4 million compared to $41.1 million for the corresponding period in 2008. The decrease was primarily related to a 56.8% decrease in average cost per KWH purchased, partially offset by a 66.5% increase in the volume of KWHs purchased from lower-priced Power Pool resources.

For year-to-date 2009, purchased power from affiliates was $58.0 million compared to $66.5 million for the corresponding period in 2008. The decrease was primarily related to a 52.8% decrease in average cost per KWH purchased, partially offset by an 85.5% increase in the volume of KWHs purchased from lower-priced Power Pool resources.

Other Operations and Maintenance Expenses

In the third quarter 2009, other operations and maintenance expenses were $57.4 million compared to $65.2 million for the corresponding period in 2008. The decrease was primarily due to an $8.0 million decrease in storm recovery costs and a $1.9 million decrease in maintenance at generation facilities, partially offset by $1.9 million in increased expense from other energy services. The decreased storm recovery costs and the increased

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

expense from other energy services did not have a material impact on earnings since they were offset by associated revenues.

For year-to-date 2009, other operations and maintenance expenses were $194.9 million compared to $197.4 million for the corresponding period in 2008. The decrease was primarily due to a $9.7 million decrease in storm recovery costs, partially offset by a $7.4 million increase in other energy services. The decreased storm recovery costs and the increased expense from other energy services did not have a material impact on earnings since they were offset by associated revenues.

Depreciation and Amortization

In the third quarter 2009, depreciation and amortization was $23.5 million compared to $22.3 million for the corresponding period in 2008. For year-to-date 2009, depreciation and amortization was $69.8 million compared to $66.2 million for the corresponding period in 2008. These increases were primarily due to net additions to generation and distribution facilities.

Taxes Other Than Income Taxes

In the third quarter 2009, taxes other than income taxes were $26.7 million compared to $25.1 million for the corresponding period in 2008. For year-to-date 2009, taxes other than income taxes were $72.1 million compared to $66.6 million for the corresponding period in 2008. These increases were primarily due to increases in franchise fees and gross receipt taxes, which have no impact on net income.

Allowance for Equity Funds Used During Construction

In the third quarter 2009, AFUDC was $6.8 million compared to $2.7 million for the corresponding period in 2008. For year-to-date 2009, AFUDC was $17.3 million compared to $6.2 million for the corresponding period in 2008. These increases were primarily due to the construction of environmental control projects.

Interest Income

In the third quarter 2009, interest income was $0.1 million compared to $0.9 million for the corresponding period in 2008. For year-to-date 2009, interest income was $0.4 million compared to $2.3 million for the corresponding period in 2008. These decreases were primarily due to decreases in interest received related to the recovery of financing costs associated with the fuel clause.

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

Interest Expense, Net of Amounts Capitalized

In the third quarter 2009, interest expense, net of amounts capitalized was $9.3 million compared to $10.5 million for the corresponding period in 2008. For year-to-date 2009, interest expense, net of amounts capitalized was $29.0 million compared to $32.2 million for the corresponding period in 2008. These decreases were primarily the result of an increase in capitalization of AFUDC related to the construction of environmental control projects.

Income Taxes

In the third quarter 2009, income taxes were $22.1 million compared to $22.9 million for the corresponding period in 2008. The decrease was primarily due to an increase in the tax benefit associated with an increase in AFUDC, which is non-taxable.

For year-to-date 2009, income taxes were $45.3 million compared to $48.5 million for the corresponding period in 2008. The decrease was primarily due to an increase in the tax benefit associated with an increase in AFUDC, which is non-taxable, and state tax credits, partially offset by higher pre-tax income.

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 recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power’s service area. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial and commercial customers. The timing and extent of the economic recovery 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 Gulf Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Gulf Power’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

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

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 information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.

In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Gulf Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Florida PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding

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

initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In recent years, Gulf Power has experienced higher than expected fuel costs for coal and natural gas. If the projected fuel cost over or under recovery balance at year-end exceeds 10% of the projected fuel revenue applicable for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.

Under recovered fuel costs at September 30, 2009 totaled $26.1 million, compared to $96.7 million at December 31, 2008. This amount is included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor would have no significant effect on Gulf Power’s revenues or net income, but would affect cash flow.

On November 4, 2009, the Florida PSC approved Gulf Power’s annual rate clause requests for its purchased power capacity, conservation, and environmental compliance cost recovery factors for 2010. A decision from the Florida PSC on Gulf Power’s annual rate clause request for its 2010 fuel cost recovery factor is expected in December 2009. The net effect of the approved and proposed changes to Gulf Power’s cost recovery factors for 2010 is a 3.9% rate increase for residential customers using 1,000 KWHs per month. The ultimate outcome of this matter cannot now be determined.

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

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Gulf Power. Gulf Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $13 million and $16 million. On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $15.5 million relates to Gulf Power, under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Gulf Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Other Matters

On March 16, 2009, Gulf Power entered into a PPA (the Agreement) with Shell Energy North America (US), L.P. (Shell). Under the terms of the Agreement, Gulf Power will be entitled to all of the capacity and energy from an approximately 885 MW combined cycle power plant (the Plant) located in Autauga County, Alabama that is owned and operated by Tenaska Alabama II Partners, L.P. (Tenaska). Shell is entitled to all of the capacity and energy from the Plant under a 20-year Energy Conversion Agreement between Shell and Tenaska that expires on May 24, 2023. On July 14, 2009, the Florida PSC approved the Agreement. On October 17, 2009, the Florida PSC’s approval became a final, non-appealable order. The Agreement became effective on November 1, 2009. Unless earlier terminated in accordance with its terms, the Agreement will

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

terminate on May 24, 2023. Payments under the Agreement will be material. However, these costs have been approved by the Florida PSC for recovery through Gulf Power’s fuel clause and purchased power capacity clause; therefore, no material impact is expected on Gulf Power’s net income.

Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury 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 emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Gulf Power’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

New Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Gulf Power is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Gulf Power’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Gulf Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper borrowings and variable rate pollution control revenue bonds. 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. Market rates for committed credit have increased, and Gulf Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees at Gulf Power currently average less than ³/4 of 1% per year. Gulf Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Gulf Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Gulf Power’s investments in pension trust funds remained stable during the third quarter 2009. Gulf Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time.

Net cash provided from operating activities totaled $148.2 million for the first nine months of 2009, compared to $90.4 million for the corresponding period in 2008. The $57.8 million increase in cash provided from operating activities was primarily due to a $118.8 million increase in cash from under recovered regulatory clause revenues related to fuel, partially offset by a $28.1 million increase in cash payments for fossil fuel inventory and a $27.0 million decrease in deferred income taxes. Net cash used for investing activities totaled $375.7 million for the first nine months of 2009, compared to $227.8 million for the corresponding period in 2008. The $147.9 million increase was primarily due to gross property additions to utility plant. These additions were primarily related to installation of equipment to comply with environmental requirements. Net cash provided from financing activities totaled $233.0 million for the first nine months of 2009, compared to $174.5 million for the corresponding period in 2008. The $58.5 million increase in cash provided from financing activities was primarily due to the issuances of $140.0 million of senior notes, $135.0 million of common stock to Southern Company, and $130.4 million of pollution control revenue bonds in 2009, partially offset by an issuance of $110.0 million of long-term debt in 2008, a $71.8 million decrease of capital contributions from Southern Company, and a $159.4 million increase in cash payments related to notes payable.

Significant balance sheet changes for the first nine months of 2009 include a net increase of $293.7 million in property, plant, and equipment, primarily related to environmental control projects; the issuance of $140.0 million in senior notes; the issuance of common stock to Southern Company for $135.0 million; the issuance of $130.4 million of pollution control revenue bonds, with a related restricted cash balance of $21.0 million; an increase in fossil fuel stock of $52.6 million; an increase in customer accounts receivable and unbilled revenues of $31.1 million; and a $66.8 million decrease in under recovered regulatory clause revenues primarily related to fuel.

GULF 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 Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power’s capital requirements for its construction program, maturities of long-term debt, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $140 million will be required through September 30, 2010 to fund maturities of debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; 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 utilized in the past. Recently, Gulf Power has utilized funds from operating cash flows, short-term debt, security offerings, a long-term bank note, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Gulf Power in Item 7 of the Form 10-K for additional information.

Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power had at September 30, 2009 approximately $8.9 million of cash and cash equivalents and $220 million of unused committed lines of credit with banks. Of these credit agreements, $60 million expire in 2009, $160 million expire in 2010, and $70 million of these facilities contain provisions allowing one-year term loans executable at expiration. Subsequent to September 30, 2009, Gulf Power renewed $40 million of its credit facilities that were set to expire in 2009 and extended the maturity dates to 2010. Gulf Power expects to renew its credit facilities, as needed, prior to expiration. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. These credit arrangements provide liquidity support to Gulf Power’s commercial paper borrowings and $69 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Gulf Power may meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At September 30, 2009, Gulf Power had $36.9 million of commercial paper outstanding. 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, emissions allowances, and energy price risk management. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $58 million. At September 30, 2009,

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

the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $384 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power’s ability to access capital markets, particularly the short-term debt market.

On September 2, 2009, Moody’s affirmed the credit ratings of Gulf Power’s senior unsecured notes and commercial paper of A2/P-1, respectively, and revised the rating outlook to negative. On October 6, 2009, Standard and Poor’s affirmed the credit ratings of Gulf Power’s senior unsecured notes and its short-term credit rating of A/A-1, respectively, and maintained its stable rating outlook. On September 4, 2009, Fitch affirmed Gulf Power’s senior unsecured notes and commercial paper ratings of A+/F1, respectively, and maintained a stable rating outlook for Gulf Power.

Market Price Risk

Gulf Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 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, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Gulf Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Gulf Power continues to manage a fuel-hedging program implemented per the guidelines of the Florida PSC. As such, Gulf Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:


	Third Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(28.2	)	$	(31.2	)
Contracts realized or settled		12.5			35.6
Current period changes^(a)		0.6			(19.5	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(15.1	)	$	(15.1	)

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

The increases in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2009 were $13 million and $16 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At September 30, 2009, Gulf Power had a net hedge volume of 12 million mmBtu with a weighted average contract cost approximately $1.23 per mmBtu above market prices, compared to 15 million mmBtu at June 30, 2009 with a weighted average contract cost approximately $1.95 per mmBtu above market prices and compared to 14 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $2.24 per mmBtu above market prices. Natural gas hedge settlements are recovered through the fuel cost recovery clause.

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

At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:


	September 30,			December 31,
Asset (Liability) Derivatives	2009			2008
	(in millions)
Regulatory hedges	$	(15.1	)	$	(31.2	)
Not designated		—			—

Total fair value	$	(15.1	)	$	(31.2	)

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

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:


				September 30, 2009
				Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
				(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(15.1	)		(12.0	)		(3.2	)		0.1
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(15.1	)	$	(12.0	)	$	(3.2	)	$	0.1

Gulf Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Gulf Power in Item 7 and Notes 1 and 6 to the financial statements of Gulf Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.

Financing Activities

On January 22, 2009, Gulf Power issued to Southern Company 1,350,000 shares of Gulf Power common stock, without par value, and realized proceeds of $135 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.

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

In March 2009, Gulf Power incurred obligations related to the issuance of $130.4 million of pollution control revenue bonds. The proceeds are being used for the acquisition, construction, installation, and equipping of certain solid waste disposal facilities located at Plant Crist.

In June 2009, Gulf Power issued $140 million of Series 2009A Floating Rate Senior Notes due June 28, 2010. The proceeds were used to repay a portion of short-term indebtedness and for other general corporate purposes, including Gulf Power’s continuous construction program.

Subsequent to September 30, 2009, Gulf Power entered into another forward starting interest rate swap to mitigate exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swap is $50 million, and the swap has been designated as a cash flow hedge.

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

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	231,894		$	241,788		$	608,761		$	597,298
Wholesale revenues, non-affiliates		81,242			106,595			235,089			274,996
Wholesale revenues, affiliates		13,404			28,908			30,785			79,833
Other revenues		4,140			4,124			11,449			12,636

Total operating revenues		330,680			381,415			886,084			964,763

Operating Expenses:
Fuel		148,115			174,300			393,912			443,273
Purchased power, non-affiliates		1,666			13,777			7,374			21,458
Purchased power, affiliates		21,946			35,421			65,346			78,903
Other operations and maintenance		61,138			64,828			182,500			192,969
Depreciation and amortization		17,707			17,229			53,382			52,327
Taxes other than income taxes		17,033			17,142			48,178			48,993

Total operating expenses		267,605			322,697			750,692			837,923

Operating Income		63,075			58,718			135,392			126,840
Other Income and (Expense):
Interest income		34			403			829			996
Interest expense, net of amounts capitalized		(6,075	)		(4,504	)		(17,091	)		(13,336	)
Other income (expense), net		474			1,507			3,239			6,025

Total other income and (expense)		(5,567	)		(2,594	)		(13,023	)		(6,315	)

Earnings Before Income Taxes		57,508			56,124			122,369			120,525
Income taxes		22,177			19,474			46,268			42,832

Net Income		35,331			36,650			76,101			77,693
Dividends on Preferred Stock		433			433			1,299			1,299

Net Income After Dividends on Preferred Stock	$	34,898		$	36,217		$	74,802		$	76,394

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2009			2008		2009		2008
	(in thousands)					(in thousands)
Net Income After Dividends on Preferred Stock	$	34,898		$	36,217	$	74,802	$	76,394
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(27), $1,285, $-, and $(169), respectively		(44	)		2,075		—		(272	)

Comprehensive Income	$	34,854		$	38,292	$	74,802	$	76,122

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

102

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	76,101		$	77,693
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		58,929			56,026
Deferred income taxes and investment tax credits, net		(27,430	)		5,112
Pension, postretirement, and other employee benefits		5,817			6,088
Stock option expense		822			639
Tax benefit of stock options		17			473
Generation construction screening expense		(21,955	)		(12,278	)
Other, net		214			(15,111	)
Changes in certain current assets and liabilities —
-Receivables		48,512			(36,440	)
-Fossil fuel stock		(42,838	)		(26,810	)
-Materials and supplies		(1,782	)		(2,961	)
-Prepaid income taxes		1,061			1,187
-Other current assets		(9,783	)		4,098
-Other accounts payable		(26,354	)		10,195
-Accrued taxes		13,430			(6,998	)
-Accrued compensation		(10,238	)		(8,066	)
-Other current liabilities		20,694			17,355

Net cash provided from operating activities		85,217			70,202

Investing Activities:
Property additions		(72,661	)		(100,490	)
Cost of removal, net of salvage		(9,911	)		(3,497	)
Construction payables		(3,949	)		(5,201	)
Hurricane Katrina capital grant proceeds		—			7,314
Other investing activities		(2,150	)		2,422

Net cash used for investing activities		(88,671	)		(99,452	)

Financing Activities:
Increase (decrease) in notes payable, net		(24,891	)		44,608
Proceeds —
Capital contributions from parent company		3,330			4,222
Gross excess tax benefit of stock options		67			892
Senior notes issuances		125,000			—
Other long-term debt issuances		—			80,000
Redemptions —
Pollution control revenue bonds		—			(7,900	)
Senior notes		(40,000	)		—
Payment of preferred stock dividends		(1,299	)		(1,299	)
Payment of common stock dividends		(51,375	)		(51,300	)
Other financing activities		(1,781	)		(1,475	)

Net cash provided from financing activities		9,051			67,748

Net Change in Cash and Cash Equivalents		5,597			38,498
Cash and Cash Equivalents at Beginning of Period		22,413			4,827

Cash and Cash Equivalents at End of Period	$	28,010		$	43,325

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $117 and $113 capitalized for 2009 and 2008, respectively)	$	15,824		$	12,054
Income taxes (net of refunds)	$	48,008		$	38,710

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

103

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	28,010		$	22,413
Receivables —
Customer accounts receivable		51,841			40,262
Unbilled revenues		28,294			24,798
Under recovered regulatory clause revenues		—			54,994
Other accounts and notes receivable		7,097			8,995
Affiliated companies		17,414			24,108
Accumulated provision for uncollectible accounts		(1,338	)		(1,039	)
Fossil fuel stock, at average cost		128,375			85,538
Materials and supplies, at average cost		28,925			27,143
Other regulatory assets, current		55,366			59,220
Prepaid income taxes		18,773			1,061
Other current assets		17,241			9,837

Total current assets		379,998			357,330

Property, Plant, and Equipment:
In service		2,302,812			2,234,573
Less accumulated provision for depreciation		936,324			923,269

Plant in service, net of depreciation		1,366,488			1,311,304
Construction work in progress		43,162			70,665

Total property, plant, and equipment		1,409,650			1,381,969

Other Property and Investments		7,321			8,280

Deferred Charges and Other Assets:
Deferred charges related to income taxes		8,860			9,566
Other regulatory assets, deferred		184,897			171,680
Other deferred charges and assets		25,842			23,870

Total deferred charges and other assets		219,599			205,116

Total Assets	$	2,016,568		$	1,952,695

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

104

MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)


	At September 30,		At December 31,
Liabilities and Stockholder’s Equity	2009		2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,304	$	41,230
Notes payable		1,403		26,293
Accounts payable —
Affiliated		28,581		36,847
Other		41,667		63,704
Customer deposits		10,790		10,354
Accrued taxes —
Accrued income taxes		24,120		8,842
Other accrued taxes		40,647		50,700
Accrued interest		4,264		3,930
Accrued compensation		10,365		20,604
Other regulatory liabilities, current		9,783		9,718
Over recovered regulatory clause liabilities		20,466		—
Liabilities from risk management activities		22,179		29,291
Other current liabilities		17,715		19,144

Total current liabilities		233,284		320,657

Long-term Debt		493,779		370,460

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		222,702		222,324
Deferred credits related to income taxes		11,862		14,074
Accumulated deferred investment tax credits		13,121		14,014
Employee benefit obligations		145,598		142,188
Other cost of removal obligations		97,208		96,191
Other regulatory liabilities, deferred		55,688		51,340
Other deferred credits and liabilities		46,434		52,216

Total deferred credits and other liabilities		592,613		592,347

Total Liabilities		1,319,676		1,283,464

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		324,193		319,958
Retained earnings		302,228		278,802
Accumulated other comprehensive income (loss)		—		—

Total common stockholder’s equity		664,112		636,451

Total Liabilities and Stockholder’s Equity	$	2,016,568	$	1,952,695

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

105

MISSISSIPPI POWER COMPANY

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

THIRD QUARTER 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008

OVERVIEW

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

Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power’s long-term financial success is dependent upon how well it satisfies its customers’ needs, Mississippi Power’s retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power’s allowed return. In addition to the PEP performance indicators, Mississippi Power focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Mississippi Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Mississippi Power’s net income after dividends on preferred stock for the third quarter 2009 was $34.9 million compared to $36.2 million for the corresponding period in 2008. The decrease in net income after dividends on preferred stock for the third quarter 2009 was primarily due to decreases in wholesale energy revenues and total other income and (expense) and an increase in income tax expense. The decrease was partially offset by an increase in retail base revenues primarily resulting from increased sales in the industrial class, an increase in territorial wholesale base revenues due to a wholesale base rate increase and increased demand, as well as a decrease in other operations and maintenance expenses.

Mississippi Power’s net income after dividends on preferred stock for year-to-date 2009 was $74.8 million compared to $76.4 million for the corresponding period in 2008. The decrease in net income after dividends on preferred stock for year-to-date 2009 was primarily due to decreases in wholesale energy revenues and total other income and (expense) and an increase in income tax expense. The decrease was partially offset by an increase in territorial wholesale base revenues primarily resulting from an increase in territorial wholesale base rates and increased demand, as well as a decrease in other operations and maintenance expenses.

106

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

Retail Revenues

In the third quarter 2009, retail revenues were $231.9 million compared to $241.8 million for the corresponding period in 2008. For year-to-date 2009, retail revenues were $608.8 million compared to $597.3 million for the corresponding period in 2008.

Details of the change to retail revenues are as follows:


	Third Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	241.8					$	597.3
Estimated change in —
Rates and pricing		1.3			0.5			3.8			0.6
Sales growth (decline)		2.0			0.8			(0.5	)		(0.1	)
Weather		0.4			0.2			0.6			0.1
Fuel and other cost recovery		(13.6	)		(5.6	)		7.6			1.3

Retail – current year	$	231.9			(4.1	)%	$	608.8			1.9	%

Revenues associated with changes in rates and pricing increased in the third quarter 2009 when compared to the corresponding period in 2008 due to a $0.7 million increase related to the reclassification of 2008 System Restoration Rider (SRR) revenue reductions to expense pursuant to an order from the Mississippi PSC dated January 9, 2009 and an increase in retail revenues of approximately $0.6 million related to the ECO Plan rate.

Revenues associated with changes in rates and pricing increased year-to-date 2009 when compared to the corresponding period in 2008 due to a $2.9 million increase related to the reclassification of 2008 SRR revenue reductions to expense pursuant to an order from the Mississippi PSC dated January 9, 2009 and an increase in base rates of $0.9 million related to a PEP rate change effective in mid-January 2008.

For additional information on SRR, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – System Restoration Rider” of Mississippi Power in Item 7 of the Form 10-K.

Revenues attributable to changes in sales increased $2.0 million in the third quarter 2009 when compared to the corresponding period in 2008, primarily due to the impacts of Hurricane Gustav, which caused the temporary closure of casinos and numerous large industrial customers in September 2008. During the third quarter 2009, production levels improved for several larger industrial customers from previous recession-driven lows. KWH energy sales to industrial customers increased 8.7%.

Revenues attributable to changes in sales declined for year-to-date 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential and commercial customers decreased slightly, primarily due to a recessionary economy. KWH energy sales to industrial customers increased 1.9%. The increase in industrial sales is primarily due to increased production levels experienced by some industrial customers in the third quarter 2009 and the impacts of Hurricane Gustav in September 2008.

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

Revenues attributable to changes in weather were not material in the third quarter and year-to-date 2009 when compared to the corresponding periods in 2008.

Fuel and other cost recovery revenues decreased in the third quarter 2009 when compared to the corresponding period in 2008, primarily due to lower recoverable fuel costs. Fuel and other cost recovery revenues increased year-to-date 2009 when compared to the corresponding period in 2008, primarily as a result of higher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power’s service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

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

In the third quarter 2009, wholesale revenues from non-affiliates were $81.2 million compared to $106.6 million for the corresponding period in 2008. The decrease was due to $18.4 million in decreased revenues from customers outside Mississippi Power’s service territory, and $7.0 million in decreased revenues from customers inside Mississippi Power’s service territory. The $18.4 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $10.5 million decrease associated with lower prices resulting from lower marginal cost of fuel, a $7.8 million decrease in sales, and a $0.1 million decrease in capacity revenues. The $7.0 million decrease in revenues from customers inside Mississippi Power’s service territory was primarily due to an $8.8 million decrease in fuel costs, partially offset by a $1.8 million increase due to higher demand by customers and a base rate increase effective in January 2009.

For year-to-date 2009, wholesale revenues to non-affiliates were $235.1 million compared to $275.0 million for the corresponding period in 2008. The decrease was due to $45.8 million in decreased revenues from customers outside Mississippi Power’s service territory, partially offset by $5.9 million in increased revenues from customers inside Mississippi Power’s service territory. The $45.8 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $34.9 million decrease associated with lower prices resulting from lower marginal cost of fuel, a $10.5 million decrease in sales, and a $0.4 million decrease in capacity revenues. The $5.9 million increase in revenues from customers inside Mississippi Power’s service territory was primarily due to a $7.6 million increase resulting from higher demand by customers and a base rate increase effective in January 2009, as well as a $0.2 million increase in ECO Plan revenues, partially offset by a $1.9 million decrease in fuel costs.

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Wholesale Revenues – Affiliates

In the third quarter 2009, wholesale revenues from affiliates were $13.4 million compared to $28.9 million for the corresponding period in 2008. The decrease was primarily due to a $16.2 million decrease in energy revenues, of which $7.1 million was associated with decreased sales and $9.1 million was associated with lower prices. Capacity revenues increased $0.7 million.

For year-to-date 2009, wholesale revenues from affiliates were $30.8 million compared to $79.8 million for the corresponding period in 2008. The decrease was primarily due to a $50.3 million decrease in energy revenues, of which $38.8 million was associated with decreased sales and $11.5 million was associated with lower prices. Capacity revenues increased $1.3 million.

Other Revenues

N/M – Not Meaningful

In the third quarter 2009, the change in other revenues was not material when compared to the corresponding period in 2008.

For year-to-date 2009, other revenues were $11.4 million compared to $12.6 million for the corresponding period in 2008. The decrease was primarily due to a $0.9 million decrease in transmission revenues and a $0.6 million transmission contract buyout that occurred in 2008.

Fuel and Purchased Power Expenses


	Third Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Third Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(26.2	)		(15.0	)	$	(49.4	)		(11.1	)
Purchased power – non-affiliates		(12.1	)		(87.9	)		(14.0	)		(65.6	)
Purchased power – affiliates		(13.5	)		(38.0	)		(13.6	)		(17.2	)

Total fuel and purchased power expenses	$	(51.8	)				$	(77.0	)

In the third quarter 2009, total fuel and purchased power expenses were $171.7 million compared to $223.5 million for the corresponding period in 2008. The decrease was primarily due to a $46.9 million decrease in cost of fuel and purchased power and a $4.9 million decrease related to the total KWHs generated and purchased.

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For year-to-date 2009, total fuel and purchased power expenses were $466.6 million compared to $543.6 million for the corresponding period in 2008. The decrease was primarily due to a $59.1 million decrease in cost of fuel and purchased power and a $17.9 million decrease related to the total KWHs generated and purchased.

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

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


	Third Quarter		Third Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2009		2008		Change			2009		2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		4.38		4.99		(12.2	)		4.34		4.32		0.5
Purchased power		3.62		7.64		(52.6	)		3.62		6.66		(45.7	)

In the third quarter 2009, fuel expense was $148.1 million compared to $174.3 million for the corresponding period in 2008. The decrease was primarily due to a 12.2% decrease in the price of fuel primarily due to lower natural gas prices. Also contributing to the decrease was a 3.2% decrease in generation from Mississippi Power facilities resulting from purchased power available at lower cost and lower energy sales.

For year-to-date 2009, fuel expense was $393.9 million compared to $443.3 million for the corresponding period in 2008. The decrease was primarily due to an 11.6% decrease in generation from Mississippi Power facilities resulting from purchased power available at lower cost and lower energy sales, partially offset by a 0.5% increase in the price of fuel primarily due to an increase in coal prices.

Non-Affiliates

In the third quarter 2009, purchased power from non-affiliates was $1.7 million compared to $13.8 million for the corresponding period in 2008. The decrease was primarily the result of a 53.4% decrease in the average cost of purchased power per KWH and a 74.0% decrease in KWH volume purchased. The decrease in prices was due to a lower marginal cost of fuel while the decrease in volume was a result of available lower-cost Southern Company system generation resulting in less opportunity purchases.

For year-to-date 2009, purchased power from non-affiliates was $7.4 million compared to $21.4 million for the corresponding period in 2008. The decrease was primarily the result of a 64.1% decrease in the average cost of purchased power per KWH and a 4.1% decrease in KWH volume purchased. The decrease in prices was due to a lower marginal cost of fuel while the decrease in volume was a result of available lower-cost Southern Company system generation resulting in less opportunity purchases.

Affiliates

In the third quarter 2009, purchased power from affiliates was $21.9 million compared to $35.4 million for the corresponding period in 2008. The decrease was primarily due to a 57.8% decrease in the average cost of purchased power per KWH, partially offset by a 60.7% increase in KWH volume purchased.

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For year-to-date 2009, purchased power from affiliates was $65.3 million compared to $78.9 million for the corresponding period in 2008. The decrease was primarily due to a 45.1% decrease in the average cost of purchased power per KWH, partially offset by a 51.0% increase in KWH volume purchased.

Other Operations and Maintenance Expenses

In the third quarter 2009, other operations and maintenance expenses were $61.1 million compared to $64.8 million for the corresponding period in 2008. The decrease was primarily due to a $1.8 million reduction in production outage expenses and a $1.7 million reduction of generation construction screening expenses incurred in the third quarter 2008 which were originally expensed and subsequently reclassified in the fourth quarter 2008 to a regulatory asset upon the FERC’s acceptance of the wholesale rate filing in October 2008. Also contributing to the change was a $1.5 million decrease in transmission and distribution expenses as a result of the timing of projects and overall reductions in spending. These decreases were partially offset by a $1.5 million increase in administrative and general expenses primarily due to an increase in property insurance expense.

For year-to-date 2009, other operations and maintenance expenses were $182.5 million compared to $193.0 million for the corresponding period in 2008. The decrease was primarily due to $5.9 million of generation construction screening expenses incurred in the first nine months of 2008 which were originally expensed and subsequently reclassified in the fourth quarter 2008 to a regulatory asset upon the FERC’s acceptance of the wholesale rate filing in October 2008. Also contributing to the change was an $8.0 million decrease in transmission, distribution, and generation expenses as a result of timing of projects and overall reductions in spending and a $1.2 million decrease in generation-related environmental expenses. These decreases were partially offset by a $3.6 million increase in expenses for the combined cycle long-term service agreement due to a 45% increase in operating hours as a result of the lower gas prices and a $2.1 million increase in administrative and general expenses primarily due to an increase in property insurance expense.

See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information.

Interest Expense, Net of Amounts Capitalized

In the third quarter 2009, interest expense, net of amounts capitalized was $6.1 million compared to $4.5 million for the corresponding period in 2008. The increase was due to a $1.5 million increase in interest expense associated with the issuance of new long-term debt in November 2008 and March 2009 and a $0.1 million increase of commitment fees.

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For year-to-date 2009, interest expense, net of amounts capitalized was $17.1 million compared to $13.3 million for the corresponding period in 2008. The increase was primarily due to a $3.8 million increase in interest expense associated with the issuance of new long-term debt in November 2008 and March 2009 and a $0.4 million increase in commitment fees, partially offset by a $0.5 million decrease in interest expense related to short-term indebtedness.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Mississippi Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” herein for additional information.

Other Income (Expense), Net

In the third quarter 2009, other income (expense), net was $0.5 million compared to $1.5 million for the corresponding period in 2008. The decrease was primarily due to a $2.7 million decrease in customer projects and a $0.2 million decrease in allowance for equity funds used during construction, partially offset by a $1.9 million increase due to mark-to-market gains on energy-related derivative positions.

For year-to-date 2009, other income (expense), net was $3.2 million compared to $6.0 million for the corresponding period in 2008. The decrease was primarily due to a $1.9 million decrease in customer projects and a decrease in amounts collected from customers for construction of substation projects which had a tax effect of $0.8 million.

Income Taxes

In the third quarter 2009, income taxes were $22.2 million compared to $19.5 million for the corresponding period in 2008. The increase was primarily due to a $1.1 million increase due to the actualization of the 2008 tax return in the third quarter 2009, a $0.9 million increase in unrecognized tax benefits, a $0.8 million increase resulting from the increase in pre-tax income, and an increase in income taxes resulting from fully amortizing a regulatory liability through income taxes in 2008 of $0.3 million pursuant to a December 2007 regulatory accounting order from the Mississippi PSC, partially offset by a $0.4 million decrease due to a higher production activities deduction.

For year-to-date 2009, income taxes were $46.3 million compared to $42.8 million for the corresponding period in 2008. The increase was primarily due to a $1.1 million increase due to the actualization of the 2008 tax return in the third quarter 2009, a $1.1 million increase resulting from the increase in pre-tax income, an increase in income taxes resulting from fully amortizing a regulatory liability through income taxes in 2008 of $1.0 million pursuant to a December 2007 regulatory accounting order from the Mississippi PSC, and a $0.4 million increase in unrecognized tax benefits, partially offset by a $0.2 million decrease due to a higher Mississippi manufacturing investment tax credit.

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

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FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Mississippi Power’s future earnings potential. The level of Mississippi Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power’s business of selling electricity. These factors include Mississippi Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power’s service area. Recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact. The timing and extent of the economic recovery 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 Mississippi Power in Item 7 of the Form 10-K.

Environmental Matters

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and cannot be determined at this time.

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Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the eight-hour ozone standard. On September 16, 2009, the EPA announced that it would reconsider its March 2008 decision regarding the eight-hour ozone standard, potentially resulting in a more stringent standard and designation of additional nonattainment areas within Mississippi Power’s service territory. The EPA is expected to propose any revisions to the standard by December 2009 and issue a final decision by August 2010. The impact of a more stringent standard will depend on the proposed and final regulations and resolution of any legal challenges and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, 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 information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.

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mandatory restrictions on Mississippi Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Mississippi PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

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 3, 2009, Mississippi Power submitted its 2009 ECO Plan notice which proposed an increase in annual revenue for Mississippi Power of approximately $1.5 million. On June 19, 2009, the Mississippi PSC approved the ECO Plan with the new rates effective June 2009.

Performance Evaluation Plan

The Mississippi Public Utilities Staff, pursuant to the Mississippi PSC’s 2004 order approving the current PEP, is reviewing the PEP to determine if any modifications should be made. On March 2, 2009, concurrent with this review, the annual PEP evaluation filing for 2009 was suspended. The suspension of the PEP filing for 2009 will not have a material impact on 2009 earnings. On August 3, 2009, the Mississippi Public Utilities Staff and Mississippi Power filed a joint report with the Mississippi PSC proposing several changes to the PEP which will result in a lower performance incentive under the PEP and therefore smaller and/or less frequent rate changes in the future. On November 2, 2009, the revised PEP was approved. Annual evaluations will resume for 2010 under the PEP. 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.

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On March 16, 2009, Mississippi Power submitted its annual PEP lookback filing for 2008, which recommended no surcharge or refund. On September 1, 2009, Mississippi Power, along with the Mississippi Public Utilities Staff, agreed and stipulated that no surcharge or refund is required.

System Restoration Rider

On September 10, 2009, the Mississippi PSC issued an order requiring Mississippi Power to develop SRR factors designed to reduce SRR revenue by approximately $1.5 million. The revised SRR factors will be in effect from November 2009 to March 2010.

Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. The Mississippi PSC approved the retail fuel cost recovery factor on March 3, 2009, with the new rates effective in March 2009. The retail fuel cost recovery factor will result in an annual increase in an amount equal to 10.3% of total 2008 retail revenues based on ten months of recovery under the new rate. At September 30, 2009, the amount of over recovered retail fuel costs included in the balance sheet was $10.6 million compared to $36.0 million under recovered at December 31, 2008. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and Market Base (MB) fuel cost recovery factor. Effective January 1, 2009, the wholesale MRA fuel rate increased resulting in an annual increase in an amount equal to 13.9% of total 2008 MRA revenues. Effective February 1, 2009, the wholesale MB fuel rate increased resulting in an annual increase in an amount equal to 16.7% of total 2008 MB revenues. At September 30, 2009, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheet was $9.1 million and $0.8 million compared to an under recovery of $15.4 million and $3.7 million, respectively, at December 31, 2008. Mississippi Power’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this increase to the billing factor will have no significant effect on Mississippi Power’s revenues or net income, but will increase annual cash flow.

In October 2008, the Mississippi PSC opened a docket to investigate and review interest and carrying charges under the fuel adjustment clause for utilities within the State of Mississippi, including Mississippi Power. A hearing was held in November 2008 to hear testimony regarding the method of calculating carrying charges on over and under recoveries of fuel-related costs. On March 4, 2009, the Mississippi PSC issued an order to apply the prime rate in calculating the carrying costs on the retail over or under recovery balances related to fuel cost recovery. On May 20, 2009, Mississippi Power filed the carrying cost calculation methodology as part of its compliance filing.

In August 2009, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of Mississippi Power’s fuel-related expenditures included in the fuel adjustment clause and the energy cost management clause for 2008 and 2009. The audit is scheduled to be completed in January 2010. The ultimate outcome of this matter cannot now be determined.

Storm Damage Cost Recovery

On March 2, 2009, Mississippi Power filed its Notice of Final Accounting related to Hurricane Katrina storm restoration costs and storm operations facility costs. An independent auditor on behalf of the Mississippi PSC is currently conducting an audit of these costs. Mississippi Power expects this audit to be completed by the end of 2009. The ultimate outcome of this matter cannot now be determined. See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Storm Damage Cost Recovery” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s storm restoration costs.

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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 the Kemper IGCC.

On June 5, 2009, the Mississippi PSC issued an order initiating an evaluation of the Kemper IGCC and establishing a two-phase procedural schedule. During Phase I, the Mississippi PSC will determine if a need exists for new generating resources. Hearings for Phase I were held in October 2009, and a decision is expected in November 2009. If it is determined a need exists in Phase I, the appropriate resource to fill the need as well as the cost recovery of that resource through application of the State of Mississippi’s Baseload Act of 2008 will be determined during Phase II. Hearings regarding Phase II issues are scheduled for February 2010 with a decision by May 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Mississippi Base Load Construction Legislation” of Mississippi Power in Item 7 of the Form 10-K for information regarding the Baseload Act of 2008.

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evaluating a combination of a joint ownership arrangement and a PPA which would provide SMEPA with up to 20% of the capacity and associated energy output from the Kemper IGCC.

The ultimate outcome of these matters cannot now be determined.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Mississippi Power. Mississippi Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $11 million and $14 million. On October 27, 2009, Southern Company and its subsidiaries received notice that an award of $165 million had been granted, of which $25 million relates to Mississippi Power, under its ARRA grant application for transmission and distribution automation and modernization projects pending final negotiations. Mississippi Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Other Matters

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Other Matters” of Mississippi Power in Item 7 of the Form 10-K for information regarding the South Mississippi Electric Power Association (SMEPA) contract. On June 3, 2009, Mississippi Power’s 10-year power supply agreement with SMEPA for approximately 152 MW effective April 1, 2011 was approved by the U.S. Department of Agriculture’s Rural Utilities Service.

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury 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 emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Mississippi Power’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Mississippi Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. 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

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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 Plant Daniel Operating Lease.

New Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Mississippi Power is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Mississippi Power’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Mississippi Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper borrowings and variable rate pollution control revenue bonds. 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. Market rates for committed credit have increased, and Mississippi Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees at Mississippi Power currently average less than ¹/4 of 1% per year. Mississippi Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Mississippi Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Mississippi Power’s investments in pension trust funds remained stable during the third quarter 2009. Mississippi Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on key variables including future trust fund performance and cannot be determined at this time.

Net cash provided from operating activities totaled $85.2 million for the first nine months of 2009, compared to $70.2 million for the corresponding period in 2008. The $15.0 million increase in cash provided from operating activities was primarily due to an increase in cash related to higher fuel rates effective in March 2009, partially offset by an increase in cash payments related to fuel inventory and a decrease in deferred income taxes. Net cash used for investing activities totaled $88.7 million for the first nine months of 2009, compared to $99.5 million for the corresponding period in 2008. The $10.8 million decrease was primarily due to a decrease in property additions. Net cash provided from financing activities totaled $9.0 million for the first nine months of 2009, compared to $67.7 million for the corresponding period in 2008. The $58.7 million decrease was primarily due to a $69.5 million decrease in notes payable and a $32.1 million decrease related to an increase in redemptions in the first nine months of 2009 compared to the corresponding period in 2008, partially offset by a $45 million increase related to the issuance of long-term debt in the first quarter 2009.

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

Significant balance sheet changes for the first nine months of 2009 include a decrease in under recovered regulatory clause revenues of $55.0 million primarily due to lower fuel costs and the implementation of a higher fuel cost recovery factor in 2009. Fossil fuel inventory increased $42.8 million primarily due to increases in coal inventory and emissions allowances of $26.9 million and $15.9 million, respectively. Other regulatory assets increased $9.4 million primarily due to the increase in spending related to the Kemper IGCC, prepaid income taxes increased by $17.7 million, and total property, plant, and equipment increased by $27.7 million. Securities due within one year decreased by $39.9 million primarily due to senior notes maturing during the first quarter 2009. Notes payable decreased by $24.9 million primarily due to a decrease in commercial paper borrowings. Long-term debt increased by $123.3 million primarily due to the issuance of senior notes in the first quarter 2009.

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, scheduled maturities of long-term debt, as well as the related interest, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $1.3 million will be required through September 30, 2010 for maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; 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

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

Mississippi Power’s current liabilities sometimes exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Mississippi Power had at September 30, 2009 approximately $28.0 million of cash and cash equivalents and $148.5 million of unused committed credit arrangements with banks. These credit arrangements provide liquidity support to Mississippi Power’s commercial paper borrowings and $40 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Of the unused credit facilities, $18.5 million expire in 2009 and $130 million expire in 2010 while $43.5 million of these credit arrangements contain provisions allowing two-year term loans executable at expiration and $15 million contain provisions allowing one-year term loans executable at expiration. Subsequent to September 30, 2009, Mississippi Power increased an existing credit facility by $10 million and renewed $15 million of its credit facilities that were set to expire in 2009 for an additional one-year period. Mississippi Power expects to renew its credit facilities, as needed, prior to expiration. See Note 6 to the financial statements of Mississippi Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Mississippi Power may meet short-term cash needs

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

through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and other Southern Company subsidiaries. At September 30, 2009, Mississippi Power had no commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

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

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $8 million. At September 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $349 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.

On September 2, 2009, Moody’s affirmed the credit ratings of Mississippi Power’s senior unsecured notes and commercial paper of A1/P-1, respectively, and revised the rating outlook for Mississippi Power to negative. On October 6, 2009, Standard and Poor’s affirmed the credit rating of Mississippi Power’s senior unsecured notes and its short-term rating of A/A-1, respectively, and maintained its stable ratings outlook. On September 4, 2009, Fitch affirmed Mississippi Power’s senior unsecured notes and commercial paper ratings of AA-/F1+, respectively, and maintained a stable rating outlook for Mississippi Power.

Market Price Risk

Mississippi Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 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, Mississippi 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, 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 has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

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

The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:


	Third Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(59.8	)	$	(52.0	)
Contracts realized or settled		20.4			46.1
Current period changes^(a)		0.1			(33.4	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(39.3	)	$	(39.3	)

(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 months and nine months ended September 30, 2009 were an increase of $21 million and $13 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas positions. At September 30, 2009, Mississippi Power had a net hedge volume of 26 million mmBtu with a weighted average contract cost approximately $1.54 per mmBtu above market prices, compared to 30 million mmBtu at June 30, 2009 with a weighted average contract cost approximately $2.02 per mmBtu above market prices and compared to 29 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $1.89 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the energy cost management clause.

At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:


Asset (Liability) Derivatives	September 30, 2009			December 31, 2008
	(in millions)
Regulatory hedges	$	(39.5	)	$	(52.0	)
Cash flow hedges		—			—
Not designated		0.2			—

Total fair value	$	(39.3	)	$	(52.0	)

Energy-related derivative contracts which are designated as regulatory hedges relate to Mississippi Power’s fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost management clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, 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.

Unrealized pre-tax gains and losses recognized in income for the three months and nine months ended September 30, 2009 for energy-related derivative contracts that are not hedges were not material. For the three months and nine months ended September 30, 2008, the total net unrealized gains (losses) recognized in the statements of income were $(1) million and $1 million, respectively. See Note (E) to the Condensed Financial Statements herein for further details of these gains (losses).

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

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:


	September 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(39.3	)		(20.7	)		(18.1	)		(0.5	)
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(39.3	)	$	(20.7	)	$	(18.1	)	$	(0.5	)

Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Mississippi Power in Item 7 and Notes 1 and 6 to the financial statements of Mississippi Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.

Financing Activities

In March 2009, Mississippi Power issued $125 million of Series 2009A 5.55% Senior Notes due March 1, 2019. The proceeds were used to repay at maturity Mississippi Power’s $40 million aggregate principal amount of Series F Floating Rate Senior Notes due March 9, 2009, to repay a portion of short-term indebtedness, and for general corporate purposes, including Mississippi Power’s continuous construction program.

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	133,032		$	296,743		$	318,521		$	548,119
Wholesale revenues, affiliates		147,921			216,622			420,923			494,008
Other revenues		2,416			2,506			6,040			5,860

Total operating revenues		283,369			515,871			745,484			1,047,987

Operating Expenses:
Fuel		58,820			221,735			176,332			334,123
Purchased power, non-affiliates		20,019			56,312			66,279			107,180
Purchased power, affiliates		20,915			59,539			49,977			175,210
Other operations and maintenance		29,094			31,549			97,033			102,234
Depreciation and amortization		23,190			24,014			74,727			64,944
Taxes other than income taxes		4,166			4,130			13,714			13,311

Total operating expenses		156,204			397,279			478,062			797,002

Operating Income		127,165			118,592			267,422			250,985
Other Income and (Expense):
Interest expense, net of amounts capitalized		(21,438	)		(22,163	)		(64,589	)		(61,414	)
Other income (expense), net		2,699			675			2,465			13,289

Total other income and (expense)		(18,739	)		(21,488	)		(62,124	)		(48,125	)

Earnings Before Income Taxes		108,426			97,104			205,298			202,860
Income taxes		41,146			37,542			79,048			78,903

Net Income	$	67,280		$	59,562		$	126,250		$	123,957

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2009			2008		2009		2008
	(in thousands)					(in thousands)
Net Income	$	67,280		$	59,562	$	126,250	$	123,957
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(298), $11,533, $4, and $3,703, respectively		(459	)		17,831		7		5,715
Reclassification adjustment for amounts included in net income, net of tax of $948, $979, $2,814, and $3,669, respectively		1,461			1,512		4,336		5,670

Total other comprehensive income (loss)		1,002			19,343		4,343		11,385

Comprehensive Income	$	68,282		$	78,905	$	130,593	$	135,342

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	126,250		$	123,957
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		83,890			75,985
Deferred income taxes		8,020			13,952
Deferred revenues		33,290			27,492
Mark-to-market adjustments		(406	)		701
Accumulated billings on construction contract		35,565			62,045
Accumulated costs on construction contract		(39,890	)		(77,534	)
Recognized income on construction contract		(2,691	)		—
Gain on sale of property		(24	)		(6,015	)
Other, net		5,326			180
Changes in certain current assets and liabilities —
-Receivables		(44,195	)		(82,449	)
-Fossil fuel stock		2,215			(2,658	)
-Materials and supplies		(4,110	)		6,246
-Other current assets		396			2,102
-Accounts payable		(20,777	)		34,116
-Accrued taxes		62,260			43,438
-Accrued interest		(12,152	)		(12,448	)
-Other current liabilities		(199	)		(3,516	)

Net cash provided from operating activities		232,768			205,594

Investing Activities:
Property additions		(47,696	)		(45,114	)
Sale of property		52			5,009
Change in construction payables		6,915			(4,393	)
Payments pursuant to long-term service agreements		(26,118	)		(24,130	)
Other investing activities		(184	)		(1,083	)

Net cash used for investing activities		(67,031	)		(69,711	)

Financing Activities:
Decrease in notes payable, net		—			(49,748	)
Proceeds — Capital contributions		2,068			3,215
Payment of common stock dividends		(79,575	)		(70,876	)

Net cash used for financing activities		(77,507	)		(117,409	)

Net Change in Cash and Cash Equivalents		88,230			18,474
Cash and Cash Equivalents at Beginning of Period		37,894			5

Cash and Cash Equivalents at End of Period	$	126,124		$	18,479

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $441 and $7,009 capitalized for 2009 and 2008, respectively)	$	68,652		$	63,311
Income taxes (net of refunds)	$	20,467		$	33,109

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	At September 30,		At December 31,
Assets	2009		2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	126,124	$	37,894
Receivables —
Customer accounts receivable		37,580		23,640
Other accounts receivable		1,457		2,162
Affiliated companies		64,762		33,401
Fossil fuel stock, at average cost		15,551		17,801
Materials and supplies, at average cost		30,636		26,527
Prepaid service agreements — current		35,795		26,304
Prepaid income taxes		—		18,066
Other prepaid expenses		2,451		2,756
Assets from risk management activities		6,288		10,799
Other current assets		4,505		4,532

Total current assets		325,149		203,882

Property, Plant, and Equipment:
In service		2,880,426		2,847,757
Less accumulated provision for depreciation		423,971		351,193

Plant in service, net of depreciation		2,456,455		2,496,564
Construction work in progress		50,115		8,775

Total property, plant, and equipment		2,506,570		2,505,339

Deferred Charges and Other Assets:
Prepaid long-term service agreements		64,025		81,542
Other deferred charges and assets — affiliated		3,612		3,827
Other deferred charges and assets — non-affiliated		18,517		18,550

Total deferred charges and other assets		86,154		103,919

Total Assets	$	2,917,873	$	2,813,140

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Accounts payable —
Affiliated	$	45,918		$	62,732
Other		13,801			11,278
Accrued taxes —
Accrued income taxes		32,256			88
Other accrued taxes		13,584			2,343
Accrued interest		17,764			29,916
Liabilities from risk management activities		3,687			7,452
Billings in excess of costs on construction contract		4,891			11,907
Other current liabilities		24			224

Total current liabilities		131,925			125,940

Long-term Debt		1,297,543			1,297,353

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		220,617			209,960
Deferred capacity revenues — affiliated		65,344			32,211
Other deferred credits and liabilities — affiliated		5,891			6,667
Other deferred credits and liabilities — non-affiliated		5,108			2,648

Total deferred credits and other liabilities		296,960			251,486

Total Liabilities		1,726,428			1,674,779

Common Stockholder’s Equity:
Common stock, par value $.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		864,175			862,109
Retained earnings		348,984			302,309
Accumulated other comprehensive loss		(21,714	)		(26,057	)

Total common stockholder’s equity		1,191,445			1,138,361

Total Liabilities and Stockholder’s Equity	$	2,917,873		$	2,813,140

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

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

THIRD QUARTER 2009 vs. THIRD QUARTER 2008
AND
YEAR-TO-DATE 2009 vs. YEAR-TO-DATE 2008

OVERVIEW

Southern Power and its wholly-owned subsidiaries construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the southeastern wholesale market. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into PPAs with investor owned utilities, independent power producers, municipalities, and electric cooperatives.

To evaluate operating results and to ensure Southern Power’s ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (EFOR), return on invested capital (ROIC), and net income. EFOR defines the hours during peak demand times when Southern Power’s generating units are not available due to forced outages (the lower the better). ROIC is focused on earning a return on all invested capital that meets or exceeds Southern Power’s weighted average cost of capital. 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

Southern Power’s net income for the third quarter 2009 was $67.3 million compared to $59.6 million for the corresponding period in 2008. The increase was due primarily to increased capacity and energy revenues associated with the operation of Plant Franklin Unit 3 and profit recognized under a construction contract with the Orlando Utilities Commission (OUC) whereby Southern Power is providing engineering, procurement, and construction services to build a combined cycle unit for the OUC.

Southern Power’s net income for year-to-date 2009 was $126.3 million compared to $124.0 million for the corresponding period in 2008. The increase was due primarily to increased capacity and energy revenues associated with the operation of Plant Franklin Unit 3, increased generation from Southern Power’s combined cycle units due to lower natural gas prices, and profit recognized under a construction contract with the OUC whereby Southern Power is providing engineering, procurement, and construction services to build a combined cycle unit for the OUC. These favorable impacts were partially offset by a gain on the sale of an undeveloped tract of land in Orange County, Florida to the OUC and the receipt of a fee for participating in an asset auction that were both recognized in income in the first quarter 2008. Additionally, depreciation increased due to an increase in depreciation rates and interest expense increased due to a reduction of capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008.

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

Wholesale Revenues – Non-Affiliates

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 cost of available energy compared to the cost of Southern Power’s energy. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

Wholesale revenues from non-affiliates for the third quarter 2009 were $133.0 million compared to $296.7 million for the corresponding period in 2008. The decrease was due primarily to lower natural gas prices reducing energy revenues by $148.3 million and a reduction in mark-to-market gains of $40.6 million. These decreases were partially offset by increased capacity and energy revenues primarily from the operation of Plant Franklin Unit 3 of $25.2 million as a result of a PPA that began in January 2009.

Wholesale revenues from non-affiliates for year-to-date 2009 were $318.5 million compared to $548.1 million for the corresponding period in 2008. The decrease was due primarily to lower natural gas prices reducing energy revenues by $256.5 million and a reduction in mark-to-market gains of $1.7 million. These decreases were partially offset by increased capacity and energy revenues primarily from the operation of Plant Franklin Unit 3 of $28.5 million as a result of a PPA that began in January 2009.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” herein for additional information.

Wholesale Revenues – Affiliates

Wholesale energy sales to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

Wholesale revenues from affiliates for the third quarter 2009 were $147.9 million compared to $216.6 million for the corresponding period in 2008. The decrease was due primarily to lower natural gas prices reducing energy revenues by $77.3 million. The decrease was partially offset by increased energy revenues of $5.1 million due to increased power sales under the IIC due to lower natural gas prices and increased capacity revenues associated with the beginning of a PPA with Gulf Power in June 2009 of $3.5 million.

Wholesale revenues from affiliates for year-to-date 2009 were $421.0 million compared to $494.0 million for the corresponding period in 2008. The decrease was due primarily to lower natural gas prices reducing energy revenues by $197.9 million. This decrease was partially offset by increased energy revenues of $120.2 million due to increased power sales under the IIC resulting from lower natural gas prices and increased capacity revenues associated with the beginning of a PPA with Gulf Power in June 2009 of $4.6 million.

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

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

Fuel and Purchased Power Expenses


	Third Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Third Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(162.9	)		(73.5	)	$	(157.8	)		(47.2	)
Purchased power – non-affiliates		(36.3	)		(64.4	)		(40.9	)		(38.2	)
Purchased power – affiliates		(38.6	)		(64.9	)		(125.2	)		(71.5	)

Total fuel and purchased power expenses	$	(237.8	)				$	(323.9	)

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

In the third quarter 2009, total fuel and purchased power expenses were $99.8 million compared to $337.6 million for the corresponding period in 2008. Fuel and purchased power expenses decreased $164.9 million due to a 31.4% decrease in the average cost of natural gas and a 37.1% decrease in the average cost of purchased power. Additionally, fuel and purchased power expenses decreased $63.0 million primarily due to the beginning of a PPA in 2009 at Plant Franklin Unit 3 under which the cost of fuel is the responsibility of the counterparty. Mark-to-market losses decreased by an additional $32.9 million. These decreases were partially offset by $23.0 million due to increased generation at Southern Power’s combined cycle units due to lower natural gas prices.

For year-to-date 2009, total fuel and purchased power expenses were $292.6 million compared to $616.5 million for the corresponding period in 2008. Fuel and purchased power expenses decreased $375.3 million due to a 37.9% decrease in the average cost of natural gas and a 56.5% decrease in the average cost of purchased power. Additionally, mark-to-market losses decreased by $2.9 million. These decreases were partially offset by $54.3 million due to increased generation at Southern Power’s combined cycle units due to lower natural gas prices.

In the third quarter 2009, fuel expense was $58.8 million compared to $221.7 million for the corresponding period in 2008. Fuel expense decreased $100.0 million due to a 31.4% decrease in the average cost of natural gas and decreased $63.0 million due to the beginning of a PPA in 2009 at Plant Franklin Unit 3 under which the cost of fuel is the responsibility of the counterparty. Additionally, mark-to-market losses decreased by $28.4 million. The decrease in fuel expense was partially offset by a $28.5 million increase in fuel expense due to increased generation at Southern Power’s combined cycle units as a result of lower natural gas prices.

For year-to-date 2009, fuel expense was $176.3 million compared to $334.1 million for the corresponding period in 2008. Fuel expense decreased $290.0 million due to a 37.9% decrease in the average cost of natural gas. The decrease was partially offset by a $130.8 million increase in fuel expense due to a 40.7% increase in generation at Southern Power’s combined cycle units as a result of lower natural gas prices. Additionally, mark-to-market losses increased by $1.5 million.

In the third quarter 2009, purchased power expense was $40.9 million compared to $115.8 million for the corresponding period in 2008. Purchased power expense decreased $64.9 million due to a decrease in the average cost of purchased power and decreased $5.5 million due to increased generation at Southern Power’s

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combined cycle units during the third quarter 2009 due to lower natural gas prices. Additionally, mark-to-market losses decreased by $4.5 million.

For year-to-date 2009, purchased power expense was $116.3 million compared to $282.4 million for the corresponding period in 2008. Purchased power decreased $85.2 million due to a decrease in the average cost of purchased power and decreased $76.5 million due to increased generation at Southern Power’s combined cycle units due to lower natural gas prices. Additionally, mark-to market losses decreased by $4.4 million.

Other Operations and Maintenance Expenses

In the third quarter 2009, other operations and maintenance expenses were $29.1 million compared to $31.5 million for the corresponding period in 2008. The decrease was primarily due to a reduction of transmission expenses of $1.2 million as a result of a decrease in power sales into the market and a decrease in plant operations and maintenance activities of $1.2 million.

For year-to-date 2009, other operations and maintenance expenses were $97.0 million compared to $102.2 million for the corresponding period in 2008. The decrease was primarily due to transmission tariff penalties of $3.6 million recognized in 2008 and a reduction in transmission expense of $1.6 million as a result of a decrease in power sales into the market.

Depreciation and Amortization

In the third quarter 2009, depreciation and amortization was $23.2 million compared to $24.0 million for the corresponding period in 2008. The decrease was primarily due to asset retirements recognized in 2008. The decrease was partially offset by higher depreciation rates implemented during 2009.

For year-to-date 2009, depreciation and amortization was $74.7 million compared to $64.9 million for the corresponding period in 2008. The increase was due to the completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented during 2009. See Note 1 to the financial statements of Southern Power under “Depreciation” in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under “Southern Power Depreciation Policy” herein for additional information.

Interest Expense, Net of Amounts Capitalized

In the third quarter 2009, interest expense, net of amounts capitalized was $21.4 million compared to $22.2 million for the corresponding period in 2008. The decrease was due to a decrease in short-term borrowing levels.

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For year-to-date 2009, interest expense, net of amounts capitalized was $64.6 million compared to $61.4 million for the corresponding period in 2008. The increase was primarily due to a decrease in capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008, partially offset by a decrease in short-term borrowing levels.

Other Income (Expense), Net

In the third quarter 2009, other income (expense), net was $2.7 million compared to $0.7 million for the corresponding period in 2008. The change was primarily due to profit recognized under a construction contract with the OUC whereby Southern Power is providing engineering, procurement, and construction services to build a combined cycle unit for the OUC.

For year-to-date 2009, other income (expense), net was $2.5 million as compared to $13.3 million for the corresponding period in 2008. The change was primarily due to a $6.0 million gain on the sale of an undeveloped tract of land in Orange County, Florida to the OUC and a $6.4 million fee received for participating in an asset auction that were both recognized in the first quarter 2008. Southern Power was not the successful bidder in the auction. Profit recognized on a construction contract with the OUC in 2009 partially offset these decreases. Southern Power is providing engineering, procurement, and construction services to build a combined cycle unit for the OUC.

Income Taxes

In the third quarter 2009, income taxes were $41.1 million compared to $37.5 million for the corresponding period in 2008. The increase was primarily due to higher pre-tax earnings, partially offset by increases in the production activities deduction.

For year-to-date 2009, income taxes were $79.0 million compared to $78.9 million for the corresponding period in 2008. The increase was primarily due to higher pre-tax earnings, primarily offset by increases in the production activities deduction.

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. The level of future earnings also depends on numerous factors including regulatory matters (such as those related to affiliate contracts), creditworthiness of customers, total generating capacity available in the Southeast, the successful remarketing of capacity as current contracts expire, and Southern Power’s ability to execute its acquisition strategy and to construct generating facilities. Recessionary conditions have negatively impacted capacity revenues. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

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Environmental Matters

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

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 information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 24, 2009, the EPA published a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change and, on September 28, 2009, the EPA published a proposed rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that finalization of this rule will cause carbon dioxide and other greenhouse gases to become regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program, which both apply to power plants. On October 27, 2009, the EPA published a proposed rule governing how these programs would be applied to stationary sources, including power plants. The EPA has stated that it expects to finalize its endangerment finding and proposed rules in March 2010. The ultimate outcome of the endangerment finding and these proposed rules cannot be determined at this time and will depend on additional regulatory action and potential legal challenges.

In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives. Similar legislation is being considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Southern Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future results of operations, cash flows, and financial condition.

Carbon Dioxide Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Carbon Dioxide Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and cannot be determined at this time.

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FERC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives. Southern Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be immaterial. Southern Power is currently assessing the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Acquisitions and Divestitures

Hartwell Energy Limited Partnership Acquisition

On April 2, 2009, Southern Power signed an agreement to acquire all of the outstanding general and limited partnership interests of Hartwell Energy Limited Partnership (Hartwell). Hartwell owns a dual-fueled generating plant near Hartwell, Georgia with installed capacity of 318 MWs. The plant consists of two combustion turbine natural gas generating units with oil back-up. The entire output of the plant is sold under a PPA with Oglethorpe Power Corporation (Oglethorpe) through May 31, 2019.

The acquisition was subject to a right of first refusal held by Oglethorpe, certain regulatory approvals, and other conditions. On July 31, 2009, Oglethorpe exercised its right of first refusal and has purchased the ownership interests of Hartwell.

Nacogdoches Power LLC Acquisition

On October 8, 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power LLC from American Renewables LLC, the original developer of the project. Nacogdoches Power LLC plans to construct a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The

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generating plant will be fueled from wood waste. Construction is expected to commence in late 2009 and the plant is expected to begin commercial operation in 2012. The total estimated cost of the project is expected to be between $475 million and $500 million. The output of the plant is contracted under a PPA with Austin Energy that begins in 2012 and expires in 2032.

West Georgia Generating Company, LLC Acquisition and DeSoto County Generating Company, LLC Divestiture

On October 21, 2009, Southern Power entered into an agreement (the Agreement) to acquire all of the outstanding membership interests of West Georgia Generating Company, LLC (West Georgia) from Broadway Gen Funding, LLC (Broadway), an affiliate of LS Power. West Georgia owns a dual-fueled generating plant near Thomaston, Georgia with installed capacity of approximately 600 MWs. The plant consists of four combustion turbine natural gas generating units with oil back-up. The output from two units is contracted under PPAs with the Municipal Electric Authority of Georgia (MEAG Power) and the Georgia Energy Cooperative (GEC). The MEAG Power agreement began in 2009 and expires in 2029. The GEC agreement begins in 2010 and expires in 2030.

The Agreement provides for the transfer of all the outstanding membership interests of DeSoto County Generating Company, LLC from Southern Power to Broadway and the payment by Southern Power of approximately $140 million in cash consideration.

The Agreement is subject to certain regulatory approvals, including the approval of the FERC, as well as review by the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvements Act. The ultimate outcome of this matter cannot now be determined.

Construction Projects

Cleveland County Units 1-4

In December 2008, Southern Power announced that it will build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to go into commercial operation in 2012. Costs incurred through September 30, 2009 were $45.8 million. The total estimated construction cost is expected to be between $350 million and $400 million.

Power Sales Agreements

Southern Power has entered into PPAs with North Carolina Electric Membership Corporation (NCEMC) and North Carolina Municipal Power Agency No. 1 (NCMPA1) for a portion of the generating capacity from the Cleveland County plant that will begin in 2012 and expire in 2036 and 2031, respectively. NCEMC will purchase 180 MWs of capacity that will be supported by one unit at the plant and will purchase capacity from a second unit at the plant that will increase to 180 MWs over a seven-year phase-in period. NCMPA1 will purchase 180 MWs from a third unit at the plant. The NCEMC PPAs were approved by the Rural Utilities Service on March 6, 2009.

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.

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Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury 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 emissions, have become more frequent. The ultimate outcome of such potential litigation against Southern Power and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from any such proceedings would have a material adverse effect on Southern Power’s financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. 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, Normal Sale and Non-Derivative Transactions, Cash Flow Hedge Transactions, Mark-to-Market Transactions, Percentage of Completion, Asset Impairments, Acquisition Accounting, Contingent Obligations, and Depreciation.

New Accounting Standards

Variable Interest Entities

In June 2009, the FASB issued new guidance on the consolidation of variable interest entities, which replaces the quantitative-based risks and rewards calculation for determining whether an enterprise is the primary beneficiary in a variable interest entity with an approach that is primarily qualitative, requires ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity, and requires additional disclosures about an enterprise’s involvement in variable interest entities. Southern Power is required to adopt this new guidance effective January 1, 2010 and is evaluating the impact, if any, it will have on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power’s financial condition remained stable at September 30, 2009. Throughout the turmoil in the financial markets, Southern Power has maintained cash balances to cover the majority of its capital needs and has had limited need to issue commercial paper or draw on committed credit arrangements. Southern Power has successfully accessed the commercial paper market as needed during 2009. There was no commercial paper outstanding at September 30, 2009. Southern Power intends to continue to monitor its access to short-term and

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long-term capital markets as well as its bank credit arrangements as needed to meet future capital and liquidity needs. Market rates for committed credit have increased, and Southern Power may be subject to higher costs as its existing facilities are replaced or renewed. The current facility expires in 2012 and the commitment fee is less than ¹/₈ of 1%. Southern Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. See “Sources of Capital” herein for additional information.

Net cash provided from operating activities totaled $232.8 million for the first nine months of 2009, compared to $205.6 million for the corresponding period in 2008. The $27.2 million increase in cash provided from operating activities was due primarily to the timing of income tax payments and a reduction in costs incurred on the OUC construction contract, partially offset by a reduction in scheduled billings on the OUC construction contract. Net cash used for investing activities totaled $67.0 million for the first nine months of 2009, compared to $69.7 million for the corresponding period in 2008. The $2.7 million decrease was primarily due to reduced property additions as Plant Franklin Unit 3 was completed in June 2008 and was partially offset by the sale of land in 2008. Net cash used in financing activities totaled $77.5 million for the first nine months of 2009, compared to $117.4 million for the corresponding period in 2008. The change was primarily due to cash used to settle short-term borrowings in 2008, partially offset by an increase in dividends paid to Southern Company in 2009.

Significant asset changes in the balance sheet for the first nine months of 2009 include increases in cash and cash equivalents, increases in accounts receivable balances due to seasonality, and a reduction in prepaid service agreements due to completion of scheduled outages. Additionally, construction work in progress has increased due to Cleveland County construction activities.

Significant liability and stockholder’s equity changes in the balance sheet for the first nine months of 2009 include a reduction in affiliate accounts payable due to timing of payments to SCS, a reduction in billings in excess of cost due to the timing of scheduled payments and costs incurred with regard to the OUC construction contract whereby Southern Power is providing engineering, procurement, and construction services to build a combined cycle unit for the OUC. Additionally, accrued income and other taxes have also increased due to the timing of tax payments.

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

Sources of Capital

Southern Power may use operating cash flows, external funds, equity capital, or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any financings, if needed, will depend

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upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Southern Power in Item 7 of the Form 10-K for additional information.

Southern Power’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at September 30, 2009 $400 million in committed credit arrangements with banks that will expire in 2012. Proceeds from these credit arrangements 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.

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

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At September 30, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $366 million. At September 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $964 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact 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 Duke Energy that could require collateral, but not accelerated payment, in the event of a downgrade to Southern Power’s credit rating to below BBB- or Baa3. 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 and certain energy-related commodity prices. 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 hedging practices. It is Southern Power’s policy that derivatives be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.

Southern Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on

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existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

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

The changes in fair value of energy-related derivative contracts for the three months and nine months ended September 30, 2009 were as follows:


	Third Quarter		Year-to-Date
	2009		2009
	Changes		Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	3.2	$	3.4
Contracts realized or settled		—		0.2
Current period changes^(a)		0.6		0.2

Contracts outstanding at the end of the period, assets (liabilities), net	$	3.8	$	3.8

(a)

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

The decreases in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2009 were $0.6 million and $0.4 million, respectively, which is due to both volume and price changes in power and natural gas positions. The net hedge position at September 30, 2009 and respective period end dates that support these changes are as follows:


	September 30,			June 30,			December 31,
	2009			2009			2008

Power (net sold)

MWHs (in millions)		2.2			1.1			0.3
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	1.26		$	2.29		$	(2.29	)

Natural gas (net purchase)

Commodity – million mmBtu		5.1			2.9			1.9
Location basis – million mmBtu		2.0			2.0			—

Commodity – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	(0.23	)	$	(0.24	)	$	(2.16	)

Location basis – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	(0.01	)	$	0.05		$	—

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At September 30, 2009 and December 31, 2008, the net fair value of energy-related derivative contracts by hedge designation was reflected in the financial statements as follows:


	September 30,			December 31,
Asset (Liability) Derivatives	2009			2008
	(in millions)
Cash flow hedges	$	(0.8	)	$	(0.8	)
Not designated		4.6			4.2

Total fair value	$	3.8		$	3.4

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 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 recognized in the statements of income for the three months and nine months ended September 30, 2009 for energy-related derivative contracts that are not hedges were $2 million and $1 million, respectively. For the three months and nine months ended September 30, 2008, the total net unrealized gains (losses) recognized in the statements of income were $8 million and $(1) million, respectively. See Note (E) to the Condensed Financial Statements herein for further details of these gains (losses).

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at September 30, 2009 are as follows:


	September 30, 2009
	Fair Value Measurements
	Total		Maturity
	Fair Value		Year 1		Years 2&3		Years 4&5
			(in millions)
Level 1	$	—	$	—	$	—	$	—
Level 2		3.8		2.6		1.1		0.1
Level 3		—		—		—		—

Fair value of contracts outstanding at end of period	$	3.8	$	2.6	$	1.1	$	0.1

Southern Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Southern Power in Item 7 and Notes 1 and 6 to the financial statements of Southern Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein.

Financing Activities

Southern Power did not issue or redeem any long-term securities during the nine months ended September 30, 2009.

141

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, 2008 have been derived from the audited financial statements of each registrant. In the opinion of each registrant’s management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2009 and 2008. In addition, all subsequent events have been evaluated for disclosure through the issuance of the financial statements on November 6, 2009. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States 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 audited financial statements included in the Form 10-K and, with respect to Southern Company, the subsequently revised audited financial statements included in the Current Report on Form 8-K filed May 8, 2009 (the Form 8-K), and details which have not changed significantly in amount or composition since the filing of the Form 10-K and, for Southern Company, the Form 8-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 and, for Southern Company, the Form 8-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented do not necessarily indicate operating results for the entire year.

			Reclassifications

Certain prior period data presented in the financial statements have been reclassified to conform to the current year presentation. For comparative purposes, each registrant’s statements of income for the three and nine months ended September 30, 2008 were modified within the operating expenses section to combine the line items “Other operations” and “Maintenance” into a single line item entitled “Other operations and maintenance.” The balance sheets at December 31, 2008 of Southern Company, Alabama Power, and Georgia Power were modified to present a separate line item for “Other regulatory assets, current” previously included in “Other current assets” and a separate line item for “Other regulatory liabilities, current” previously included in “Other current liabilities.” In addition, Georgia Power’s balance sheet was modified to present a separate line item for “Joint owner accounts receivable” previously included in “Other accounts and notes receivable” and to reflect a new line item “Liabilities from risk management activities” previously included in “Other current liabilities.” Gulf Power’s balance sheet shows separately the amount of “Prepaid expenses” previously reported in “Other current assets” in the prior period. Southern Company modified its statements of cash flows within the investing activities section by collapsing the line items “Investment in unconsolidated subsidiaries” and “Hurricane Katrina capital grant proceeds” previously shown as separate line items into “Other investing activities” while “Change in construction payables” previously included in “Other investing activities” is shown separately in the current presentation. Within the operating activities of Georgia Power’s statements of cash flows, “Deferred expenses,” and “Insurance cash surrender value” previously included in “Other, net” in the prior period are now shown as separate line items, and “Deferred expenses—affiliates” previously shown as a separate line item is included in the line item “Deferred expenses.” Also, within the financing activities of the same statement, the line item “Capital leases” was collapsed into “Other

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financing activities.” Mississippi Power’s statement of cash flows for the nine months ended September 30, 2008 was modified within the operating activities to present separately from “Other, net” the amount of “Generation construction screening expense.”

These reclassifications had no effect on total assets, net income, cash flows, or earnings per share.

Effective January 1, 2009, Southern Company and its subsidiaries adopted retrospectively a new accounting standard for noncontrolling interests. In connection with the adoption, Southern Company evaluated the requirements with respect to the presentation of preferred and preference stock of subsidiaries. Based on the accounting guidance, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are considered to be “noncontrolling interests” and are separately presented as a component of “Stockholders’ Equity” on Southern Company’s consolidated balance sheets. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary’s board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as “Redeemable Preferred Stock of Subsidiaries” in a manner consistent with temporary equity. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision that would allow the holders to elect a majority of such subsidiary’s board.

			In addition, the new accounting standard for noncontrolling interests requires that preferred and preference dividends of subsidiaries previously presented within Southern Company’s consolidated statements of income as a component of “Other Income and (Expense)” be presented as a deduction from “Consolidated Net Income” to arrive at “Consolidated Net Income After Dividends on Preferred and Preference Stock.” In Southern Company’s consolidated statements of cash flows, the preferred and preference dividends previously classified in operating activities are now classified in financing activities.

			Southern Power Depreciation Policy

			See Note 1 to the financial statements of Southern Power under “Depreciation” in Item 8 of the Form 10-K for information regarding Southern Power’s depreciation policy. Southern Power revised its depreciation rates in 2009. The change in estimate is due to revised useful life assumptions for certain components of plant in service. The expected 2009 impact to Southern Power is an increase in depreciation expense of $4.8 million and a reduction in net income of $2.9 million.

			Nuclear Relicensing

			The NRC operating licenses for Plant Vogtle Units 1 and 2 were scheduled to expire in January 2027 and February 2029, respectively. In June 2007, Georgia Power filed an application with the NRC to extend the licenses for Plant Vogtle Units 1 and 2 for an additional 20 years. On June 3, 2009, the NRC approved the extension of the licenses as requested.

			Leveraged Leases

On June 29, 2009, Southern Company terminated two international leveraged lease investments for a net gain, after termination of related debt, of $25.5 million. The termination is reflected on the statements of cash flows and the statements of income on line items “Proceeds from property sales,” “Gain on disposition of lease termination,” and “Loss on extinguishment of debt.”

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(B)

CONTINGENCIES AND REGULATORY MATTERS

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

			General Litigation Matters

			Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, each registrant’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury 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 emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against the registrants and any of their 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 liabilities, if any, arising from such current proceedings would have a material adverse effect on such registrant’s financial statements.

			Mirant Matters

			Mirant was an energy company with businesses that included independent power projects and energy trading and risk management companies in the United States and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.

			*Mirant Bankruptcy*

In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization in December 2005, and Mirant announced that this plan became effective in January 2006. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).

Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed under “Guarantees” in Note 7 to the financial statements of Southern Company in Item 8 of the Form 10-K and with various lawsuits related to Mirant discussed below. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax returns through 2001, as discussed in Note 5 to the financial statements of Southern Company in Item 8 of the Form 10-K. In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid approximately $39 million in additional tax and interest related to Mirant tax items and filed a claim in Mirant’s bankruptcy case for that amount. Southern Company has received from the IRS approximately $38 million in refunds related to Mirant. Southern Company believes it has a right to recoup the $39 million tax payment owed by Mirant from such tax refunds. As a result, Southern Company intends to retain the tax refunds and reduce its claim against Mirant for the payment of Mirant taxes by the amount of such refunds. MC Asset Recovery, LLC, a special purpose subsidiary of Reorganized Mirant (MC Asset Recovery), has objected to and sought to equitably subordinate the Southern Company tax claim in its fraudulent transfer litigation against Southern Company. Southern Company’s proofs of claim filed in the Mirant bankruptcy survive the settlement of the MC Asset Recovery litigation. Southern Company has reserved the remaining amount with respect to its Mirant tax claim.

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			Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional IRS assessments. As a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. As part of a complaint filed against Southern Company in June 2005 and amended thereafter, Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (Unsecured Creditors’ Committee) objected to and sought equitable subordination of Southern Company’s claims, and Mirant moved to reject the separation agreements entered into in connection with the spin-off, which motion was granted on June 4, 2009. MC Asset Recovery has been substituted as plaintiff in the complaint. If Southern Company’s claims for indemnification with respect to these, or any additional future payments, are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. The final outcome of this matter cannot now be determined.

			*MC Asset Recovery Litigation*

In June 2005, Mirant, as a debtor in possession, and the Unsecured Creditors’ Committee filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005, February 2006, May 2006, and March 2007.

In December 2005, the Bankruptcy Court entered an order authorizing the transfer of this proceeding, along with certain other actions, to MC Asset Recovery. Under that order, Reorganized Mirant was obligated to fund up to $20 million in professional fees in connection with the lawsuits, as well as certain additional amounts. Any net recoveries from these lawsuits would be distributed to, and shared equally by, certain unsecured creditors and the original equity holders. In January 2006, the U.S. District Court for the Northern District of Texas substituted MC Asset Recovery as plaintiff.

The complaint, as amended in March 2007, alleged that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The alleged fraudulent transfers and illegal dividends included without limitation: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80% interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer plaintiff asserted was valued at over $200 million. The complaint also sought to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleged that Southern Company was liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of recovery and that Southern Company breached its fiduciary duties to Mirant and its creditors, caused Mirant to breach its fiduciary duties to creditors, and aided and abetted breaches of fiduciary duties by Mirant’s directors and officers. The complaint also sought recoveries under the theories of restitution and unjust enrichment. In addition, the complaint alleged a claim under the Federal Debt Collection Procedure Act (FDCPA) to avoid certain transfers from Mirant to Southern Company; however, in July 2008, the court ruled that the FDCPA does not apply and that Georgia law should apply instead. The complaint sought monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, the complaint included an objection to Southern Company’s pending claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements of Southern Company in Item 8 of the Form 10-K) and sought equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the complaint in April 2007.

In January 2006, the U.S. District Court for the Northern District of Texas granted Southern Company’s motion to withdraw this action from the Bankruptcy Court and, in February 2006, granted Southern Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia. In May 2006, Southern Company filed a motion for summary judgment seeking entry of judgment against the plaintiff as to all counts of the complaint. In December 2006, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the motion. As a result, certain breach of fiduciary duty claims alleged in earlier versions of

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

the complaint were barred; all other claims in the complaint were allowed to proceed. In August 2008, Southern Company filed a second motion for summary judgment. MC Asset Recovery filed its response to Southern Company’s motion for summary judgment in October 2008. On February 5, 2009, the court denied the summary judgment motion in connection with the fraudulent conveyance and illegal dividend claims concerning certain advance return/loan repayments in 1999, dividends in 1999 and 2000, and transfers in connection with Mirant’s separation from Southern Company. The court granted Southern Company’s motion for summary judgment with respect to certain claims, including claims for unjust enrichment, claims that Southern Company aided and abetted Mirant’s directors’ breach of fiduciary duties to Mirant, and claims that Southern Company used Mirant as an alter ego. In addition, the court granted Southern Company’s motion in connection with the fraudulent transfer and illegal dividend claims concerning certain turbine termination payments.

			On March 31, 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve the action. The settlement includes an agreement by Southern Company to pay MC Asset Recovery $202 million and requires MC Asset Recovery to release Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in connection with Mirant’s plan of reorganization, as well as to release all actions against current or former officers and directors of Mirant and Southern Company that have or could have been filed. Pursuant to the settlement, Southern Company recorded a charge in the first quarter 2009 of $202 million, which was paid in the second quarter 2009. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. On June 29, 2009, the case was dismissed with prejudice. Southern Company’s claims in the Mirant bankruptcy remain pending. Southern Company is currently evaluating potential recovery of the settlement payment through various means. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. The ultimate outcome of any such recovery and/or income tax treatment cannot be determined at this time.

			Environmental Matters

			*New Source Review Actions*

In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by Mississippi Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the Court denied the motion based on lack of jurisdiction, and the EPA has not refiled. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization. It also formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, where the appeal was stayed, pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007, and in December 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, and the ultimate outcome of these matters cannot be determined at this time.

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

			*Carbon Dioxide Litigation*

			New York Case

			In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. This ruling is subject to potential reconsideration and appeal. Therefore, the ultimate outcome of these matters cannot be determined at this time.

			Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend 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 the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. On September 30, 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled that the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			conduct caused the injury alleged. The ultimate outcome of this matter may depend on appeals or other legal proceedings and cannot be determined at this time.

			Environmental Remediation

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

Georgia Power’s environmental remediation liability at September 30, 2009 was $13.6 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 claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and CERCLA NPL are anticipated.

By letter dated September 30, 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 from the EPA. Georgia Power, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, on April 30, 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, it is not expected to have a material impact on Georgia Power’s financial statements.

Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $66.6 million at September 30, 2009. 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 now in bankruptcy and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. Amounts expensed related to this work have not been material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of PRPs. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan. 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 additional information.

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

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			FERC Matters

			*Market-Based Rate Authority*

Each of the traditional operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.

In November 2007, the presiding administrative law judge issued an initial decision regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the traditional operating companies and Southern Power to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates and could also result in total refunds of up to $19.7 million, plus interest. The potential refunds include $3.9 million for Alabama Power, $5.8 million for Georgia Power, $0.8 million for Gulf Power, $8.4 million for Mississippi Power, and $0.7 million for Southern Power, in each case plus interest. Southern Company and its subsidiaries believe that there is no meritorious basis for an adverse decision in this proceeding and are vigorously defending themselves in this matter.

In June 2007, the FERC issued its final rule in Order No. 697 regarding market-based rate authority. The FERC generally retained its current market-based rate standards. Responding to a number of requests for rehearing, the FERC issued Order No. 697-A on April 21, 2008, Order No. 697-B on December 12, 2008, and Order No. 697-C on June 16, 2009. These orders largely affirmed and clarified the FERC’s prior revision and codification of the regulations governing market-based rates for public utilities. In accordance with the orders, Southern Company submitted to the FERC an updated market power analysis in September 2008 related to its continued market-based rate authority.

			In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction within 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas.

			*Intercompany Interchange Contract*

Southern Company’s generation fleet in its retail service territory is operated under the IIC as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, Southern Power, and SCS, as agent, under the terms of which the Power Pool is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility

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companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.

			In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on Southern Company’s or the traditional operating companies’ financial statements. Southern Power’s annual cost of implementing the compliance plan is approximately $7.0 million. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments challenging the audit report’s findings were submitted. A decision is now pending from the FERC.

			*Generation Interconnection Agreements*

In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, filed complaints at the FERC requesting that the FERC modify the agreements and that those Southern Company subsidiaries refund a total of $19 million previously paid for interconnection facilities, of which $11 million would be refunded by Alabama Power and $8 million by Georgia Power. No other similar complaints are pending with the FERC.

			In January 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, Southern Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied, and Southern Company and Tenaska appealed the orders to the U.S. Circuit Court for the District of Columbia. On July 7, 2009, the court affirmed the FERC’s January 2007 order and, on September 9, 2009, denied Tenaska’s petitions for rehearing of such order. The ultimate outcome of these matters cannot now be determined.

			Right of Way Litigation

Southern Company and certain of its subsidiaries, including Mississippi Power, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and Mississippi Power believe that they have complied with applicable laws and that the plaintiffs’ claims are without merit.

To date, Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and dismissals of the related cases are in progress. These agreements have not resulted in any material effects on Southern Company’s or Mississippi Power’s financial statements.

151

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fibernet, Inc., a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. Southern Company and Mississippi Power believe that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

			Nuclear Fuel Disposal Cost Litigation

See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 of the Form 10-K for information regarding the litigation brought by Alabama Power and Georgia Power against the government for breach of contracts related to the disposal of spent nuclear fuel. In July 2007, the U.S. Court of Federal Claims awarded Georgia Power a total of $30 million, based on its ownership interests, and awarded Alabama Power $17.3 million, representing all of the direct costs of the expansion of spent nuclear fuel storage facilities from 1998 through 2004. In August 2007, the government filed a motion for reconsideration, which was denied in November 2007. In January 2008, the government filed a notice of appeal to the U.S. Court of Appeals for the Federal Circuit. In February 2008, the government filed a motion to stay the appeal pending the court’s decisions in three other cases already on appeal. In April 2008, the court granted the government’s motion to stay the appeal pending the court’s decisions in three other similar cases already on appeal. Those cases were decided in August 2008. The Court of Appeals has left the stay of appeals in place pending appeals in two other cases involving spent nuclear fuel contracts.

			In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. In October 2008, the court denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of September 30, 2009 for either claim. The final outcome of these matters cannot be determined at this time; however, no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.

			Income Tax Matters

			*Leveraged Leases*

In 2002, the IRS began the examination of three sale-in-lease-out (SILO) transactions entered into by Southern Company. As a result of this examination, the IRS challenged the deductions related to these transactions. Southern Company disagreed with the IRS’s conclusion, went through all administrative appeals, paid approximately $168 million of the additional tax, and sued the IRS for the refund of such taxes.

During the second quarter 2008, decisions in favor of the IRS were reached in several court cases involving other taxpayers with similar leveraged lease investments. Pursuant to the application of certain accounting standards related to leveraged leases, management is required to assess on a periodic basis the likely outcome of the uncertain tax positions related to the SILO transactions. Based on these accounting standards and management’s review of the recent court decisions, Southern Company recorded an after-tax charge of approximately $67 million in the second quarter 2008.

152

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			In December 2008, Southern Company received from the Commissioner of the IRS an invitation to participate in a global settlement initiative related to the SILO transactions. Southern Company accepted the settlement offer on January 8, 2009. Pursuant to the settlement offer, Southern Company recorded an additional after-tax charge in the fourth quarter 2008 of $16 million. Including the charge recorded in the second quarter 2008, total after-tax charges related to settling the SILO litigation amounted to $83 million in 2008. Of the total, approximately $7 million represented interest and $76 million represented non-cash charges related to the reallocation of lease income and will be recognized in income over the remaining term of the affected leases. All additional taxes due as a result of the settlement have now been paid. A final closing agreement with the IRS was signed on June 19, 2009. This agreement ends the dispute with the IRS. Subsequent to the settlement, Southern Company terminated one of the SILOs and one other international leveraged lease. Of the $76 million non-cash charges related to the IRS settlement, approximately $30 million related to the SILO which was terminated on June 29, 2009.

			*Georgia State Income Tax Credits*

			Georgia Power’s 2005 through 2008 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, these claims could have a significant, and possibly material, positive effect on Southern Company’s and Georgia Power’s net income. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s and Georgia Power’s cash flow. The ultimate outcome of this matter cannot now be determined.

			Retail Rate Matters

153

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			Construction Projects

			*Integrated Coal Gasification Combined Cycle*

On January 16, 2009, Mississippi Power filed for a Certificate of Public Convenience and Necessity with the Mississippi PSC to allow construction of a new electric generating plant located in Kemper County, Mississippi. The plant would utilize an advanced integrated coal gasification combined cycle technology with an output capacity of 582 MWs. The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. This certificate, if approved by the Mississippi PSC, would authorize Mississippi Power to acquire, construct and operate the Kemper IGCC and related facilities. The Kemper IGCC, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. As part of its filing, Mississippi Power has requested certain rate recovery treatment in accordance with the base load construction legislation.

Mississippi Power filed an application in June 2006 with the DOE for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The DOE subsequently certified the Kemper IGCC, and in November 2006 the IRS allocated Internal Revenue Code Section 48A tax credits of $133 million to Mississippi Power. On May 11, 2009, Mississippi Power received notification from the IRS formally certifying these tax credits. The utilization of these credits is dependent upon meeting the certification requirements for the Kemper IGCC, including an in-service date no later than May 2014. Mississippi Power has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for the Section 48A credits.

On February 14, 2008, Mississippi Power also requested that the DOE transfer the remaining funds previously granted to a cancelled Southern Company project that would have been located in Orlando, Florida. On December 12, 2008, an agreement was reached to assign the remaining funds to the Kemper IGCC. The estimated construction cost of the Kemper IGCC is approximately $2.2 billion, which is net of $220 million related to funding to be received from the DOE related to project construction. The remaining DOE funding of $50 million is projected to be used for demonstration over the first few years of operation.

Beginning in December 2006, the Mississippi PSC has approved Mississippi Power’s requested accounting treatment to defer the costs associated with Mississippi Power’s generation resource planning, evaluation, and screening activities as a regulatory asset. On December 22, 2008, Mississippi Power requested an amendment to its original order that would allow these costs to continue to be charged to and remain in a regulatory asset until January 1, 2010. On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures. The Mississippi PSC’s determination of prudence for Mississippi Power’s pre-construction costs is scheduled to occur by May 2010. As of September 30, 2009, Mississippi Power had spent a total of $64.5 million associated with Mississippi Power’s generation resource planning, evaluation, and

154

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

screening activities, including regulatory filing costs. Costs incurred for the nine months ended September 30, 2009 totaled $22.2 million as compared to $18.1 million for the nine months ended September 30, 2008. Of the total $64.5 million, $59.8 million was deferred in other regulatory assets, $3.9 million was related to land purchases capitalized, and $0.8 million was previously expensed.

			The ultimate outcome of these matters cannot now be determined.

			*Nuclear*

In August 2006, Southern Nuclear, on behalf of Georgia Power, Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), 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), filed an application with the NRC for an early site permit relating to two additional nuclear units on the site of Plant Vogtle. On August 26, 2009, the NRC issued the Early Site Permit and Limited Work Authorization for Plant Vogtle Units 3 and 4. See Note 4 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information on these co-owners. On March 31, 2008, Southern Nuclear filed an application with the NRC for a combined construction and operating license (COL) for the new units. If licensed by the NRC, Plant Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively.

On April 8, 2008, Georgia Power, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse and Stone & Webster, Inc. (collectively, Consortium) entered into an 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 (Vogtle 3 and 4 Agreement).

The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners will pay a purchase price that will be subject to certain price escalation and adjustments, adjustments for change orders, and performance bonuses. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. Georgia Power’s proportionate share, based on its current ownership interest, is 45.7%.

155

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The Owners and the Consortium have agreed to certain liquidated damages upon the Consortium’s failure to comply with the schedule and performance guarantees. The Owners and the Consortium also have agreed to certain bonuses payable to the Consortium for early completion and unit performance. The Consortium’s liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.

The obligations of Westinghouse Electric Company LLC and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement.

In addition, the Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events.

Southern Company is also exploring other possibilities relating to additional nuclear power projects, both on its own or in partnership with other utilities. The final outcome of these matters cannot now be determined.

156

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(C)

FAIR VALUE MEASUREMENTS

As of September 30, 2009, 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, are as follows:


	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2009:	(Level 1)		(Level 2)		(Level 3)		Total

	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	20	$	—	$	20
Nuclear decommissioning trusts^(a)(b)		681		375		—		1,056
Cash equivalents and restricted cash		499		—		—		499
Other		3		48		31		82

Total	$	1,183	$	443	$	31	$	1,657

Liabilities:
Energy-related derivatives	$	—	$	183	$	—	$	183
Interest rate derivatives		—		12		—		12

Total	$	—	$	195	$	—	$	195


Alabama Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	4
Nuclear decommissioning trusts:^(a)
Domestic equity		275		48		—		323
U.S. Treasury and government agency securities		—		18		—		18
Corporate bonds		7		55		—		62
Mortgage and asset backed securities		—		48		—		48
Other		—		13		—		13
Cash equivalents and restricted cash		221		—		—		221

Total	$	503	$	186	$	—	$	689

Liabilities:
Energy-related derivatives	$	—	$	51	$	—	$	51
Interest rate derivatives		—		6		—		6

Total	$	—	$	57	$	—	$	57


Georgia Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	5
Nuclear decommissioning trusts:^(a)
Domestic equity		399		1		—		400
U.S. Treasury and government agency securities		—		42		—		42
Municipal bonds		—		20		—		20
Corporate bonds		—		96		—		96
Mortgage and asset backed securities		—		26		—		26
Other		—		8		—		8
Cash equivalents and restricted cash		6		—		—		6

Total	$	405	$	198	$	—	$	603

Liabilities:
Energy-related derivatives	$	—	$	71	$	—	$	71
Interest rate derivatives		—		5		—		5

Total	$	—	$	76	$	—	$	76

157

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2009:	(Level 1)		(Level 2)		(Level 3)		Total

	(in millions)
Gulf Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents and restricted cash		24		—		—		24

Total	$	24	$	1	$	—	$	25

Liabilities:
Energy-related derivatives	$	—	$	16	$	—	$	16
Interest rate derivatives		—		1		—		1

Total	$	—	$	17	$	—	$	17


Mississippi Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents		27		—		—		27

Total	$	27	$	2	$	—	$	29

Liabilities:
Energy-related derivatives	$	—	$	41	$	—	$	41


Southern Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	8
Cash equivalents		126		—		—		126

Total	$	126	$	8	$	—	$	134

Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	4


(a)		Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.

(b)		For additional detail, see the nuclear decommissioning trusts for Alabama Power and Georgia Power.

Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note (E) under “Financial Instruments” herein for additional information. The nuclear decommissioning trust funds are invested in a diversified mix of equity and fixed income securities. The cash equivalents and restricted cash consist of securities with original maturities of 90 days or less. “Other” represents marketable securities and certain deferred compensation funds also invested in various marketable securities. All of these financial instruments and investments are valued primarily using the market approach.

Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at September 30, 2009 are as follows:


	Level 3
	Other
	Three Months Ended			Nine Months Ended
	September 30, 2009			September 30, 2009

	(in millions)
Beginning balance	$	34		$	35
Total gains (losses) — realized/unrealized:
Included in earnings		—			(3	)
Included in OCI		(3	)		(1	)

Ending balance at September 30, 2009	$	31		$	31

158

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Unrealized losses of $3 million were included in earnings during the nine-month period relating to assets still held at September 30, 2009 and are recorded in “depreciation and amortization.”

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months and nine months ended September 30, 2009, the increase in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $47 million and $68 million, respectively, for Alabama Power, $63 million and $90 million, respectively, for Georgia Power, and $110 million and $158 million, respectively, for Southern Company.

As of September 30, 2009, 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	$	18,322	$	19,184
Alabama Power		$6,157		$6,506
Georgia Power		$7,475		$7,754
Gulf Power		$1,119		$1,157
Mississippi Power		$491		$511
Southern Power		$1,297		$1,417

The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

(D)		STOCKHOLDERS’ EQUITY

		Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to exercised options and outstanding options under the stock option plan. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for further information on the stock option plan. The effect of the stock options was determined using the treasury stock method. Shares used to compute diluted earnings per share are as follows (in thousands):


	Three Months		Three Months		Nine Months		Nine Months
	Ended		Ended		Ended		Ended
	September 30, 2009		September 30, 2008		September 30, 2009		September 30, 2008

As reported shares		798,418		772,622		789,675		769,298
Effect of options		1,760		4,281		1,584		4,153

Diluted shares		800,178		776,903		791,259		773,451

The reduction in the effect of options for the three months and nine months ended September 30, 2009 compared to the corresponding periods in 2008 is primarily due to the anti-dilutive nature of certain stock options outstanding that have exercise prices that exceed the average stock price of Southern Company shares in the three months and nine months ended September 30, 2009. For the three months and nine months ended September 30, 2009, there were 25.5 million and 37.7 million stock options, respectively, that were not included in the diluted earnings per share calculation because they were anti-dilutive. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options for the three months and nine months ended September 30, 2009 would have increased by 2.2 million and 3.3 million shares, respectively.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Changes in Stockholders’ Equity

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


				Preferred and
	Common			Preference		Total
	Stockholders’			Stock of		Stockholders’
	Equity			Subsidiaries		Equity

	(in millions)
Balance at December 31, 2008	$	13,276		$	707	$	13,983
Net income after dividends on preferred and preference stock		1,394			—		1,394
Other comprehensive income (loss)		20			—		20
Stock issued		692			—		692
Cash dividends on common stock		(1,018	)		—		(1,018	)
Other		(2	)		—		(2	)

Balance at September 30, 2009	$	14,362		$	707	$	15,069


Balance at December 31, 2007	$	12,385		$	707	$	13,092
Net income after dividends on preferred and preference stock		1,556			—		1,556
Other comprehensive income (loss)		8			—		8
Stock issued		415			—		415
Cash dividends on common stock		(954	)		—		(954	)
Other		(6	)		—		(6	)

Balance at September 30, 2008	$	13,404		$	707	$	14,111

	(E)		FINANCING

			Bank Credit Arrangements

At September 30, 2009, unused credit arrangements with banks totaled $4.7 billion, of which $99 million expires during 2009, $1.4 billion expires in 2010, $25 million expires in 2011, and $3.2 billion expires in 2012. These credit arrangements provide liquidity support to the registrants’ commercial paper borrowings and the traditional operating companies’ variable rate pollution control revenue bonds.

The following table outlines the credit arrangements by company:


					Executable
					Term-Loans				Expires
					One		Two
Company	Total		Unused		Year		Years		2009		2010		2011		2012

	(in millions)
Southern Company	$	950	$	950	$	—	$	—	$	—	$	—	$	—	$	950
Alabama Power		1,271		1,271		372		—		20		461		25		765
Georgia Power		1,715		1,703		—		40		—		595		—		1,120
Gulf Power		220		220		70		—		60		160		—		—
Mississippi Power		149		149		15		44		19		130		—		—
Southern Power		400		400		—		—		—		—		—		400
Other		55		55		55		—		—		55		—		—

Total	$	4,760	$	4,748	$	512	$	84	$	99	$	1,401	$	25	$	3,235

160

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Subsequent to September 30, 2009, Gulf Power and Mississippi Power renewed $40 million and $15 million, respectively, of credit facilities that were set to expire in 2009 and extended the maturity dates to 2010. Also subsequent to September 30, 2009, Mississippi Power increased an existing credit facility by $10 million.

			See Note 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information.

			Changes in Redeemable Preferred Stock of Subsidiaries

The following table presents year-to-date changes in redeemable preferred stock of subsidiaries for Southern Company:


	Redeemable Preferred
	Stock of Subsidiaries

	(in millions)
Balance at December 31, 2008	$	375
Issuance (Redemption) of preferred stock		—

Balance at September 30, 2009	$	375


Balance at December 31, 2007	$	498
Issuance (Redemption) of preferred stock		(125	)
Other		2

Balance at September 30, 2008	$	375

Financial Instruments

			Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate 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 the companies’ policies in areas such as counterparty exposure and risk management practices. The registrants’ 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 statement of financial position 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, 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. Southern Power also 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 registrants 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 registrants may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

161

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 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 transactions are reflected in earnings.

•

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

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

At September 30, 2009, the net volume of energy-related derivative contracts for power and natural gas positions for the registrants, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:


	Power						Gas
			Longest		Longest		Net			Longest		Longest
	Net Sold		Hedge		Non-Hedge		Purchased			Hedge		Non-Hedge
As of September 30, 2009:	MWH		Date		Date		mmBtu			Date		Date

	(in thousands)						(in millions)
Southern Company		3,643		2010		2010		154	*		2013		2010
Alabama Power		563		2009		2009		40			2012		—
Georgia Power		737		2009		2009		68			2013		—
Gulf Power		117		2009		2009		13			2013		—
Mississippi Power		117		2009		2009		26			2013		2009
Southern Power		2,109		2010		2010		7	*		2012		2010


*		Includes location basis of 2 million mmBtu.

			For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending September 30, 2010 are immaterial for all registrants.

			*Interest Rate Derivatives*

Southern Company and certain subsidiaries also enter into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

For cash flow hedges, the fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time the hedged transactions affect earnings.

162

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 30, 2009, Southern Company had a total of $1.2 billion notional amount of interest rate derivatives outstanding with net fair value losses of $12 million as follows:


				Weighted				Fair Value
				Average				Gain (Loss)
	Notional		Variable Rate	Fixed Rate			Hedge Maturity	September 30,
Registrant	Amount		Received	Paid			Date	2009
	(in millions)							(in millions)
*Cash flow hedges of existing debt*
Alabama Power	$	576	SIFMA* Index		2.69	%	February 2010	$	(6	)
Georgia Power		301	SIFMA* Index		2.22	%	December 2009		(1	)
Georgia Power		300	1-month LIBOR		2.43	%	April 2010		(4	)
*Cash flow hedges on forecasted debt*
Gulf Power		50	3-month LIBOR		3.97	%	April 2020		(1	)

Total	$	1,227						$	(12	)


*		Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA)

For the nine months ended September 30, 2009, Georgia Power had realized net losses of $16 million (all of which were realized in the first quarter 2009) upon termination of certain interest rate derivatives at the same time it issued debt. The effective portion of these losses has been deferred in OCI and is being amortized to interest expense over the life of the original interest rate derivative, reflecting the period in which the forecasted hedged transaction affects earnings.

The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending September 30, 2010, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.


	Estimated Gain (Loss) to
	be Reclassified for the			Total Deferred
	12 Months Ending			Gains (Losses)
Registrant	September 30, 2010			Amortized Through
	(in millions)
Southern Company	$	(32	)		2037
Alabama Power		(6	)		2035
Georgia Power		(15	)		2037
Gulf Power		(1	)		2020
Southern Power		(10	)		2016

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Derivative Financial Statement Presentation and Amounts

At September 30, 2009, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:


Asset Derivatives at September 30, 2009
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives
Other current assets	$	5	$	2	$	2	$	1	$	—
Other deferred charges and assets		6		2		3		—		1

Total derivatives designated as hedging instruments for regulatory purposes	$	11	$	4	$	5	$	1	$	1		N/A


Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives
Other deferred charges and assets	$	1	$	—	$	—	$	—	$	—	$	1


Derivatives not designated as hedging instruments
Energy-related derivatives
Other current assets*	$	7	$	—	$	—	$	—	$	1	$	—
Assets from risk management activities		—		—		—		—		—		6
Other deferred charges and assets		1		—		—		—		—		1

Total derivatives not designated as hedging instruments	$	8	$	—	$	—	$	—	$	1	$	7


Total asset derivatives	$	20	$	4	$	5	$	1	$	2	$	8


*		Southern Company includes Assets from risk management activities in Other current assets.


Liability Derivatives at September 30, 2009
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives
Liabilities from risk management activities	$	130	$	42	$	54	$	13	$	21
Other deferred credits and liabilities		48		9		17		3		19

Total derivatives designated as hedging instruments for regulatory purposes	$	178	$	51	$	71	$	16	$	40		N/A


Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives
Liabilities from risk management activities	$	2	$	—	$	—	$	—	$	—	$	2
Interest rate derivatives
Liabilities from risk management activities		12		6		5		1		—		—

Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	14	$	6	$	5	$	1	$	—	$	2

164

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


Liability Derivatives at September 30, 2009
	Fair Value
	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Derivative Category and Balance Sheet Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives not designated as hedging instruments
Energy-related derivatives
Liabilities from risk management activities	$	3	$	—	$	—	$	—	$	1	$	2

Total liability derivatives	$	195	$	57	$	76	$	17	$	41	$	4

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

At September 30, 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:


Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet	Southern			Alabama			Georgia			Gulf			Mississippi
Location	Company			Power			Power			Power			Power
	(in millions)
Energy-related derivatives
Other regulatory assets, current	$	(130	)	$	(42	)	$	(54	)	$	(13	)	$	(21	)
Other regulatory assets, deferred		(48	)		(9	)		(17	)		(3	)		(19	)
Other regulatory liabilities, current		5			2			2			1			—
Other regulatory liabilities, deferred		6			2			3			—			1

Total energy-related derivative gains (losses)	$	(167	)	$	(47	)	$	(66	)	$	(15	)	$	(39	)

For the three months ended September 30, 2009 and September 30, 2008, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:


	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI
Derivatives in Cash Flow	on Derivative						into Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2009			2008				2009			2008
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(1	)	$	32		Fuel	$	—		$	—
Interest rate derivatives		(3	)		(2	)	Interest expense		(12	)		(4	)

Total	$	(4	)	$	30			$	(12	)	$	(4	)

Alabama Power
Energy-related derivatives	$	—		$	—		Fuel	$	—		$	—
Interest rate derivatives		(1	)		—		Interest expense		(3	)		—

Total	$	(1	)	$	—			$	(3	)	$	—

Georgia Power
Interest rate derivatives total	$	(1	)	$	(2	)	Interest expense	$	(6	)	$	(1	)

Gulf Power
Interest rate derivatives total	$	(1	)	$	—		Interest expense	$	—		$	(1	)

Mississippi Power
Energy-related derivatives total	$	—		$	4		Fuel	$	—		$	—

Southern Power
Energy-related derivatives	$	(1	)	$	29		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(2	)		(2	)

Total	$	(1	)	$	29			$	(2	)	$	(2	)

165

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the nine months ended September 30, 2009 and September 30, 2008, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:


	Gain (Loss)
	Recognized in OCI
Derivatives in Cash Flow	on Derivative						Gain (Loss) Reclassified from Accumulated OCI
Hedging Relationships	(Effective Portion)						into Income (Effective Portion)
							Statements of Income Location	Amount
	2009			2008				2009			2008
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	—		$	8		Fuel	$	—		$	—
Interest rate derivatives		(6	)		(7	)	Interest expense		(34	)		(15	)

Total	$	(6	)	$	1			$	(34	)	$	(15	)

Alabama Power
Energy-related derivatives	$	—		$	(1	)	Fuel	$	—		$	—
Interest rate derivatives		(5	)		(2	)	Interest expense		(9	)		(2	)

Total	$	(5	)	$	(3	)		$	(9	)	$	(2	)

Georgia Power
Interest rate derivatives total	$	—		$	(2	)	Interest expense	$	(17	)	$	(3	)

Gulf Power
Interest rate derivatives total	$	(1	)	$	(3	)	Interest expense	$	(1	)	$	(1	)

Mississippi Power
Energy-related derivatives total	$	—		$	—		Fuel	$	—		$	—

Southern Power
Energy-related derivatives	$	—		$	9		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(7	)		(9	)

Total	$	—		$	9			$	(7	)	$	(9	)

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

For the three months ended September 30, 2009 and September 30, 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:


Derivatives not Designated
as Hedging Instruments	Unrealized Gain (Loss) Recognized in Income
	Statements of Income Location	Amount
		2009			2008
		(in millions)
Southern Company
Energy-related derivatives	Wholesale revenues	$	4		$	44
	Fuel		(1	)		(30	)
	Purchased power		(1	)		(6	)
	Other income (expense), net		—			(1	)

Total		$	2		$	7

Mississippi Power
Energy-related derivatives	Other income (expense), net	$	—		$	(1	)

Southern Power
Energy-related derivatives	Wholesale revenues	$	4		$	44
	Fuel		(1	)		(30	)
	Purchased power		(1	)		(6	)

Total		$	2		$	8

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the nine months ended September 30, 2009 and September 30, 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:


Derivatives not Designated
as Hedging Instruments	Unrealized Gain (Loss) Recognized in Income
	Statements of Income Location	Amount
		2009			2008
		(in millions)
Southern Company
Energy-related derivatives	Wholesale revenues	$	9		$	10
	Fuel		(4	)		(2	)
	Purchased power		(4	)		(9	)
	Other income (expense), net		—			1

Total		$	1		$	—

Mississippi Power
Energy-related derivatives	Other income (expense), net	$	—		$	1

Southern Power
Energy-related derivatives	Wholesale revenues	$	9		$	10
	Fuel		(4	)		(2	)
	Purchased power		(4	)		(9	)

Total		$	1		$	(1	)

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2009, the fair value of derivative liabilities with contingent features, by registrant, is as follows:


	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power
	(in millions)
Derivative liabilities	$	51	$	12	$	16	$	4	$	4	$	15

At September 30, 2009, the registrants had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $51 million for each registrant.

Currently, each of the registrants has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade.

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(F)

RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2009. 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 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. Components of the pension plans’ and postretirement plans’ net periodic costs for the three-month and nine-month periods ended September 30, 2009 and 2008 are as follows (in millions):


	Southern			Alabama			Georgia			Gulf			Mississippi
PENSION PLANS	Company			Power			Power			Power			Power
Three Months Ended September 30, 2009
Service cost	$	36		$	8		$	12		$	2		$	2
Interest cost		96			24			37			4			4
Expected return on plan assets		(135	)		(41	)		(54	)		(6	)		(6	)
Net amortization		11			3			4			1			1

Net cost (income)	$	8		$	(6	)	$	(1	)	$	1		$	1


Nine Months Ended September 30, 2009
Service cost	$	109		$	25		$	36		$	5		$	5
Interest cost		290			72			110			13			13
Expected return on plan assets		(406	)		(123	)		(162	)		(18	)		(16	)
Net amortization		32			8			12			1			2

Net cost (income)	$	25		$	(18	)	$	(4	)	$	1		$	4


Three Months Ended September 30, 2008
Service cost	$	36		$	9		$	12		$	2		$	2
Interest cost		87			21			33			4			4
Expected return on plan assets		(131	)		(40	)		(52	)		(6	)		(6	)
Net amortization		12			4			5			—			1

Net cost (income)	$	4		$	(6	)	$	(2	)	$	—		$	1


Nine Months Ended September 30, 2008
Service cost	$	109		$	26		$	37		$	5		$	5
Interest cost		261			65			100			12			12
Expected return on plan assets		(394	)		(120	)		(158	)		(18	)		(16	)
Net amortization		35			10			13			1			2

Net cost (income)	$	11		$	(19	)	$	(8	)	$	—		$	3

168

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


	Southern			Alabama			Georgia			Gulf			Mississippi
POSTRETIREMENT PLANS	Company			Power			Power			Power			Power
Three Months Ended September 30, 2009
Service cost	$	7		$	2		$	2		$	—		$	—
Interest cost		28			7			13			1			1
Expected return on plan assets		(16	)		(6	)		(8	)		—			—
Net amortization		7			2			4			—			1

Net cost (income)	$	26		$	5		$	11		$	1		$	2


Nine Months Ended September 30, 2009
Service cost	$	20		$	5		$	7		$	1		$	1
Interest cost		85			22			38			4			4
Expected return on plan assets		(46	)		(18	)		(23	)		(1	)		(1	)
Net amortization		21			6			11			—			1

Net cost (income)	$	80		$	15		$	33		$	4		$	5


Three Months Ended September 30, 2008
Service cost	$	7		$	1		$	3		$	—		$	—
Interest cost		28			7			12			1			1
Expected return on plan assets		(15	)		(6	)		(8	)		—			—
Net amortization		8			3			4			—			—

Net cost (income)	$	28		$	5		$	11		$	1		$	1


Nine Months Ended September 30, 2008
Service cost	$	21		$	5		$	8		$	1		$	1
Interest cost		83			22			37			3			4
Expected return on plan assets		(44	)		(17	)		(23	)		(1	)		(1	)
Net amortization		23			7			12			1			—

Net cost (income)	$	83		$	17		$	34		$	4		$	4

	(G)		EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

			Effective Tax Rate

Southern Company’s effective tax rate was 36.5% for the nine months ended September 30, 2009, as compared to 34.3% for the same period in 2008. 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’s effective tax rate increased for the nine months ended September 30, 2009 primarily due to the $202 million charge recorded for the MC Asset Recovery settlement. Southern Company is currently evaluating potential recovery of the settlement payment through various means. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. The increase in Southern Company’s effective tax rate was partially offset by the early termination of an international leveraged lease investment, which is not taxable. See Note (B) herein under “Mirant Matters” and “Income Tax Matters — Leveraged Leases” for further information regarding these matters.

169

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Unrecognized Tax Benefits

Changes during 2009 for unrecognized tax benefits are as follows:


	Southern			Alabama		Georgia		Gulf		Mississippi		Southern
	Company			Power		Power		Power		Power		Power
	(in millions)
Unrecognized tax benefits as of December 31, 2008	$	146.4		$	3.0	$	137.1	$	0.3	$	1.8	$	0.5
Tax positions from current periods		39.5			1.6		32.4		0.2		1.0		0.4
Tax positions from prior periods		4.7			0.3		2.8		0.4		—		0.6
Reductions due to settlements		—			—		—		—		—		—
Reductions due to expired statute of limitations		(1.0	)		—		—		—		—		—

Balance as of September 30, 2009	$	189.6		$	4.9	$	172.3	$	0.9	$	2.8	$	1.5

The tax positions increase from the current periods relates primarily to the Georgia state tax credits and other miscellaneous uncertain tax positions. See Note (B) herein under “Income Tax Matters — Georgia State Income Tax Credits” for additional information. The tax positions increase from the prior periods relates to the production activities deduction tax position.

Impact on Southern Company’s effective tax rate, if recognized, is as follows:


					As of		As of
	Georgia		Other		September 30,		December 31,
	Power		Registrants		2009		2008		Change
	(in millions)
Tax positions impacting the effective tax rate	$	169.6	$	17.3	$	186.9	$	143.5	$	43.4
Tax positions not impacting the effective tax rate		2.7		—		2.7		2.9		(0.2	)

Balance of unrecognized tax benefits	$	172.3	$	17.3	$	189.6	$	146.4	$	43.2

The change in the tax positions impacting the effective tax rate increase relates primarily to the Georgia state tax credits and the production activities deduction.

Accrued interest for unrecognized tax benefits:


	(in millions)
Interest accrued as of December 31, 2008	$	14.8
Interest accrued year-to-date		6.4
Interest reduction due to expired statute of limitations		(1.1	)

Balance as of September 30, 2009	$	20.1

It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of Southern Company’s and Georgia Power’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The conclusion or settlement of the Georgia state tax credits litigation would substantially reduce the balances. The conclusion or settlement of federal or state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

170

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	(H)		ACQUISITIONS AND DIVESTITURES

			Nacogdoches Power LLC Acquisition

On October 8, 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 plans to construct a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction is expected to commence in late 2009 and the plant is expected to begin commercial operation in 2012. The total estimated cost of the project is expected to be between $475 million and $500 million. The output of the plant is contracted under a PPA with Austin Energy that begins in 2012 and expires in 2032.

			Southern Power’s acquisition of the interests in Nacogdoches was pursuant to a Membership Interests Purchase Agreement dated September 11, 2009 for cash consideration of approximately $50.3 million, which includes advance construction payments. The Nacogdoches acquisition is in accordance with Southern Power’s overall growth strategy. Post-closing working capital adjustments have not been completed. The purchase price allocation and fair value determinations have not been completed and thus the information related to the fair value of each major class of consideration and goodwill, if any, is not provided herein. There are no contingent consideration arrangements and no significant assets or liabilities arising from contingencies.

			West Georgia Generating Company, LLC Acquisition and DeSoto County Generating Company, LLC Divestiture

On October 21, 2009, Southern Power entered into an agreement (the Agreement) to acquire all of the outstanding membership interests of West Georgia Generating Company, LLC (West Georgia) from Broadway Gen Funding, LLC (Broadway), an affiliate of LS Power. West Georgia owns a dual-fueled generating plant near Thomaston, Georgia with installed capacity of approximately 600 MWs. The plant consists of four combustion turbine natural gas generating units with oil back-up. The output from two units is contracted under PPAs with MEAG Power and the Georgia Energy Cooperative (GEC). The MEAG Power agreement began in 2009 and expires in 2029. The GEC agreement begins in 2010 and expires in 2030.

The Agreement provides for the transfer of all the outstanding membership interests of DeSoto County Generating Company, LLC (DeSoto) from Southern Power to Broadway and the payment by Southern Power of approximately $140 million in cash consideration. The carrying amounts of the major classes of assets and liabilities for DeSoto are as follows:


As of September 30, 2009
	(in millions)
Total current assets	$	5.5
Total property, plant, and equipment		72.1
Total deferred charges and other assets		0.6
Total current liabilities		1.1
Total membership interests		77.1

The Agreement is subject to certain regulatory approvals, including the approval of the FERC, as well as review by the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvements Act. This potential acquisition is in accordance with Southern Power’s overall growth strategy. The ultimate outcome of this matter cannot now be determined.

171

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(I)

SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Southern Power’s revenues from sales to the traditional operating companies were $148 million and $421 million for the three months and nine months ended September 30, 2009, respectively, and $217 million and $494 million for the three months and nine months ended September 30, 2008, 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, energy-related services, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:


	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
					(in millions)
Three Months Ended
September 30, 2009:
Operating revenues	$	4,542	$	283	$	(168	)	$	4,657	$	43		$	(18	)	$	4,682
Segment net income (loss)*		726		67		—			793		(2	)		(1	)		790
Nine Months Ended
September 30, 2009:
Operating revenues	$	11,880	$	745	$	(470	)	$	12,155	$	130		$	(52	)	$	12,233
Segment net income (loss)*		1,449		126		—			1,575		(182	)		1			1,394
Total assets at September 30, 2009	$	47,401	$	2,918	$	(185	)	$	50,134	$	1,061		$	(671	)	$	50,524


Three Months Ended
September 30, 2008:
Operating revenues	$	5,156	$	516	$	(276	)	$	5,396	$	46		$	(15	)	$	5,427
Segment net income (loss)*		727		60		—			787		(7	)		—			780
Nine Months Ended
September 30, 2008:
Operating revenues	$	12,849	$	1,048	$	(669	)	$	13,228	$	141		$	(44	)	$	13,325
Segment net income (loss)*		1,520		124		—			1,644		(88	)		—			1,556
Total assets at December 31, 2008	$	44,794	$	2,813	$	(139	)	$	47,468	$	1,407		$	(528	)	$	48,347

	*		After dividends on preferred and preference stock of subsidiaries.

	Products and Services


	Electric Utilities’ Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2009	$	3,997	$	519	$	141	$	4,657
Three Months Ended September 30, 2008		4,479		775		142		5,396

Nine Months Ended September 30, 2009	$	10,355	$	1,408	$	392	$	12,155
Nine Months Ended September 30, 2008		10,934		1,880		414		13,228

172


Item 6.		Exhibits.


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

Southern Company

(a)1	-	Fifth Supplemental Indenture to the Senior Note Indenture dated as of October 22, 2009, providing for the issuance of the Series 2009B Floating Rate Senior Notes due October 21, 2011. (Designated in Form 8-K dated October 19, 2009, File No. 1-3526, as Exhibit 4.2.)

(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, 2008, File No. 1-3526 as Exhibit 24(a).)

Alabama Power

(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-Q for the quarter ended June 30, 2009, File No. 1-3164 as Exhibit 24(b)1.)

Georgia Power

(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 1-6468 as Exhibit 24(c).)

(c)2	-	Power of Attorney for Ronnie R. Labrato. (Designated in the Form 10-Q for the quarter ended March 31, 2009, File No. 1-6468 as Exhibit 24(c)2.)

Gulf Power

(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 0-2429 as Exhibit 24(d).)

Mississippi Power

(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 001-11229 as Exhibit 24(e).)

Southern Power

(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 333-98553 as Exhibit 24(f).)

174


(31) Section 302 Certifications

Southern Company

(a)1	-	Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(a)2	-	Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Alabama Power

(b)1	-	Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(b)2	-	Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Georgia Power

(c)1	-	Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(c)2	-	Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Gulf Power

(d)1	-	Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(d)2	-	Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Mississippi Power

(e)1	-	Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(e)2	-	Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Southern Power

(f)1	-	Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(f)2	-	Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

175


(32) Section 906 Certifications

Southern Company

(a)	-	Certificate of Southern Company’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Alabama Power

(b)	-	Certificate of Alabama Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Georgia Power

(c)	-	Certificate of Georgia Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Gulf Power

(d)	-	Certificate of Gulf Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Mississippi Power

(e)	-	Certificate of Mississippi Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Southern Power

(f)	-	Certificate of Southern Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

(101) XBRL-Related Documents

Southern Company

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

176


		Page
		Number
PART II — OTHER INFORMATION

Item 1.	Legal Proceedings		173
Item 1A.	Risk Factors		173
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Submission of Matters to a Vote of Security Holders	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits		174
	Signatures		177


		Page
		Number
DEFINITIONS			5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			7

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	The Southern Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		9
	Condensed Consolidated Statements of Cash Flows		10
	Condensed Consolidated Balance Sheets		11
	Condensed Consolidated Statements of Comprehensive Income		13
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
	Alabama Power Company
	Condensed Statements of Income		37
	Condensed Statements of Comprehensive Income		37
	Condensed Statements of Cash Flows		38
	Condensed Balance Sheets		39
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
	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		81
	Condensed Statements of Comprehensive Income		81
	Condensed Statements of Cash Flows		82
	Condensed Balance Sheets		83
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		85
	Mississippi Power Company
	Condensed Statements of Income		102
	Condensed Statements of Comprehensive Income		102
	Condensed Statements of Cash Flows		103
	Condensed Balance Sheets		104
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		106
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		125
	Condensed Consolidated Statements of Comprehensive Income		125
	Condensed Consolidated Statements of Cash Flows		126
	Condensed Consolidated Balance Sheets		127
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		129
	Notes to the Condensed Financial Statements		142
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		35
Item 4.	Controls and Procedures		35
Item 4T.	Controls and Procedures		35


Term		Meaning
SouthernLINC Wireless		Southern Communications Services, Inc.
Southern Nuclear		Southern Nuclear Operating Company, Inc.
Southern Power		Southern Power Company
Standard and Poor’s		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


Registrant		Applicable Notes

Southern Company		A, B, C, D, E, F, G, I

Alabama Power		A, B, C, E, F, G

Georgia Power		A, B, C, E, F, G

Gulf Power		A, B, C, E, F, G

Mississippi Power		A, B, C, E, F, G

Southern Power		A, B, C, E, G, H


				THE SOUTHERN COMPANY

		By		David M. Ratcliffe
				Chairman, President, and Chief Executive Officer
				(Principal Executive Officer)

		By		W. Paul Bowers
				Executive Vice President and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				ALABAMA POWER COMPANY

		By		Charles D. McCrary
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Art P. Beattie
				Executive Vice President, Chief Financial Officer, and Treasurer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				GEORGIA POWER COMPANY

		By		Michael D. Garrett
				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/ W. Paul Bowers (W. Paul Bowers, Attorney-in-fact)


				GULF POWER COMPANY

		By		Susan N. Story
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Philip C. Raymond
				Vice President and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ W. Paul Bowers

				(W. Paul Bowers, Attorney-in-fact)


				MISSISSIPPI POWER COMPANY

		By		Anthony J. Topazi
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Frances Turnage
				Vice President, Treasurer, and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ W. Paul Bowers (W. Paul Bowers, Attorney-in-fact)


				SOUTHERN POWER COMPANY

		By		Ronnie L. Bates
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Michael W. Southern
				Senior Vice President, Treasurer, and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ Laura I. Patterson (Laura I. Patterson, Attorney-in-fact)