Georgia Power (GPJA) 10-Q 2010 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2010

OR

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

For the transition period from                    to                    

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

     Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or15(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. Yesþ Noo

     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). Yesþ Noo (Response applicable only to The Southern Company at this time.)

     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.) Yeso Noþ(Response applicable to all registrants.)

	Description of	Shares Outstanding
Registrant	Common Stock	at September 30, 2010
The Southern Company	Par Value $5 Per Share		838,671,173
Alabama Power Company	Par Value $40 Per Share		30,537,500
Georgia Power Company	Without Par Value		9,261,500
Gulf Power Company	Without Par Value		3,642,717
Mississippi Power Company	Without Par Value		1,121,000
Southern Power Company	Par Value $0.01 Per Share		1,000

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

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2010

		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		40
	Condensed Statements of Comprehensive Income		40
	Condensed Statements of Cash Flows		41
	Condensed Balance Sheets		42
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		44
	Georgia Power Company
	Condensed Statements of Income		62
	Condensed Statements of Comprehensive Income		62
	Condensed Statements of Cash Flows		63
	Condensed Balance Sheets		64
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		66
	Gulf Power Company
	Condensed Statements of Income		86
	Condensed Statements of Comprehensive Income		86
	Condensed Statements of Cash Flows		87
	Condensed Balance Sheets		88
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		90
	Mississippi Power Company
	Condensed Statements of Income		108
	Condensed Statements of Comprehensive Income		108
	Condensed Statements of Cash Flows		109
	Condensed Balance Sheets		110
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		112
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		134
	Condensed Consolidated Statements of Comprehensive Income		134
	Condensed Consolidated Statements of Cash Flows		135
	Condensed Consolidated Balance Sheets		136
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		138
	Notes to the Condensed Financial Statements		151
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		37
Item 4.	Controls and Procedures		37
Item 4T.	Controls and Procedures		37

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2010

		Page
		Number
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		182
Item 1A.	Risk Factors		182
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits		183
	Signatures		188

4

DEFINITIONS

Term	Meaning
2007 Retail Rate Plan	Georgia Power’s retail rate plan for the years 2008 through 2010
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
Clean Air Act	Clean Air Act Amendments of 1990
DOE	U.S. Department of Energy
Duke Energy	Duke Energy Corporation
ECO Plan	Mississippi Power’s Environmental Compliance Overview Plan
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
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, 2009
GAAP	Generally Accepted Accounting Principles
Georgia Power	Georgia Power Company
Georgia PSC Staff	Georgia Public Service Commission Public Interest Advocacy Staff
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
NDR	Alabama Power’s natural disaster reserve
NRC	Nuclear Regulatory Commission
NSR	New Source Review
OCI	Other Comprehensive Income
PEP	Mississippi Power’s Performance Evaluation Plan
Power Pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power Purchase Agreement
PSC	Public Service Commission
Rate CNP Environmental	Alabama Power’s certificated new plant for environmental costs
Rate ECR	Alabama Power’s energy cost recovery rate mechanism
Rate NDR	Alabama Power’s natural disaster cost recovery rate mechanism
Rate RSE	Alabama Power’s rate stabilization and equalization plan
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
SCS	Southern Company Services, Inc.
SEC	Securities and Exchange Commission

5

DEFINITIONS
(continued)

Term	Meaning
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, and other subsidiaries
SouthernLINC Wireless	Southern Communications Services, Inc.
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Westinghouse	Westinghouse Electric Company LLC
wholesale revenues	revenues generated from sales for resale

6

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the wholesale business, retail sales, customer growth, economic recovery, fuel cost recovery and other rate actions, environmental regulations and expenditures, future earnings, dividend payout ratios, access to sources of capital, financing activities, start and completion of construction projects, plans and estimated costs for new generation resources, impact of the American Recovery and Reinvestment Act of 2009, impact of recent healthcare legislation, impact of the Small Business Jobs and Credit Act of 2010, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory 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, coal combustion byproducts, and emissions of sulfur, nitrogen, carbon, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, financial reform legislation, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

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

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

• variations in demand for electricity, including those relating to weather, the general economy and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;

• available sources and costs of fuels;

• effects of inflation;

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

• investment performance of Southern Company’s employee benefit plans and nuclear decommissioning trusts;

• advances in technology;

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

• regulatory approvals and actions related to the potential Plant Vogtle expansion, including Georgia PSC and NRC approvals and potential DOE loan guarantees;

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

• the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

• internal restructuring or other restructuring options that may be pursued;

• potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

• the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

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

• 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 influenzas, or other similar occurrences;

• the direct or indirect effects on Southern Company’s business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

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

• other factors discussed elsewhere herein and in other reports (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.

7

THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES

8

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	4,572,617		$	3,997,659		$	11,603,017		$	10,355,330
Wholesale revenues		565,932			519,122			1,580,748			1,408,286
Other electric revenues		160,960			139,869			438,547			391,070
Other revenues		20,403			24,832			62,336			78,267
Total operating revenues		5,319,912			4,681,482			13,684,648			12,232,953
Operating Expenses:
Fuel		1,969,683			1,733,527			5,243,826			4,588,932
Purchased power		209,287			166,791			464,226			407,623
Other operations and maintenance		1,020,370			820,889			2,846,785			2,523,184
MC Asset Recovery litigation settlement		—			—			—			202,000
Depreciation and amortization		426,797			332,117			1,136,730			1,099,216
Taxes other than income taxes		235,260			212,882			661,521			620,851
Total operating expenses		3,861,397			3,266,206			10,353,088			9,441,806
Operating Income		1,458,515			1,415,276			3,331,560			2,791,147
Other Income and (Expense):
Allowance for equity funds used during construction		45,162			51,061			139,853			141,173
Interest income		5,463			6,013			15,057			17,791
Leveraged lease income (losses)		5,839			6,578			12,639			24,695
Gain on disposition of lease termination		—			—			—			26,300
Loss on extinguishment of debt		—			—			—			(17,184	)
Interest expense, net of amounts capitalized		(225,138	)		(226,345	)		(666,289	)		(684,902	)
Other income (expense), net		(14,481	)		(10,466	)		(37,185	)		(27,293	)
Total other income and (expense)		(183,155	)		(173,159	)		(535,925	)		(519,420	)
Earnings Before Income Taxes		1,275,360			1,242,117			2,795,635			2,271,727
Income taxes		441,927			435,947			925,110			828,833
Consolidated Net Income		833,433			806,170			1,870,525			1,442,894
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	$	817,238		$	789,975		$	1,821,940		$	1,394,309
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.98		$	0.99		$	2.20		$	1.77
Diluted EPS	$	0.97		$	0.99		$	2.19		$	1.76
Average number of shares of common stock outstanding (in thousands)
Basic		835,953			798,418			828,947			789,675
Diluted		841,835			800,178			833,220			791,259
Cash dividends paid per share of common stock	$	0.4550		$	0.4375		$	1.3475		$	1.2950

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

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2010			2009
	(in thousands)
Operating Activities:
Consolidated net income	$	1,870,525		$	1,442,894
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		1,376,511			1,310,854
Deferred income taxes		572,862			(14,565	)
Deferred revenues		(76,976	)		(40,781	)
Allowance for equity funds used during construction		(139,853	)		(141,173	)
Leveraged lease income (losses)		(12,639	)		(24,695	)
Gain on disposition of lease termination		—			(26,300	)
Loss on extinguishment of debt		—			17,184
Pension, postretirement, and other employee benefits		51,792			42,775
Stock based compensation expense		28,307			20,850
Hedge settlements		1,530			(16,167	)
Generation construction screening costs		(50,554	)		(21,955	)
Other, net		10,126			32,321
Changes in certain current assets and liabilities —
-Receivables		(319,384	)		319,286
-Fossil fuel stock		220,017			(361,520	)
-Materials and supplies		(10,880	)		(40,811	)
-Other current assets		(48,186	)		(50,977	)
-Accounts payable		(82,318	)		(210,459	)
-Accrued taxes		118,131			238,988
-Accrued compensation		93,323			(273,349	)
-Other current liabilities		(75,733	)		157,384
Net cash provided from operating activities		3,526,601			2,359,784
Investing Activities:
Property additions		(2,893,812	)		(3,179,009	)
Investment in restricted cash from pollution control revenue bonds		(12	)		(49,528	)
Distribution of restricted cash from pollution control revenue bonds		24,811			90,088
Nuclear decommissioning trust fund purchases		(695,855	)		(1,066,688	)
Nuclear decommissioning trust fund sales		671,600			1,019,401
Proceeds from property sales		6,607			339,911
Cost of removal, net of salvage		(83,930	)		(85,022	)
Change in construction payables		(83,678	)		110,265
Other investing activities		48,285			(35,766	)
Net cash used for investing activities		(3,005,984	)		(2,856,348	)
Financing Activities:
Increase (decrease) in notes payable, net		(289,202	)		118,124
Proceeds —
Long-term debt issuances		2,796,000			2,216,010
Common stock issuances		610,465			668,529
Redemptions —
Long-term debt		(1,871,485	)		(1,229,484	)
Payment of common stock dividends		(1,113,948	)		(1,018,928	)
Payment of dividends on preferred and preference stock of subsidiaries		(48,921	)		(48,675	)
Other financing activities		(34,513	)		(18,732	)
Net cash provided from financing activities		48,396			686,844
Net Change in Cash and Cash Equivalents		569,013			190,280
Cash and Cash Equivalents at Beginning of Period		689,722			416,581
Cash and Cash Equivalents at End of Period	$	1,258,735		$	606,861
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $61,165 and $59,849 capitalized for 2010 and 2009, respectively)	$	589,129		$	589,919
Income taxes (net of refunds)	$	277,716		$	644,541

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

10

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	1,258,735		$	689,722
Restricted cash and cash equivalents		18,336			43,135
Receivables —
Customer accounts receivable		1,435,968			953,222
Unbilled revenues		443,838			394,492
Under recovered regulatory clause revenues		226,820			333,459
Other accounts and notes receivable		261,104			374,670
Accumulated provision for uncollectible accounts		(29,741	)		(24,568	)
Fossil fuel stock, at average cost		1,222,690			1,446,984
Materials and supplies, at average cost		808,446			793,847
Vacation pay		144,607			145,049
Prepaid expenses		529,823			508,338
Other regulatory assets, current		222,531			166,549
Other current assets		66,295			48,558
Total current assets		6,609,452			5,873,457
Property, Plant, and Equipment:
In service		56,029,332			53,587,853
Less accumulated depreciation		19,947,881			19,121,271
Plant in service, net of depreciation		36,081,451			34,466,582
Nuclear fuel, at amortized cost		660,856			593,119
Construction work in progress		4,457,402			4,170,596
Total property, plant, and equipment		41,199,709			39,230,297
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,142,566			1,070,117
Leveraged leases		620,674			610,252
Miscellaneous property and investments		279,015			282,974
Total other property and investments		2,042,255			1,963,343
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,182,050			1,047,452
Unamortized debt issuance expense		192,296			208,346
Unamortized loss on reacquired debt		265,867			254,936
Deferred under recovered regulatory clause revenues		291,736			373,245
Other regulatory assets, deferred		2,652,520			2,701,910
Other deferred charges and assets		458,895			392,880
Total deferred charges and other assets		5,043,364			4,978,769
Total Assets	$	54,894,780		$	52,045,866

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

11

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

	At September 30,			At December 31,
Liabilities and Stockholders’ Equity	2010			2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,983,593		$	1,112,705
Notes payable		348,399			639,199
Accounts payable		1,160,993			1,329,448
Customer deposits		333,876			330,582
Accrued taxes —
Accrued income taxes		77,995			13,005
Unrecognized tax benefits		177,969			165,645
Other accrued taxes		459,839			398,384
Accrued interest		238,944			218,188
Accrued vacation pay		182,454			183,911
Accrued compensation		351,859			247,950
Liabilities from risk management activities		175,938			124,648
Other regulatory liabilities, current		190,760			528,147
Other current liabilities		311,793			292,016
Total current liabilities		5,994,412			5,583,828
Long-term Debt		18,198,225			18,131,244
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		7,069,518			6,454,822
Deferred credits related to income taxes		238,734			248,232
Accumulated deferred investment tax credits		472,174			447,650
Employee benefit obligations		2,336,393			2,304,344
Asset retirement obligations		1,247,760			1,201,343
Other cost of removal obligations		1,202,491			1,091,425
Other regulatory liabilities, deferred		295,545			277,932
Other deferred credits and liabilities		502,756			345,888
Total deferred credits and other liabilities		13,365,371			12,371,636
Total Liabilities		37,558,008			36,086,708
Redeemable Preferred Stock of Subsidiaries		374,496			374,496
Stockholders’ Equity:
Common Stockholders’ Equity:
Common stock, par value $5 per share —
Authorized — September 30, 2010: 1.5 billion shares
— December 31, 2009: 1.0 billion shares
Issued — September 30, 2010: 839,145,736 Shares
— December 31, 2009: 820,151,801 Shares
Treasury — September 30, 2010: 474,563 Shares
— December 31, 2009: 505,116 Shares
Par value		4,195,666			4,100,742
Paid-in capital		3,550,130			2,994,245
Treasury, at cost		(13,962	)		(14,797	)
Retained earnings		8,594,861			7,884,922
Accumulated other comprehensive loss		(71,747	)		(87,778	)
Total Common Stockholders’ Equity		16,254,948			14,877,334
Preferred and Preference Stock of Subsidiaries		707,328			707,328
Total Stockholders’ Equity		16,962,276			15,584,662
Total Liabilities and Stockholders’ Equity	$	54,894,780		$	52,045,866

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

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Consolidated Net Income	$	833,433		$	806,170		$	1,870,525		$	1,442,894
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $1,025, $(1,356), $544, and $(2,338), respectively		1,595			(2,151	)		814			(3,815	)
Reclassification adjustment for amounts included in net income, net of tax of $2,438, $4,610, $9,114, and $13,073, respectively		3,839			7,339			14,413			20,807
Marketable securities:
Change in fair value, net of tax of $(2,007), $(1,056), $(391), and $239, respectively		(3,086	)		(1,359	)		(290	)		2,310
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $230, $222, $690, and $665, respectively		365			350			1,094			1,049
Total other comprehensive income (loss)		2,713			4,179			16,031			20,351
Dividends on preferred and preference stock of subsidiaries		(16,195	)		(16,195	)		(48,585	)		(48,585	)
Comprehensive Income	$	819,951		$	794,154		$	1,837,971		$	1,414,660

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009

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, telecommunications, and renewable energy projects. For additional information on these businesses, see BUSINESS — The Southern Company System — “Traditional Operating Companies,” “Southern Power,” and “Other Businesses” in Item 1 of the Form 10-K.

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

RESULTS OF OPERATIONS

Net Income

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$27.2	3.5	$427.6	30.7

Southern Company’s third quarter 2010 net income after dividends on preferred and preference stock of subsidiaries was $817.2 million ($0.98 per share) compared to $790.0 million ($0.99 per share) for third quarter 2009. The increase for the third quarter 2010 when compared to the corresponding period in 2009 was primarily the result of increases in revenues due to warmer weather, revenues associated with increases in rates under Alabama Power’s Rate RSE and Rate CNP Environmental that took effect in January 2010, and increases in sales primarily in the industrial sector. The increase for the third quarter 2010 was partially offset by increases in operations and maintenance expenses, which includes an additional NDR accrual at Alabama Power, reduced amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects.

Southern Company’s year-to-date 2010 net income after dividends on preferred and preference stock of subsidiaries was $1.82 billion ($2.20 per share) compared to $1.39 billion ($1.77 per share) for year-to-date 2009. The increase for year-to-date 2010 when compared to the corresponding period in 2009 was primarily the result of a litigation settlement agreement with MC Asset Recovery, LLC (MC Asset Recovery) in the first quarter 2009, increases in revenues due to warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010, the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC, revenues associated with increases in rates under Alabama Power’s Rate RSE and Rate CNP Environmental that took effect in January 2010, and increases in sales primarily in the industrial sector. The increase for year-to-date 2010 was partially offset by increases in operations and maintenance expenses, which includes an additional NDR accrual at Alabama Power, a gain in 2009 on the early termination of two international leveraged lease investments, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects.

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

Retail Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$574.9	14.4	$1,247.7	12.0

In the third quarter 2010, retail revenues were $4.57 billion compared to $4.00 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $11.60 billion compared to $10.36 billion for the corresponding period in 2009.

Details of the change to retail revenues are as follows:

	Third Quarter					Year-to-Date
	2010					2010
	(in millions)		(% change)			(in millions)		(% change)
Retail – prior year	$	3,997.7				$	10,355.3
Estimated change in —
Rates and pricing		162.1		4.1			296.7		2.9
Sales growth (decline)		8.0		0.2			50.4		0.5
Weather		197.3		4.9			377.1		3.6
Fuel and other cost recovery		207.5		5.2			523.5		5.0
Retail – current year	$	4,572.6		14.4	%	$	11,603.0		12.0	%

Revenues associated with changes in rates and pricing increased in the third quarter and for year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to Rate RSE and Rate CNP Environmental increases at Alabama Power, higher contributions from market-driven rates for sales to industrial customers at Georgia Power, recovery of environmental compliance costs at Gulf Power, and increased recognition of environmental compliance cost recovery revenues at Georgia Power in accordance with the 2007 Retail Rate Plan.

Revenues attributable to changes in sales increased in the third quarter and for year-to-date 2010 when compared to the corresponding periods in 2009 due to increases in weather-adjusted retail KWH energy sales of 1.4% and 2.5%, respectively. For the third quarter 2010, weather-adjusted residential KWH energy sales increased 0.1%, weather-adjusted commercial KWH energy sales decreased 0.8%, and weather-adjusted industrial KWH energy sales increased 5.7%. For year-to-date 2010, weather-adjusted residential KWH energy sales increased 0.9%, weather-adjusted commercial KWH energy sales decreased 0.7%, and weather-adjusted industrial KWH energy sales increased 8.2%. Increased demand in the primary metals, chemicals, and transportation sectors were the main contributors to the increases in weather-adjusted industrial KWH energy sales for the third quarter and year-to-date 2010.

Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.

Fuel and other cost recovery revenues increased $207.5 million in the third quarter 2010 and $523.5 million for year-to-date 2010 when compared to the corresponding periods in 2009. 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.

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

Wholesale Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$46.8	9.0	$172.5	12.2

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

In the third quarter 2010, wholesale revenues were $565.9 million compared to $519.1 million for the corresponding period in 2009. The increase was primarily due to higher energy and capacity revenues under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010. This increase was partially offset by the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010.

For year-to-date 2010, wholesale revenues were $1.58 billion compared to $1.41 billion for the corresponding period in 2009. This increase was primarily due to higher energy and capacity revenues under existing PPAs and new PPAs at Southern Power that began in January, June, and July 2010, as well as increased energy sales that were not covered by PPAs at Southern Power due to more favorable weather year-to-date 2010 compared to the corresponding period in 2009. This increase was partially offset by the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010.

Other Electric Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$21.1	15.1	$47.4	12.1

In the third quarter 2010, other electric revenues were $161.0 million compared to $139.9 million for the corresponding period in 2009. This increase was primarily the result of a $15.2 million increase in transmission revenues and a $3.1 million increase in co-generation revenues due to increased sales volume.

For year-to-date 2010, other electric revenues were $438.5 million compared to $391.1 million for the corresponding period in 2009. This increase was primarily the result of a $25.7 million increase in transmission revenues, a $10.7 million increase in co-generation revenues due to increased sales volume, a $4.1 million increase in rents from electric property, and a $2.3 million increase in outdoor lighting revenues.

Revenues from co-generation and other energy services are generally offset by related expenses and do not have a significant effect on net income.

Other Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(4.4)	(17.8)	$(16.0)	(20.4)

In the third quarter 2010, other revenues were $20.4 million compared to $24.8 million for the corresponding period in 2009. The decrease was primarily the result of a $4.3 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry.

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

For year-to-date 2010, other revenues were $62.3 million compared to $78.3 million for the corresponding period in 2009. The decrease was primarily the result of a $15.0 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry.

Fuel and Purchased Power Expenses

	Third Quarter 2010				Year-to-Date 2010
	vs.				vs.
	Third Quarter 2009				Year-to-Date 2009
	(change in millions)		(% change)		(change in millions)		(% change)
Fuel*		$236.2		13.6		$654.9		14.3
Purchased power		42.5		25.5		56.6		13.9
Total fuel and purchased power expenses		$278.7				$711.5

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

Fuel and purchased power expenses for the third quarter 2010 were $2.18 billion compared to $1.90 billion for the corresponding period in 2009. The increase was primarily the result of a $208.5 million increase related to total KWHs generated and purchased and a $70.2 million increase in the average cost of fuel and purchased power. The increase in total fuel and purchased power expenses resulted primarily from increased generation and higher fossil fuel prices when compared to the corresponding period in 2009.

For year-to-date 2010, fuel and purchased power expenses were $5.71 billion compared to $5.00 billion for the corresponding period in 2009. The increase was primarily the result of a $402.9 million increase related to total KWHs generated and purchased and a $308.6 million increase in the average cost of fuel and purchased power. The increase in total fuel and purchased power expenses resulted primarily from increased generation and higher fossil fuel prices when compared to the corresponding period in 2009.

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

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

Average Cost	Third Quarter 2010		Third Quarter 2009		Percent Change		Year-to-Date 2010		Year-to-Date 2009		Percent Change
	(cents per net KWH)						(cents per net KWH)
Fuel		3.55		3.42		3.8		3.55		3.39		4.7
Purchased power		8.03		8.00		0.4		7.13		6.20		15.0

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.

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

Other Operations and Maintenance Expenses

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$199.5	24.3	$323.6	12.8

In the third quarter 2010, other operations and maintenance expenses were $1.02 billion compared to $820.9 million for the corresponding period in 2009. The increase was primarily the result of a $42.2 million increase in fossil, hydro, and nuclear expenses, a $31.4 million increase in commodity and labor costs, a $79.5 million increase in transmission and distribution expenses, which includes an additional accrual of $40.0 million to the NDR at Alabama Power, a $37.2 million increase in administrative and general expenses, and a $9.2 million increase in customer service and sales expenses.

For year-to-date 2010, other operations and maintenance expenses were $2.85 billion compared to $2.52 billion for the corresponding period in 2009. The increase was primarily the result of a $112.1 million increase in fossil, hydro, and nuclear expenses, a $69.4 million increase in commodity and labor costs, a $108.2 million increase in transmission and distribution expenses, which includes an additional accrual of $40.0 million to the NDR at Alabama Power, a $30.4 million increase in administrative and general expenses, and a $3.5 million increase in customer service and sales expenses.

See FUTURE EARNINGS POTENTIAL — “State PSC Matters — Alabama Power Retail Regulatory Matters — Natural Disaster Cost Recovery” and Note (B) to the Condensed Financial Statements under “State PSC Matters — Alabama Power — Natural Disaster Cost Recovery” herein for additional information on the NDR.

MC Asset Recovery Litigation Settlement

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
—	—	$(202.0)	N/M

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 and required 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. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. In June 2009, the case was dismissed with prejudice. See Note (B) to the Condensed Financial Statements under “Mirant Matters” herein for additional information.

Depreciation and Amortization

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$94.7	28.5	$37.5	3.4

In the third quarter 2010, depreciation and amortization was $426.8 million compared to $332.1 million for the corresponding period in 2009. The increase was primarily due to the amortization of $5.0 million in the third quarter 2010 compared to $54.0 million in the third quarter 2009 of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC, as well as additional depreciation on plant in service related to environmental, transmission, and distribution projects.

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

For year-to-date 2010, depreciation and amortization was $1.14 billion compared to $1.10 billion for the corresponding period in 2009. The increase was primarily the result of additional depreciation on plant in service related to environmental, transmission, and distribution projects. The increase was partially offset by the amortization of $119.3 million in 2010 compared to $54.0 million in 2009 of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC.

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

Taxes Other Than Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$22.4	10.5	$40.6	6.6

In the third quarter 2010, taxes other than income taxes were $235.3 million compared to $212.9 million for the corresponding period in 2009. This increase was primarily due to higher municipal franchise fees at Georgia Power as a result of increased retail revenues, increases in ad valorem taxes, and increases in payroll taxes.

For year-to-date 2010, taxes other than income taxes were $661.5 million compared to $620.9 million for the corresponding period in 2009. This increase was primarily due to higher municipal franchise fees at Georgia Power as a result of increased retail revenues, increases in ad valorem taxes, and increases in payroll taxes.

Allowance for Equity Funds Used During Construction

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(5.9)	(11.6)	$(1.3)	(0.9)

In the third quarter 2010, AFUDC equity was $45.2 million compared to $51.1 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $139.9 million compared to $141.2 million for the corresponding period in 2009. The third quarter and year-to-date 2010 decreases were primarily due to the completion of environmental projects at Alabama Power and Gulf Power. These decreases were partially offset by increases in construction related to three new combined cycle units, two new nuclear generating units, and ongoing environmental and transmission projects at Georgia Power.

Leveraged Lease Income

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(0.8)	(11.2)	$(12.1)	(48.8)

In the third quarter 2010, leveraged lease income was $5.8 million compared to $6.6 million for the corresponding period in 2009. The decrease when compared to the corresponding period in 2009 was not material.

For year-to-date 2010, leveraged lease income was $12.6 million compared to $24.7 million for the corresponding period in 2009. This decrease was primarily related to the early termination of two leveraged lease investments in the second quarter 2009.

19

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

Gain on Disposition of Lease Termination

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
—	—	$(26.3)	N/M

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.

Loss on Extinguishment of Debt

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
—	—	$(17.2)	N/M

N/M — Not Meaningful

In the second quarter 2009, Southern Company terminated two international leveraged lease investments early. The proceeds from the terminations were 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

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(1.2)	(0.5)	$(18.6)	(2.7)

In the third quarter 2010, interest expense, net of amounts capitalized was $225.1 million compared to $226.3 million for the corresponding period in 2009. The decrease when compared to the corresponding period in 2009 was not material.

For year-to-date 2010, interest expense, net of amounts capitalized was $666.3 million compared to $684.9 million for the corresponding period in 2009. The decrease was primarily due to a $24.8 million decrease related to lower average interest rates on variable-rate debt, an $18.7 million decrease in other interest charges, and a $1.3 million decrease related to higher capitalized interest. Partially offsetting this decrease was a $26.2 million increase associated with $1.04 billion in additional debt outstanding at September 30, 2010 when compared to September 30, 2009.

Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$6.0	1.4	$96.3	11.6

In the third quarter 2010, income taxes were $441.9 million compared to $435.9 million for the corresponding period in 2009. This increase was primarily due to higher pre-tax earnings in the third quarter 2010, partially offset by state investment tax credits at Georgia Power, and tax benefits associated with the construction of a biomass facility at Southern Power.

For year-to-date 2010, income taxes were $925.1 million compared to $828.8 million for the corresponding period in 2009. This increase was primarily due to higher pre-tax earnings in 2010, partially offset by a decrease in uncertain tax positions at Georgia Power related to state income tax credits that remain subject to litigation, state investment tax credits at Georgia Power, and tax benefits associated with the construction of a biomass facility at Southern Power.

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

See FUTURE EARNINGS POTENTIAL — “Income Tax Matters — Georgia State Income Tax Credits” and Note (B) to the Condensed Financial Statements under “Income Tax Matters — Georgia State Income Tax Credits” and Note (G) to the Condensed Financial Statements herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company’s future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Other major factors include profitability of the competitive wholesale supply business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. 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. Changes in economic conditions impact sales for the traditional operating companies and Southern Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

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

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — New Source Review Actions” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power is alleging that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including one relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
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 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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Southern Company in Item 7 of the Form 10-K for information regarding the Industrial Boiler Maximum Achievable Control Technology regulations. On April 29, 2010, the EPA issued a proposed rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers. The EPA is required to finalize the rules by January 16, 2011. The impact of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time.

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 information regarding proposed sulfur dioxide (SO₂) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO₂, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO₂) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Southern Company’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO₂ standard could result in significant additional compliance and operational costs for units that require new source permitting.

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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern

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

states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, Florida, and Georgia, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including each of the states in Southern Company’s service territory, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

These regulations could result in significant additional compliance and operational 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.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts” of Southern Company in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.

The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on the management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational 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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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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 and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational 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. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.

State PSC Matters

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In recent years, the traditional operating companies have experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and uranium and volatile price swings in natural gas. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power of approximately $505 million at September 30, 2010. Alabama Power and Mississippi Power collected all previously under recovered fuel costs and, as of September 30, 2010, had a total over recovered fuel balance of approximately $102 million. At December 31, 2009, total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power were approximately $667 million and Alabama Power and Mississippi Power had a total over recovered fuel balance of $229 million. Fuel cost recovery 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 balances. 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 under “Retail Regulatory Matters — Alabama Power — Fuel Cost Recovery” and “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

Alabama Power Retail Regulatory Matters

Nuclear Outage Accounting Order

On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Currently, Alabama Power accrues nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period.

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

The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period.

Natural Disaster Cost Recovery

Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities, referred to as the NDR.

On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the $75 million base reserve.

In September 2010, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $118 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The additional accruals are reflected as operations and maintenance expense in the Condensed Statements of Income herein.

Georgia Power Retail Regulatory Matters

Rate Plans

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Georgia Power” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Georgia Power — Retail Rate Plans” and “— Cost of Removal” in Item 8 of the Form 10-K for additional information regarding the 2007 Retail Rate Plan.

On August 27, 2009, the Georgia PSC approved an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail return on equity (ROE). In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. From July 1, 2009 through September 30, 2010, Georgia Power had amortized $161 million of the regulatory liability. Georgia Power currently expects to amortize approximately $40 million of the regulatory liability in the fourth quarter 2010; however, the final amount is subject to the limitations described previously and cannot be determined at this time.

In accordance with the 2007 Retail Rate Plan, Georgia Power filed a base rate case with the Georgia PSC on July 1, 2010. The filing includes a requested rate increase totaling $615 million, or 8.2% of retail revenues, to be effective January 1,

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2011 based on a proposed retail ROE of 11.95%. The requested increase will be recovered through Georgia Power’s existing base rate tariffs as follows: $451 million, or 6.0%, through the traditional base rate tariffs; $115 million, or 1.5%, through the Environmental Compliance Cost Recovery (ECCR) tariff; $32 million through the Demand Side Management (DSM) tariffs; and $17 million through the Municipal Franchise Fee (MFF) tariff. The majority of the increase in retail revenues is being requested to cover the costs of environmental compliance and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. The remainder of the increase includes recovery of higher operation, maintenance, and other investment costs to meet the current and future demand for electricity.

Unlike rate plans based on traditional one-year test periods, the 2007 Retail Rate Plan was designed to operate for the three-year period ending December 31, 2010. The 2010 rate case request includes proposed enhancements to the structure of the 2007 Retail Rate Plan to fit the current economic climate, including a process of annual tariff compliance reviews that would allow it to continue to operate for multiple years (Proposed Alternate Rate Plan). The primary points of the Proposed Alternate Rate Plan include:

§	Continuation of a plus or minus 100 basis point range for ROE.
§	Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.
	The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.
§	Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.
§	Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.
§	Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.

These proposed enhancements would become effective in 2012 with revenue requirements for each tariff updated through separate compliance filings based on Georgia Power’s budget for the upcoming year. Based on Georgia Power’s 2010 budget, earnings are currently projected to be slightly below the proposed ROE band in 2012 and within the band in 2013. However, updated budgets and revenue forecasts may eliminate, increase, or decrease the need for an ACR tariff adjustment in either year. In addition, Georgia Power currently estimates the ECCR tariff would increase by $120 million in 2012 and would decrease by $12 million in 2013. The CCCR tariff would begin recovering the costs of Plant McDonough Units 4, 5, and 6 with increases of $99 million in February 2012, $77 million in June 2012, and $76 million in February 2013. The DSM tariffs would increase by $17 million in 2012 and $18 million in 2013 to reflect the terms of the stipulated agreement in Georgia Power’s 2010 DSM Certification proceeding. Amounts recovered under the MFF tariff are based on amounts recovered under all other tariffs.

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Hearings on Georgia Power’s direct testimony were held in October 2010. In direct testimony filed on October 22, 2010, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period that would result in a proposed increase of $436 million in 2011 using a 10.5% ROE. The Georgia PSC Staff recommendation would also allow additional increases of $181 million and $88 million in 2012 and 2013, respectively, to recover the costs associated with Plant McDonough Units 4, 5, and 6. These additional increases would be recovered through Georgia Power’s traditional base rate tariffs. While supporting the proposed DSM and MFF tariffs, the Georgia PSC Staff recommended against approval of the proposed ECCR, CCCR, and ACR tariffs. Georgia Power disagrees with the Georgia PSC Staff’s positions. Hearings on the Georgia PSC Staff and intervenor direct testimony will be held in November 2010. Georgia Power’s rebuttal hearings will occur in early December 2010. The Georgia PSC is scheduled to issue a final order in this matter on December 21, 2010.

The final outcome of these matters cannot now be determined.

Fuel Cost Recovery

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 under “Retail Regulatory Matters — Georgia Power — Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

On March 11, 2010, the Georgia PSC voted to approve the stipulation among Georgia Power, the Georgia PSC Staff, and three customer groups with the exception that the under recovered fuel balance be collected over 42 months. The new rates, which became effective April 1, 2010, will result in an increase of approximately $373 million to Georgia Power’s total annual fuel cost recovery billings. Georgia Power is required to file its next fuel case by March 1, 2011.

Legislation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Legislation” of Southern Company in Item 7 of the Form 10-K for additional information.

Healthcare Reform

On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Southern Company and the traditional operating companies have been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Southern Company. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Southern Company cannot be determined at this time.

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Stimulus Funding

On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding, to be matched by Southern Company, will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013.

Income Tax Matters

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power had 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. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia Department of Revenue has appealed to the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers. 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 cash flow. See Note 5 to the financial statements of Southern Company under “Unrecognized Tax Benefits” in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot now be determined.

Tax Method of Accounting for Repairs

Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $243 million. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Bonus Depreciation

On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Southern Company has estimated the cash flow reduction to tax payments for 2010 to be approximately $309 million.

Construction Projects

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including units at Southern Power, proposed new nuclear units, and a proposed IGCC facility, as well as adding environmental control equipment and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the

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

On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost Recovery tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act. The filing includes a rate increase of approximately $218 million to recover financing costs associated with the construction of two additional nuclear units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4), effective January 1, 2011.

Other Matters

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

The coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has not significantly impacted operations, but has had and may continue to have significant economic impacts on the affected areas within Southern Company’s service territory.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company prepares its consolidated financial statements in accordance with 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, Unbilled Revenues, and Pension and Other Postretirement Benefits.

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FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition remained stable at September 30, 2010. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $3.5 billion for the first nine months of 2010, an increase of $1.2 billion from the corresponding period in 2009. Significant changes in operating cash flow for the first nine months of 2010 compared to the corresponding period in 2009 include an increase in net income as previously discussed, a reduction in fossil fuel stock, and an increase in deferred income taxes primarily due to the change in the tax accounting method for repair costs as previously discussed. Net cash used for investing activities totaled $3.0 billion for the first nine months of 2010, an increase of $150 million from the corresponding period in 2009. The increase was due to proceeds received on sales of property in 2009. Net cash provided from financing activities totaled $48 million for the first nine months of 2010, a decrease of $638 million from the corresponding period in 2009, primarily due to fewer issuances of securities in the first nine months of 2010 and a reduction in notes payable outstanding. 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 2010 include an increase in cash and cash equivalents of $569 million and an increase of $2.0 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 equity of $1.4 billion.

The market price of Southern Company’s common stock at September 30, 2010 was $37.24 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $19.38 per share, representing a market-to-book ratio of 192%, compared to $33.32, $18.15, and 184%, respectively, at the end of 2009. The dividend for the third quarter 2010 was $0.4550 per share compared to $0.4375 per share in the third quarter 2009.

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 program, scheduled maturities of long-term debt, interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $2 billion will be required through September 30, 2011 to fund maturities and announced repurchases and redemptions of long-term debt. Georgia Power met its obligations to repurchase $462.5 million in pollution control revenue bonds subsequent to September 30, 2010 with a portion of its current cash and cash equivalents balance at September 30, 2010. Gulf Power met its obligations to redeem $75 million in senior notes subsequent to September 30, 2010 with a portion of its current cash and cash equivalents balance at September 30, 2010. No mandatory contributions to Southern Company’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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Sources of Capital

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 2010, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. Except as described below with respect to potential DOE loan guarantees, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those utilized in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company.

However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Sources of Capital” of Southern Company in Item 7 of the Form 10-K for additional information.

On June 18, 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined construction and operating license for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.

In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE but has yet to begin discussions with the DOE regarding the terms and conditions of any loan guarantee. There can be no assurance the DOE will issue federal loan guarantees to Mississippi Power.

Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities), to meet liquidity needs. At September 30, 2010, Southern Company and its subsidiaries had approximately $1.3 billion of cash and cash equivalents and approximately $4.8 billion of unused committed credit arrangements with banks. Of the cash and cash equivalents, approximately $1.1 billion was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $126 million expire in 2010, $1.4 billion expire in 2011, and $3.2 billion expire in 2012. Of the credit arrangements expiring in 2010 and 2011, $81 million contain provisions allowing two-year term loans executable at expiration and $922 million contain provisions allowing one-year term loans executable at expiration. At September 30, 2010, approximately $1.8 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. Subsequent to September 30, 2010, Gulf Power renewed an existing credit agreement totaling $30 million and increased an existing credit agreement by $5 million; both agreements contain provisions allowing a one-year term loan executable at expiration and extended the expiration date to 2011. 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

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

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, 2010, the Southern Company system had approximately $345 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.4% per annum. During the third quarter 2010, Southern Company had an average of $814 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $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. In April 2010, Mississippi Power was required to notify the lessor, Juniper Capital L.P., if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the units or renew the lease. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be determined at this time.

Credit Rating Risk

Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At September 30, 2010, 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 $483 million. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.5 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.

On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch ratings of the preferred stock, preference stock, and long-term debt payable to affiliated trusts of the traditional operating companies decreased from A to A- at Alabama Power and Georgia Power, from A- to BBB+ at Gulf Power, and from A+ to A at Mississippi Power. These ratings are not applicable to the collateral requirements described above.

On August 12, 2010, Moody’s downgraded the issuer and long-term debt ratings of Southern Company (senior unsecured to Baa1 from A3), Georgia Power (senior unsecured to A3 from A2), Gulf Power (senior unsecured to A3 from A2) and Mississippi Power (senior unsecured to A2 from A1). Moody’s also announced that it had downgraded the short-term ratings of Southern Company and a financing subsidiary of Southern Company that issues commercial paper for the benefit of Southern Company subsidiaries (including Georgia Power, Gulf Power, and Mississippi Power) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of Georgia Power, Gulf Power, and Mississippi Power to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of Georgia Power (to Baa2 from Baa1), Gulf Power (to Baa2 from Baa1), and Mississippi Power (to Baa1 from A3). Moody’s also downgraded the trust preferred securities rating of Georgia Power to Baa1 from A3. All of these companies have stable ratings outlooks from Moody’s.

32

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

On September 3, 2010, Fitch downgraded the issuer and long-term debt ratings of Mississippi Power (senior unsecured to A+ from AA- and issuer default rating to A from A+). Fitch also announced that it had downgraded the short-term ratings of Mississippi Power to F1 from F1+. In addition, Fitch announced that it had downgraded the pollution control revenue bond ratings of Mississippi Power to A+ from AA- and the preferred stock ratings of Mississippi Power to A- from A. Fitch announced that the ratings outlook for Mississippi Power is stable. Also, Fitch announced that the ratings outlook of Southern Company had been revised to negative.

Market Price Risk

Southern Company’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 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 2010, 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, the registrants may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. As such, Southern Company had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.

The changes in fair value of energy-related derivative contracts for the three and nine months ended September 30, 2010 were as follows:

	Third Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(202	)	$	(178	)
Contracts realized or settled		49			160
Current period changes(a)		(96	)		(231	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(249	)	$	(249	)

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

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 was a decrease of $47 million and a decrease of $71 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At September 30, 2010, Southern Company had a net hedge volume of 138 million mmBtu with a weighted average contract cost of approximately $1.85 per mmBtu above market prices, compared to 134 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $1.56 per mmBtu above market prices and compared to 145 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.23 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses.

33

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

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

Asset (Liability) Derivatives	September 30, 2010			December 31, 2009
	(in millions)
Regulatory hedges	$	(247	)	$	(175	)
Cash flow hedges		1			(2	)
Not designated		(3	)		(1	)
Total fair value	$	(249	)	$	(178	)

Energy-related derivative contracts that are designated as regulatory hedges relate to the traditional operating companies’ fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Gains and losses on energy-related derivatives that are designated as cash flow hedges are mainly used by Southern Power to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Total net unrealized pre-tax gains (losses) recognized in income for the three and nine months ended September 30, 2010 were $(4) million and $(2) million, respectively. For the three and nine months ended September 30, 2009, the total net unrealized pre-tax gains (losses) recognized in income were $2 million and $1 million, respectively.

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. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:

	September 30, 2010
	Fair Value Measurements
	Total	Maturity
	Fair Value	Year 1	Years 2&3	Years 4&5
		(in millions)
Level 1	$   —	$   —	$   —	$   —
Level 2	(249)	(168)	(80)	(1)
Level 3	—	—	—	—
Fair value of contracts outstanding at end of period	$(249)	$ (168)	$  (80)	$   (1)

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 Note 1 under “Financial Instruments” and Note 11 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

During the third quarter 2010, Southern Company issued approximately $198 million of common stock through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued approximately 2 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of approximately $73 million, net of $0.6 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.

34

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

In the first nine months of 2010, Southern Company issued approximately $475 million of common stock through the Southern Investment Plan and employee and director stock plans. In addition, Southern Company issued approximately 4 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of approximately $143 million, net of $1.2 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 March 2010, Georgia Power issued $350 million aggregate principal amount of Series 2010A Floating Rate Senior Notes due March 15, 2013. The net proceeds were used to repay at maturity $250 million aggregate principal amount of Series 2008A Floating Rate Senior Notes due March 17, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program.

In April 2010, Gulf Power issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 15, 2020. The net proceeds were used to repay at maturity $140 million aggregate principal amount of its Series 2009A Floating Rate Senior Notes due June 28, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Gulf Power’s continuous construction program.

In June 2010, Georgia Power issued $600 million aggregate principal amount of Series 2010B 5.40% Senior Notes due June 1, 2040. The net proceeds from the sale of the Series 2010B Senior Notes were used for the redemption of all of the $200 million aggregate principal amount of Georgia Power’s Series R 6.00% Senior Notes due October 15, 2033 and all of the $150 million aggregate principal amount of Georgia Power’s Series O 5.90% Senior Notes due April 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program.

In June 2010, Gulf Power incurred obligations in connection with the issuance of $21 million aggregate principal amount of the Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Plant Scherer Project), First Series 2010. The net proceeds were used to fund pollution control and environmental improvement facilities at Plant Scherer.

In September 2010, Southern Company issued $400 million aggregate principal amount of Series 2010A 2.375% Senior Notes due September 15, 2015. The net proceeds will be used for the announced redemption of $250 million aggregate principal amount of Southern Company Capital Funding, Inc.’s Series C 5.75% Senior Notes due November 15, 2015 and were also used to repay a portion of its outstanding short-term indebtedness, and for other general corporate purposes.

In September 2010, Mississippi Power entered into a one-year $125 million aggregate principal amount long-term floating rate bank loan that bears interest based on one-month LIBOR. The proceeds were used to repay a portion of Mississippi Power’s short-term indebtedness and for general corporate purposes, including Mississippi Power’s continuous construction program.

In September 2010, Georgia Power issued $500 million aggregate principal amount Series 2010C 4.75% Senior Notes due September 1, 2040. The net proceeds were used to redeem all of the $250 million aggregate principal amount of Georgia Power’s Series X 5.70% Senior Notes due January 15, 2045, $125 million aggregate principal amount of Georgia Power’s Series W 6% Senior Notes due August 15, 2044, $100 million aggregate principal amount of Georgia Power’s Series T 5.75% Senior Public Income Notes due January 15, 2044, and $35 million aggregate principal amount of Savannah Electric and Power Company’s (Savannah Electric) Series G 5.75% Senior Notes due December 1, 2044 (which were assumed by Georgia Power upon its merger with Savannah Electric).

Also in September 2010, Georgia Power issued $500 million aggregate principal amount Series 2010D 1.30% Senior Notes due September 15, 2013. Subsequent to September 30, 2010, the net proceeds were used for the repurchase of all of the $114.3 million aggregate principal amount of outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Plant Vogtle Project), First Series 2009, due January 1, 2049; $40 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Plant Scherer Project), First Series 2009, due January 1, 2049; $173 million aggregate principal

35

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

amount of the outstanding Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Plant Bowen Project), First Series 2009, due December 1, 2032; $89.2 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Plant Scherer Project), Second Series 2009, due October 1, 2048; and $46 million aggregate principal amount of the outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Plant Vogtle Project), First Series 1996, due October 1, 2032, and for other general corporate purposes, including Georgia Power’s continuous construction program. The pollution control revenue bonds repurchased by Georgia Power are being held by Georgia Power and may be remarketed to investors in the future.

In September 2010, Gulf Power issued $125 million aggregate principal amount of its Series 2010B 5.10% Senior Notes due October 1, 2040. The net proceeds were used to repay a portion of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power’s continuous construction program, and, subsequent to September 30, 2010, for the redemption of all of the $40 million aggregate principal amount of Gulf Power’s Series I 5.75% Senior Notes due September 15, 2033 and $35 million aggregate principal amount of Gulf Power’s Series J 5.875% Senior Notes due April 1, 2044.

Subsequent to September 30, 2010, Alabama Power issued $250 million aggregate principal amount of Series 2010A 3.375% Senior Notes due October 1, 2020. Subsequent to September 30, 2010, the net proceeds were used for the redemption of $150 million aggregate principal amount of Alabama Power’s Series AA 5.625% Senior Notes due April 15, 2034 and for other general corporate purposes, including Alabama Power’s continuous construction program.

See Southern Company’s Condensed Consolidated Statements of Cash Flows herein for further details regarding financing activities during the first nine months of 2010.

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

36

PART I

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

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

Item 4. Controls and Procedures.

     (a) Evaluation of disclosure controls and procedures.

As of the end of the period covered by this quarterly report, Southern Company 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.

There have been no changes in Southern Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the third quarter 2010 that have materially affected or are reasonably likely to materially affect Southern Company’s internal control over financial reporting other than as described in the next paragraph.

In August 2010, Alabama Power implemented a new general ledger system and Mississippi Power implemented new general ledger, supply chain, and work management systems. These systems provide additional operational and internal control benefits including system security and the automation of previously manual controls. These process improvement initiatives were not in response to an identified internal control deficiency.

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.

There have been no changes in Georgia Power’s, Gulf Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the third quarter 2010 that have materially affected or are reasonably likely to materially affect Georgia Power’s, Gulf Power’s, or Southern Power’s internal control over financial reporting.

There have been no changes in Alabama Power’s and Mississippi Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the third quarter 2010 that have materially affected or are reasonably likely to materially affect Alabama Power’s and Mississippi Power’s internal control over financial reporting, other than as described in the next paragraph.

37

In August 2010, Alabama Power implemented a new general ledger system and Mississippi Power implemented new general ledger, supply chain, and work management systems. These systems provide additional operational and internal control benefits including system security and the automation of previously manual controls. These process improvement initiatives were not in response to an identified internal control deficiency.

38

ALABAMA POWER COMPANY

39

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	1,526,738		$	1,342,665		$	3,924,612		$	3,520,408
Wholesale revenues, non-affiliates		85,823			170,573			395,164			483,180
Wholesale revenues, affiliates		42,966			34,042			193,622			170,887
Other revenues		50,406			44,876			149,927			123,963
Total operating revenues		1,705,933			1,592,156			4,663,325			4,298,438
Operating Expenses:
Fuel		500,150			506,376			1,455,226			1,437,095
Purchased power, non-affiliates		34,931			42,915			65,532			84,582
Purchased power, affiliates		57,524			73,966			161,216			172,096
Other operations and maintenance		378,133			272,118			997,731			827,275
Depreciation and amortization		153,488			136,784			451,065			406,687
Taxes other than income taxes		84,261			77,353			247,592			239,673
Total operating expenses		1,208,487			1,109,512			3,378,362			3,167,408
Operating Income		497,446			482,644			1,284,963			1,131,030
Other Income and (Expense):
Allowance for equity funds used during construction		8,155			21,053			28,529			56,931
Interest income		4,129			4,419			12,143			12,689
Interest expense, net of amounts capitalized		(76,292	)		(75,817	)		(226,986	)		(224,792	)
Other income (expense), net		(6,137	)		(6,714	)		(17,827	)		(17,577	)
Total other income and (expense)		(70,145	)		(57,059	)		(204,141	)		(172,749	)
Earnings Before Income Taxes		427,301			425,585			1,080,822			958,281
Income taxes		157,782			154,050			398,912			344,416
Net Income		269,519			271,535			681,910			613,865
Dividends on Preferred and Preference Stock		9,866			9,866			29,598			29,598
Net Income After Dividends on Preferred and Preference Stock	$	259,653		$	261,669		$	652,312		$	584,267

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010		2009
	(in thousands)						(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	259,653		$	261,669		$	652,312	$	584,267
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $18, $(187), $8, and $(1,773), respectively		30			(307	)		13		(2,916	)
Reclassification adjustment for amounts included in net income, net of tax of $(68), $1,217, $475, and $3,456, respectively		(110	)		2,002			782		5,685
Total other comprehensive income (loss)		(80	)		1,695			795		2,769
Comprehensive Income	$	259,573		$	263,364		$	653,107	$	587,036

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

40

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	681,910		$	613,865
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		519,320			474,250
Deferred income taxes		301,119			(32,333	)
Allowance for equity funds used during construction		(28,529	)		(56,931	)
Pension, postretirement, and other employee benefits		(8,840	)		(2,955	)
Stock based compensation expense		4,174			3,475
Other, net		27,933			25,302
Changes in certain current assets and liabilities —
-Receivables		(109,948	)		232,890
-Fossil fuel stock		21,130			(20,609	)
-Materials and supplies		(9,906	)		(22,783	)
-Other current assets		(33,540	)		(43,436	)
-Accounts payable		(66,037	)		(197,357	)
-Accrued taxes		(48,091	)		168,493
-Accrued compensation		7,541			(46,583	)
-Other current liabilities		(103,390	)		70,111
Net cash provided from operating activities		1,154,846			1,165,399
Investing Activities:
Property additions		(684,738	)		(896,913	)
Distribution of restricted cash from pollution control revenue bonds		18,464			39,866
Nuclear decommissioning trust fund purchases		(126,039	)		(177,639	)
Nuclear decommissioning trust fund sales		126,039			177,639
Cost of removal, net of salvage		(25,830	)		(21,419	)
Change in construction payables		(34,329	)		37,486
Other investing activities		(9,212	)		(27,484	)
Net cash used for investing activities		(735,645	)		(868,464	)
Financing Activities:
Decrease in notes payable, net		—			(24,995	)
Proceeds —
Common stock issued to parent		—			135,000
Capital contributions from parent company		18,823			17,177
Pollution control revenue bonds		—			53,000
Senior notes issuances		—			500,000
Redemptions —
Senior notes		—			(250,000	)
Payment of preferred and preference stock dividends		(29,670	)		(29,602	)
Payment of common stock dividends		(407,025	)		(392,100	)
Other financing activities		(1,242	)		(2,474	)
Net cash provided from (used for) financing activities		(419,114	)		6,006
Net Change in Cash and Cash Equivalents		87			302,941
Cash and Cash Equivalents at Beginning of Period		368,016			28,181
Cash and Cash Equivalents at End of Period	$	368,103		$	331,122
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $11,121 and $23,813 capitalized for 2010 and 2009, respectively)	$	214,102		$	190,014
Income taxes (net of refunds)	$	212,036		$	274,486

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

41

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	368,103		$	368,016
Restricted cash and cash equivalents		18,249			36,711
Receivables —
Customer accounts receivable		451,381			322,292
Unbilled revenues		142,372			134,875
Under recovered regulatory clause revenues		12,065			37,338
Other accounts and notes receivable		46,986			33,522
Affiliated companies		45,382			61,508
Accumulated provision for uncollectible accounts		(12,035	)		(9,551	)
Fossil fuel stock, at average cost		369,074			394,511
Materials and supplies, at average cost		335,954			326,074
Vacation pay		54,038			53,607
Prepaid expenses		222,608			111,320
Other regulatory assets, current		45,246			34,347
Other current assets		8,633			6,203
Total current assets		2,108,056			1,910,773
Property, Plant, and Equipment:
In service		19,794,009			18,574,229
Less accumulated provision for depreciation		6,861,206			6,558,864
Plant in service, net of depreciation		12,932,803			12,015,365
Nuclear fuel, at amortized cost		296,484			253,308
Construction work in progress		560,185			1,256,311
Total property, plant, and equipment		13,789,472			13,524,984
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		61,600			59,628
Nuclear decommissioning trusts, at fair value		516,696			489,795
Miscellaneous property and investments		70,066			69,749
Total other property and investments		648,362			619,172
Deferred Charges and Other Assets:
Deferred charges related to income taxes		411,986			387,447
Prepaid pension costs		159,843			132,643
Other regulatory assets, deferred		741,280			750,492
Other deferred charges and assets		207,103			198,582
Total deferred charges and other assets		1,520,212			1,469,164
Total Assets	$	18,066,102		$	17,524,093

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

42

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2010			2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	450,000		$	100,000
Accounts payable —
Affiliated		225,885			194,675
Other		193,220			328,400
Customer deposits		85,849			86,975
Accrued taxes —
Accrued income taxes		1,721			14,789
Other accrued taxes		101,088			31,918
Accrued interest		65,219			65,455
Accrued vacation pay		44,415			44,751
Accrued compensation		81,239			71,286
Liabilities from risk management activities		40,499			37,844
Over recovered regulatory clause revenues		95,227			181,565
Other current liabilities		38,062			40,020
Total current liabilities		1,422,424			1,197,678
Long-term Debt		5,732,575			6,082,489
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,572,558			2,293,468
Deferred credits related to income taxes		85,979			88,705
Accumulated deferred investment tax credits		158,770			164,713
Employee benefit obligations		405,342			387,936
Asset retirement obligations		511,828			491,007
Other cost of removal obligations		701,073			668,151
Other regulatory liabilities, deferred		198,742			169,224
Deferred over recovered regulatory clause revenues		5,495			22,060
Other deferred credits and liabilities		77,676			37,113
Total deferred credits and other liabilities		4,717,463			4,322,377
Total Liabilities		11,872,462			11,602,544
Redeemable Preferred Stock		341,715			341,715
Preference Stock		343,373			343,373
Common Stockholder’s Equity:
Common stock, par value $40 per share —
Authorized - 40,000,000 shares
Outstanding - 30,537,500 shares		1,221,500			1,221,500
Paid-in capital		2,145,902			2,119,818
Retained earnings		2,145,738			1,900,526
Accumulated other comprehensive loss		(4,588	)		(5,383	)
Total common stockholder’s equity		5,508,552			5,236,461
Total Liabilities and Stockholder’s Equity	$	18,066,102		$	17,524,093

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

43

ALABAMA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009

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 given current economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Appropriately balancing 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

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(2.0)	(0.8)	$68.0	11.6

Alabama Power’s net income after dividends on preferred and preference stock for the third quarter 2010 was $259.7 million compared to $261.7 million for the corresponding period in 2009. Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2010 was $652.3 million compared to $584.3 million for the corresponding period in 2009. For the third quarter 2010, the decrease in net income when compared to the corresponding period in 2009 was not material. The increase for year-to-date 2010 when compared to the corresponding period in 2009 was primarily due to increases in rates under Rate RSE and Rate CNP Environmental that took effect in January 2010, warmer weather in the second and third quarters 2010 as well as significantly colder weather in the first quarter 2010, and increases in industrial sales. The increases in revenues were partially offset by increases in operations and maintenance expenses, which include an additional NDR accrual in the third quarter 2010, and depreciation and amortization and a reduction in AFUDC equity.

The increases in rates under Rate RSE and Rate CNP Environmental were offset by decreases in Rate ECR and the costs associated with the expiration of a PPA certificated by the Alabama PSC, resulting in an overall annual reduction in Alabama Power’s retail customer billing rates in 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Rate Adjustments” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

44

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

Retail Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$184.0	13.7	$404.2	11.5

In the third quarter 2010, retail revenues were $1.53 billion compared to $1.34 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $3.92 billion compared to $3.52 billion for the corresponding period in 2009.

Details of the change to retail revenues are as follows:

	Third Quarter						Year-to-Date
	2010						2010
	(in millions)			(% change)			(in millions)		(% change)
Retail – prior year	$	1,342.7					$	3,520.4
Estimated change in —
Rates and pricing		90.4			6.7			218.7		6.2
Sales growth (decline)		(1.6	)		(0.1	)		6.4		0.2
Weather		82.6			6.2			163.7		4.7
Fuel and other cost recovery		12.6			0.9			15.4		0.4
Retail – current year	$	1,526.7			13.7	%	$	3,924.6		11.5	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to Rate RSE and Rate CNP Environmental increases effective January 2010.

Revenues attributable to changes in sales decreased in the third quarter 2010 when compared to the corresponding period in 2009. Industrial KWH energy sales increased 8.8% due to an increase in demand primarily in the chemicals and primary metals sectors. Weather-adjusted residential KWH energy sales decreased 2.5% driven by a decrease in demand. Weather-adjusted commercial KWH energy sales growth was not material.

Revenues attributable to changes in sales increased year-to-date 2010 when compared to the corresponding period in 2009. Industrial KWH energy sales increased 12.4% due to an increase in demand primarily in the chemicals and primary metals sectors. Weather-adjusted residential KWH energy sales growth was not material. Weather-adjusted commercial KWH energy sales decreased 1.2% driven by a decline in the number of customers.

Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.

Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to increased generation. These increases were offset primarily by a decrease in costs associated with the expiration of a PPA certificated by the Alabama PSC and a reduction in the Rate NDR customer billing rate as a result of achieving the target reserve balance in January 2010. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not impact net income.

45

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

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.

Wholesale Revenues – Non-Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(84.8)	(49.7)	$(88.0)	(18.2)

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. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

In May 2010, the long-term unit power sales contracts expired and the unit power sales capacity revenues ceased, resulting in a $90.2 million and $107.4 million revenue reduction in the third quarter and year-to-date 2010, respectively. Beginning in June 2010, such capacity subject to the unit power sales contracts became available for retail service. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Operating Revenues” of Alabama Power in Item 7 of the Form 10-K for additional information.

In the third quarter 2010, wholesale revenues from non-affiliates were $85.8 million compared to $170.6 million for the corresponding period in 2009. This decrease was primarily due to a 62.3% decrease in KWH sales, partially offset by a 33.5% increase in the price of energy.

For year-to-date 2010, wholesale revenues from non-affiliates were $395.2 million compared to $483.2 million for the corresponding period in 2009. This decrease was primarily due to a 32.5% decrease in KWH sales, partially offset by a 21.1% increase in the price of energy.

Wholesale Revenues – Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$9.0	26.2	$22.7	13.3

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 2010, wholesale revenues from affiliates were $43.0 million compared to $34.0 million for the corresponding period in 2009. The increase was due to an 18.5% increase in prices and a 6.5% increase in KWH sales.

For year-to-date 2010, wholesale revenues from affiliates were $193.6 million compared to $170.9 million for the corresponding period in 2009. The increase was primarily due to an 8.7% increase in prices and a 4.3% increase in KWH sales.

46

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

Other Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$5.5	12.3	$26.0	20.9

In the third quarter 2010, other revenues were $50.4 million compared to $44.9 million for the corresponding period in 2009. This increase was due to a $3.7 million increase in transmission sales and a $3.2 million increase in revenues from gas-fueled co-generation steam facilities as a result of greater sales volume, partially offset by a decrease in customer charges related to collection fees.

For year-to-date 2010, other revenues were $149.9 million compared to $124.0 million for the corresponding period in 2009. This increase was due to a $10.9 million increase in revenues from gas-fueled co-generation steam facilities as a result of greater sales volume, an $8.2 million increase in transmission sales, a $1.3 million increase in customer charges related to reconnection fees, and a $1.3 million increase in pole attachment rentals.

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

Fuel and Purchased Power Expenses

	Third Quarter 2010						Year-to-Date 2010
	vs.						vs.
	Third Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	(6.2	)		(1.2	)	$	18.1			1.3
Purchased power – non-affiliates		(8.0	)		(18.6	)		(19.0	)		(22.5	)
Purchased power – affiliates		(16.5	)		(22.2	)		(10.9	)		(6.3	)
Total fuel and purchased power expenses	$	(30.7	)				$	(11.8	)

* 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 2010, total fuel and purchased power expenses were $592.6 million compared to $623.3 million for the corresponding period in 2009. The decrease was primarily due to a $41.3 million decrease in the volume of energy purchased, partially offset by a $14.9 million increase in KWHs generated.

For year-to-date 2010, the decrease in total fuel and purchased power expenses when compared to the corresponding period in 2009 was not material.

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.

47

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	2010		2009		Change			2010		2009		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		2.72		2.80		(2.9	)		2.78		2.83		(1.8	)
Purchased power		7.11		6.45		10.2			6.83		6.23		9.6

In the third quarter 2010, the decrease in fuel expense when compared to the corresponding period in 2009 was not material. For year-to-date 2010, the increase in fuel expense when compared to the corresponding period in 2009 was not material.

Non-Affiliates

In the third quarter 2010, purchased power expense from non-affiliates was $34.9 million compared to $42.9 million for the corresponding period in 2009. This decrease was primarily related to a 35.8% decrease in the average cost per KWH purchased, partially offset by a 26.8% increase in the volume of energy purchased.

For year-to-date 2010, purchased power expense from non-affiliates was $65.5 million compared to $84.6 million for the corresponding period in 2009. This decrease was related to an 18.7% decrease in the volume of energy purchased and a 4.7% decrease in the average cost per KWH purchased.

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

Affiliates

In the third quarter 2010, purchased power expense from affiliates was $57.5 million compared to $74.0 million for the corresponding period in 2009. The decrease was related to a 41.5% decrease in the amount of energy purchased, partially offset by a 33.0% increase in price.

For year-to-date 2010, purchased power expense from affiliates was $161.2 million compared to $172.1 million for the corresponding period in 2009. The decrease was related to a 27.2% increase in price, partially offset by a 26.3% decrease in the volume of energy purchased.

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

Other Operations and Maintenance Expenses

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$106.0	39.0	$170.4	20.6

In the third quarter 2010, other operations and maintenance expenses were $378.1 million compared to $272.1 million for the corresponding period in 2009. Transmission and distribution expenses increased $58.8 million due primarily to an additional accrual of $40 million to the NDR. See FUTURE EARNINGS POTENTIAL – “FERC and Alabama PSC

48

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

Matters – Retail Regulatory Matters” herein for additional information on the NDR. In addition, overhead line maintenance expenses increased. Steam production expenses increased $12.3 million due to environmental mandates (which are offset by revenues associated with Rate CNP Environmental) and maintenance costs related to increases in labor and materials expenses. Administrative and general expenses increased $20.6 million related to increases in the injuries and damages reserve, affiliated service companies’ expenses, and labor, partially offset by a reduction in employee medical and other benefit-related expenses. Nuclear production expenses increased $8.2 million due to maintenance costs related to increases in labor.

For year-to-date 2010, other operations and maintenance expenses were $997.7 million compared to $827.3 million for the corresponding period in 2009. Transmission and distribution expenses increased $60.2 million due primarily to an additional accrual of $40 million to the NDR. See FUTURE EARNINGS POTENTIAL – “FERC and Alabama PSC Matters – Retail Regulatory Matters” herein for additional information on the NDR. In addition, overhead line maintenance expenses increased. Steam production expenses increased $48.4 million due to scheduled outage costs, environmental mandates (which are offset by revenues associated with Rate CNP Environmental), and maintenance costs related to increases in labor and materials expenses. Administrative and general expenses increased $43.3 million due to increases in the injuries and damages reserve, affiliated service companies’ expenses, labor, and property insurance expenses, partially offset by a reduction in employee medical and other benefit-related expenses. Nuclear production expenses increased $12.2 million due to maintenance costs related to increases in labor.

Depreciation and Amortization

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$16.7	12.2	$44.4	10.9

In the third quarter 2010, depreciation and amortization was $153.5 million compared to $136.8 million for the corresponding period in 2009. For year-to-date 2010, depreciation and amortization was $451.1 million compared to $406.7 million for the corresponding period in 2009. These increases were due to additions of property, plant, and equipment primarily related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.

Taxes Other Than Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$6.9	8.9	$7.9	3.3

In the third quarter 2010, taxes other than income taxes were $84.3 million compared to $77.4 million for the corresponding period in 2009. The increase was primarily due to increases in state and municipal public utility license tax bases.

For year-to-date 2010, the increase in taxes other than income taxes when compared to the corresponding period in 2009 was not material.

49

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

Allowance for Equity Funds Used During Construction

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(12.9)	(61.3)	$(28.4)	(49.9)

In the third quarter 2010, AFUDC equity was $8.2 million compared to $21.1 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $28.5 million compared to $56.9 million for the corresponding period in 2009. These decreases were due to the completion of construction projects related to environmental mandates at generating facilities, partially offset by increases in nuclear facility projects.

Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$3.7	2.4	$54.5	15.8

In the third quarter 2010, the increase in total income taxes when compared to the corresponding period in 2009 was not material. For year-to-date 2010, income taxes were $398.9 million compared to $344.4 million for the corresponding period in 2009. These increases were primarily due to higher pre-tax earnings and a reduction of the tax benefits associated with a decrease in AFUDC equity.

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 all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power’s service area. Changes in economic conditions impact sales for Alabama Power, and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

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.

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional

50

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

information regarding a civil action brought by the EPA alleging that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including one relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.

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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Alabama Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO₂) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO₂, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO₂) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Alabama Power’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO₂ standard could result in significant additional compliance and operational costs for units that require new source permitting.

51

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

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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Alabama, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

These regulations could result in significant additional compliance and operational 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.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Alabama Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.

The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Alabama Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational 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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

52

ALABAMA 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 Alabama Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational 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. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.

FERC and Alabama PSC Matters

Retail Regulatory Matters

Nuclear Outage Accounting Order

On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Currently, Alabama Power accrues nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period.

The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period.

53

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

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s over recovered fuel costs as of September 30, 2010 totaled $57.7 million as compared to $199.6 million at December 31, 2009. These over recovered fuel costs at September 30, 2010 are included in over recovered regulatory clause revenues and deferred over recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. The current and deferred classifications are based on estimates which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs.

Natural Disaster Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Reserve” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery.

On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the $75 million base reserve.

In September 2010, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $118 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The additional accruals are reflected as operations and maintenance expense in the Condensed Statements of Income herein.

Hydro Relicensing

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters” of Alabama Power in Item 7 of the Form 10-K for information regarding Alabama Power’s applications to the FERC for new licenses for certain of its hydroelectric projects. On March 31, 2010, the FERC issued a new 30-year license for the Lewis Smith and Bankhead developments on the Warrior River. The new license authorizes Alabama Power to continue operating these facilities in a manner consistent with past operations. On April 30, 2010, a stakeholders group filed a request for rehearing of the FERC order issuing the new license. On May 27, 2010, the FERC granted the rehearing request for the limited purpose of allowing the FERC additional time to consider the substantive issues raised in the request. The ultimate outcome of this matter cannot be determined at this time.

54

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

Legislation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Alabama Power in Item 7 of the Form 10-K for additional information.

Healthcare Reform

On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Alabama Power has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Alabama Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Alabama Power cannot be determined at this time.

Stimulus Funding

On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009 (ARRA). This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. Alabama Power will receive, and will match, $65 million under this agreement.

On May 12, 2010, Alabama Power signed an agreement with the DOE formally accepting a $6 million grant under the ARRA. This funding will be used for hydro generation upgrades. The total upgrade project is expected to cost $30 million and Alabama Power plans to spend $24 million on the project.

Income Tax Matters

Tax Method of Accounting for Repairs

Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $117 million for Alabama Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

55

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

Bonus Depreciation

On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Alabama Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $102 million.

Other Matters

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

The coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has not impacted operations, but has had and may continue to have significant economic impacts on the affected areas within Alabama Power’s service territory.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Alabama Power prepares its financial statements in accordance with 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, Unbilled Revenues, and Pension and Other Postretirement Benefits.

56

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, 2010. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $1.16 billion for the first nine months of 2010, compared to $1.17 billion for the corresponding period in 2009. The $10.6 million decrease in cash provided from operating activities was primarily due to less cash collections of regulatory clause revenues when compared to the prior year, partially offset by an increase in deferred income taxes primarily due to the change in the tax accounting method for repair costs as previously discussed. Net cash used for investing activities totaled $735.6 million in the first nine months of 2010 primarily due to gross property additions related to steam generation equipment and construction payables. Net cash used for financing activities totaled $419.1 million for the first nine months of 2010, compared to $6.0 million provided in the corresponding period in 2009. The $425.1 million decrease is primarily due to no issuances of securities in the first nine months of 2010. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2010 include increases of $264.5 million in total property, plant, and equipment related to environmental projects, partially offset by a reduction in construction work in progress and an increase in accumulated provision for depreciation; $129.1 million in customer accounts receivable; $111.3 million in prepaid expenses; $279.1 million in accumulated deferred income taxes; and $245.2 million in retained earnings.

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, interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $450 million will be required through September 30, 2011 to fund maturities and announced redemptions of long-term debt. No mandatory contributions to Alabama Power’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

57

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

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, 2010 cash and cash equivalents of approximately $368 million and unused committed credit arrangements with banks of approximately $1.3 billion. Of the cash and cash equivalents, approximately $319 million was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $60 million expire in 2010, $446 million expire in 2011, and $765 million expire in 2012. All of the credit arrangements that expire in 2010 contain provisions allowing for one-year term loans executable at expiration. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Alabama Power’s commercial paper borrowings and $798 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. 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, 2010, Alabama Power had no commercial paper borrowings outstanding. During the third quarter 2010, Alabama Power had an average of $8 million of commercial paper outstanding at a weighted average interest rate of 0.2% per annum and the maximum amount outstanding was $60 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $343 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power’s ability to access capital markets, particularly the short-term debt market.

On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch ratings of Alabama Power’s preferred stock, preference stock, and long-term debt payable to affiliated trusts decreased from A to A-. These ratings are not applicable to the collateral requirements described above.

Market Price Risk

Alabama Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 reporting period. Since a significant portion of outstanding indebtedness remains at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

58

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

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 had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2010 were as follows:

	Third Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(45	)	$	(44	)
Contracts realized or settled		14			48
Current period changes(a)		(23	)		(58	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(54	)	$	(54	)

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

The change in the fair value positions of the energy-related derivative contracts for the three months and nine months ended September 30, 2010 was a decrease of $9 million and a decrease of $10 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At September 30, 2010, Alabama Power had a net hedge volume of 34 million mmBtu with a weighted average contract cost of approximately $1.62 per mmBtu above market prices, compared to 31 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $1.47 per mmBtu above market prices and 36 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.22 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the fuel cost recovery clause.

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

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.

Alabama Power uses over-the-counter contracts that are not exchange-traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:

	September 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(54	)		(40	)		(14	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(54	)	$	(40	)	$	(14	)	$	—

See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements.

59

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

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

Financing Activities

Subsequent to September 30, 2010, Alabama Power issued $250 million aggregate principal amount of Series 2010A 3.375% Senior Notes due October 1, 2020. Subsequent to September 30, 2010, the net proceeds were used for the redemption of $150 million aggregate principal amount of Alabama Power’s Series AA 5.625% Senior Notes due April 15, 2034 and for other general corporate purposes, including Alabama Power’s continuous construction program.

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.

60

GEORGIA POWER COMPANY

61

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	2,418,231		$	2,093,503		$	6,036,216		$	5,368,123
Wholesale revenues, non-affiliates		108,938			108,521			307,167			301,077
Wholesale revenues, affiliates		16,844			53,687			43,118			98,520
Other revenues		84,163			71,477			225,345			199,623
Total operating revenues		2,628,176			2,327,188			6,611,846			5,967,343
Operating Expenses:
Fuel		928,016			830,283			2,442,897			2,083,662
Purchased power, non-affiliates		128,557			86,450			294,098			219,220
Purchased power, affiliates		142,509			158,864			436,507			528,505
Other operations and maintenance		434,904			358,821			1,224,157			1,102,876
Depreciation and amortization		181,866			122,740			426,094			464,931
Taxes other than income taxes		98,732			86,620			264,372			243,876
Total operating expenses		1,914,584			1,643,778			5,088,125			4,643,070
Operating Income		713,592			683,410			1,523,721			1,324,273
Other Income and (Expense):
Allowance for equity funds used during construction		34,039			23,200			104,694			66,267
Interest income		603			611			1,398			1,644
Interest expense, net of amounts capitalized		(94,596	)		(95,309	)		(274,918	)		(293,124	)
Other income (expense), net		(5,754	)		(4,127	)		(12,967	)		(8,316	)
Total other income and (expense)		(65,708	)		(75,625	)		(181,793	)		(233,529	)
Earnings Before Income Taxes		647,884			607,785			1,341,928			1,090,744
Income taxes		223,669			215,720			432,851			378,030
Net Income		424,215			392,065			909,077			712,714
Dividends on Preferred and Preference Stock		4,345			4,345			13,036			13,036
Net Income After Dividends on Preferred and Preference Stock	$	419,870		$	387,720		$	896,041		$	699,678

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2010		2009			2010			2009
	(in thousands)					(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	419,870	$	387,720		$	896,041		$	699,678
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(430), $(6), and $(156), respectively		—		(682	)		(10	)		(247	)
Reclassification adjustment for amounts included in net income, net of tax of $1,379, $2,350, $5,136, and $6,520, respectively		2,186		3,725			8,143			10,336
Total other comprehensive income (loss)		2,186		3,043			8,133			10,089
Comprehensive Income	$	422,056	$	390,763		$	904,174		$	709,767

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

62

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	909,077		$	712,714
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		550,940			566,741
Deferred income taxes		225,432			111,035
Deferred revenues		(77,081	)		(37,210	)
Deferred expenses		(53,761	)		(39,570	)
Allowance for equity funds used during construction		(104,694	)		(66,267	)
Pension, postretirement, and other employee benefits		20,458			16,713
Hedge settlements		—			(16,167	)
Insurance cash surrender value		1,275			22,381
Other, net		(8,925	)		21,131
Changes in certain current assets and liabilities —
-Receivables		(125,658	)		3,648
-Fossil fuel stock		153,144			(245,777	)
-Prepaid income taxes		2,096			(20,694	)
-Other current assets		4,006			505
-Accounts payable		61,223			40,719
-Accrued taxes		65,873			131,432
-Accrued compensation		45,015			(105,097	)
-Other current liabilities		38,103			35,575
Net cash provided from operating activities		1,706,523			1,131,812
Investing Activities:
Property additions		(1,628,055	)		(1,778,030	)
Distribution of restricted cash from pollution control revenue bonds		—			22,077
Nuclear decommissioning trust fund purchases		(569,815	)		(889,049	)
Nuclear decommissioning trust fund sales		545,561			841,763
Nuclear decommissioning trust securities lending collateral		20,793			43,824
Cost of removal, net of salvage		(45,918	)		(41,709	)
Change in construction payables, net of joint owner portion		27,345			45,828
Other investing activities		(16,318	)		7,519
Net cash used for investing activities		(1,666,407	)		(1,747,777	)
Financing Activities:
Decrease in notes payable, net		(320,549	)		(103,634	)
Proceeds —
Capital contributions from parent company		681,353			923,840
Pollution control revenue bonds issuances		—			416,510
Senior notes issuances		1,950,000			500,000
Other long-term debt issuances		—			1,100
Redemptions —
Pollution control revenue bonds		—			(327,310	)
Senior notes		(1,111,914	)		(332,841	)
Other long-term debt		(2,500	)		—
Payment of preferred and preference stock dividends		(13,300	)		(13,121	)
Payment of common stock dividends		(615,000	)		(554,175	)
Other financing activities		(32,761	)		(12,674	)
Net cash provided from financing activities		535,329			497,695
Net Change in Cash and Cash Equivalents		575,445			(118,270	)
Cash and Cash Equivalents at Beginning of Period		14,309			132,739
Cash and Cash Equivalents at End of Period	$	589,754		$	14,469
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $39,022 and $28,443 capitalized for 2010 and 2009, respectively)	$	231,285		$	239,290
Income taxes (net of refunds)	$	107,427		$	115,436

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

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	589,754		$	14,309
Receivables —
Customer accounts receivable		753,688			486,885
Unbilled revenues		206,150			172,035
Under recovered regulatory clause revenues		196,149			291,837
Joint owner accounts receivable		45,288			146,932
Other accounts and notes receivable		55,466			62,758
Affiliated companies		28,593			11,775
Accumulated provision for uncollectible accounts		(13,309	)		(9,856	)
Fossil fuel stock, at average cost		573,122			726,266
Materials and supplies, at average cost		367,308			362,803
Vacation pay		73,806			74,566
Prepaid income taxes		90,058			132,668
Other regulatory assets, current		105,665			76,634
Other current assets		117,249			62,651
Total current assets		3,188,987			2,612,263
Property, Plant, and Equipment:
In service		26,109,530			25,120,034
Less accumulated provision for depreciation		9,857,869			9,493,068
Plant in service, net of depreciation		16,251,661			15,626,966
Nuclear fuel, at amortized cost		364,372			339,810
Construction work in progress		3,079,691			2,521,091
Total property, plant, and equipment		19,695,724			18,487,867
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		68,037			66,106
Nuclear decommissioning trusts, at fair value		625,869			580,322
Miscellaneous property and investments		38,391			38,516
Total other property and investments		732,297			684,944
Deferred Charges and Other Assets:
Deferred charges related to income taxes		707,496			608,851
Deferred under recovered regulatory clause revenues		291,736			373,245
Other regulatory assets, deferred		1,331,659			1,321,904
Other deferred charges and assets		202,049			205,492
Total deferred charges and other assets		2,532,940			2,509,492
Total Assets	$	26,149,948		$	24,294,566

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

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GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2010			2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	874,817		$	253,882
Notes payable		3,410			323,958
Accounts payable —
Affiliated		293,416			238,599
Other		545,539			602,003
Customer deposits		200,189			200,103
Accrued taxes —
Accrued income taxes		79,533			548
Unrecognized tax benefits		177,241			164,863
Other accrued taxes		261,155			290,174
Accrued interest		117,228			89,228
Accrued vacation pay		55,098			57,662
Accrued compensation		91,663			42,756
Liabilities from risk management activities		84,146			49,788
Other cost of removal obligations, current		37,000			216,000
Other regulatory liabilities, current		21,066			99,807
Other current liabilities		117,382			84,319
Total current liabilities		2,958,883			2,713,690
Long-term Debt		7,985,180			7,782,340
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,648,873			3,389,907
Deferred credits related to income taxes		129,985			133,683
Accumulated deferred investment tax credits		232,566			242,496
Employee benefit obligations		945,999			923,177
Asset retirement obligations		703,827			676,705
Other cost of removal obligations		186,793			124,662
Other deferred credits and liabilities		210,345			139,024
Total deferred credits and other liabilities		6,058,388			5,629,654
Total Liabilities		17,002,451			16,125,684
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		5,281,791			4,592,350
Retained earnings		3,213,975			2,932,934
Accumulated other comprehensive loss		(12,699	)		(20,832	)
Total common stockholder’s equity		8,881,540			7,902,925
Total Liabilities and Stockholder’s Equity	$	26,149,948		$	24,294,566

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

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GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009

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 given current economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. Georgia Power is currently constructing two new nuclear and three new combined cycle generating units. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future. Georgia Power filed a general rate case on July 1, 2010, requesting a base rate increase effective January 1, 2011. On March 11, 2010, the Georgia PSC approved Georgia Power’s request to increase its fuel cost recovery rate effective April 1, 2010. Georgia Power is required to file its next fuel cost recovery case by March 1, 2011.

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

RESULTS OF OPERATIONS

Net Income

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$32.2	8.3	$196.3	28.1

Georgia Power’s net income after dividends on preferred and preference stock for the third quarter 2010 was $419.9 million compared to $387.7 million for the corresponding period in 2009. The increase was due primarily to higher residential base revenues resulting from warmer weather in the third quarter 2010, partially offset by a reduction in the amortization of the regulatory liability related to other cost of removal obligations that began in July 2009 as authorized by the Georgia PSC, as well as higher operations and maintenance expenses.

Georgia Power’s year-to-date 2010 net income after dividends on preferred and preference stock was $896.0 million compared to $699.7 million for the corresponding period in 2009. The increase was due primarily to higher residential base revenues resulting from warmer weather in the second and third quarters 2010, significantly colder weather in the first quarter 2010, and the amortization of the regulatory liability related to other cost of removal obligations, partially offset by increases in operations and maintenance expenses.

Retail Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$324.7	15.5	$668.1	12.4

In the third quarter 2010, retail revenues were $2.4 billion compared to $2.1 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $6.0 billion compared to $5.4 billion for the corresponding period in 2009.

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

Details of the change to retail revenues are as follows:

	Third Quarter					Year-to-Date
	2010					2010
	(in millions)		(% change)			(in millions)		(% change)
Retail – prior year	$	2,093.5				$	5,368.1
Estimated change in —
Rates and pricing		49.5		2.4			21.8		0.4
Sales growth (decline)		9.8		0.4			49.9		0.9
Weather		104.3		5.0			181.9		3.4
Fuel cost recovery		161.1		7.7			414.5		7.7
Retail – current year	$	2,418.2		15.5	%	$	6,036.2		12.4	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009 due to higher contributions from market-driven rates for sales to industrial customers and increased recognition of environmental compliance cost recovery revenues in accordance with the 2007 Retail Rate Plan.

Revenues attributable to changes in sales increased for all customer classes in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009. Weather-adjusted KWH energy sales increased 2.0%, decreased 1.8%, and increased 4.3% in the third quarter 2010 when compared to the corresponding period in 2009 for residential, commercial, and industrial classes, respectively. Weather-adjusted KWH energy sales increased 1.7%, decreased 0.4%, and increased 6.3% for year-to-date 2010 when compared to the corresponding period in 2009 for residential, commercial, and industrial classes, respectively.

Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $161.1 million in the third quarter 2010 and $414.5 million for year-to-date 2010 when compared to the corresponding periods in 2009 due to increased KWH energy sales and higher fuel costs. See Note (B) to the Condensed Financial Statements under “State PSC Matters – Georgia Power – Fuel Cost Recovery” herein for additional information.

Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(36.8)	(68.6)	$(55.4)	(56.2)

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.

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

In the third quarter 2010, wholesale revenues from affiliates were $16.9 million compared to $53.7 million for the corresponding period in 2009. For year-to-date 2010, wholesale revenues from affiliates were $43.1 million compared to $98.5 million for the corresponding period in 2009. These decreases were due to an 80.6% decrease and a 63.6% decrease in KWH sales due to lower demand in the third quarter and year-to-date 2010, respectively, because the market cost of available energy was lower than the cost of Georgia Power-owned generation.

Other Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$12.7	17.7	$25.7	12.9

In the third quarter 2010, other revenues were $84.2 million compared to $71.5 million for the corresponding period in 2009. This increase was primarily due to a $10.4 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies and an increase of $0.9 million in outdoor lighting revenues.

For year-to-date 2010, other revenues were $225.3 million compared to $199.6 million for the corresponding period in 2009. This increase was due to a $16.7 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies, a $5.1 million increase in late payment fees and customer maintenance request revenues, an increase of $2.0 million in pole attachment and equipment rental revenue primarily as a result of a new transmission line rental agreement that began in June 2009, and an increase of $2.3 million in outdoor lighting revenues primarily as a result of new customer sales associated with government stimulus programs.

Fuel and Purchased Power Expenses

	Third Quarter 2010						Year-to-Date 2010
	vs.						vs.
	Third Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	97.7			11.8		$	359.2			17.2
Purchased power – non-affiliates		42.1			48.7			74.9			34.2
Purchased power – affiliates		(16.4	)		(10.3	)		(92.0	)		(17.4	)
Total fuel and purchased power expenses	$	123.4					$	342.1

* 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 2010, total fuel and purchased power expenses were $1.2 billion compared to $1.1 billion in the corresponding period in 2009. This increase was primarily due to an $87.7 million increase related to higher KWHs generated primarily due to higher customer demand as a result of warmer weather in the third quarter 2010 and a $35.7 million increase in the average cost of fuel and purchased power.

For year-to-date 2010, total fuel and purchased power expenses were $3.2 billion compared to $2.8 billion in the corresponding period in 2009. This increase was due to a $218.4 million increase in the average cost of fossil and nuclear fuel and a $123.7 million increase related to higher KWHs generated primarily due to higher customer demand as a result of significantly colder weather in the first quarter 2010 and warmer weather in the second and third quarters 2010.

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 – “Georgia PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

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

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

	Third Quarter		Third Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2010		2009		Change			2010		2009		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		3.97		3.50		13.4			3.84		3.39		13.3
Purchased power		5.50		6.43		(14.5	)		5.90		6.14		(3.9	)

In the third quarter 2010, fuel expense was $928.0 million compared to $830.3 million in the corresponding period in 2009. This increase was due to a 13.4% increase in the average cost of fuel per KWH and a 1.4% increase of KWHs generated as a result of higher KWH demand. The average cost of coal and natural gas increased 8.1% and 44.6%, respectively.

For year-to-date 2010, fuel expense was $2.4 billion compared to $2.1 billion in the corresponding period in 2009. This increase was due to a 13.3% increase in the average cost of fuel per KWH and a 6.6% increase of KWHs generated as a result of higher KWH demand. The average cost of coal and natural gas increased 9.3% and 32.8%, respectively.

Non-Affiliates

In the third quarter 2010, purchased power expense from non-affiliates was $128.6 million compared to $86.5 million in the corresponding period in 2009. This increase was due to a 13.6% increase in the average cost per KWH purchased reflecting higher fuel costs and a 49.3% increase in the volume of KWHs purchased due to higher KWH demand as a result of warmer weather in the third quarter 2010 as compared to the corresponding period in 2009.

For year-to-date 2010, purchased power expense from non-affiliates was $294.1 million compared to $219.2 million in the corresponding period in 2009. This increase was due to a 29.4% increase in the average cost per KWH purchased reflecting additional tolling agreements associated with PPAs that went into effect in June 2009, higher fuel costs, and a 14.3% increase in the volume of KWHs purchased due to higher KWH demand as a result of significantly colder weather in the first quarter 2010 and warmer weather in the second and third quarters 2010 as compared to the corresponding periods in 2009.

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

Affiliates

In the third quarter 2010, purchased power expense from affiliates was $142.5 million compared to $158.9 million in the corresponding period in 2009. This decrease was due to a 26.9% decrease in the average cost per KWH purchased following the expiration of a PPA in December 2009, partially offset by a 13.8% increase in the volume of KWHs purchased due to higher KWH demand.

For year-to-date 2010, purchased power expense from affiliates was $436.5 million compared to $528.5 million in the corresponding period in 2009. This decrease was due to a 15.1% decrease in the average cost per KWH purchased and a 3.8% decrease in the volume of KWHs purchased following the expiration of a PPA in December 2009.

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

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

Other Operations and Maintenance Expenses

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$76.1	21.2	$121.3	11.0

In the third quarter 2010, other operations and maintenance expenses were $434.9 million compared to $358.8 million in the corresponding period in 2009. This increase was due to increases of $34.2 million in power generation, $19.0 million in transmission and distribution, $14.8 million in administrative and general expenses, and $8.5 million in customer accounting, service, and sales primarily due to cost containment efforts in 2009 as a result of economic conditions and higher generation levels to meet increased customer demand in 2010.

For year-to-date 2010, other operations and maintenance expenses were $1.2 billion compared to $1.1 billion in the corresponding period in 2009. This increase was due to increases of $80.0 million in power generation and $39.1 million in transmission and distribution due to cost containment efforts in 2009 as a result of economic conditions and higher generation levels to meet increased customer demand in 2010.

Depreciation and Amortization

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$59.1	48.2	$(38.8)	(8.4)

In the third quarter 2010, depreciation and amortization was $181.8 million compared to $122.7 million in the corresponding period in 2009. This increase was due to the amortization of $5.0 million in the third quarter 2010 compared to $54.0 million for the corresponding period in 2009 of the regulatory liability related to the other cost of removal obligations as authorized by the Georgia PSC and depreciation on additional plant in service related to transmission, distribution, and environmental projects.

For year-to-date 2010, depreciation and amortization was $426.1 million compared to $464.9 million in the corresponding period in 2009. This decrease was due to the amortization of $119.3 million for year-to-date 2010 compared to $54.0 million for the corresponding period in 2009 of the regulatory liability related to the other cost of removal obligations, as authorized by the Georgia PSC, partially offset by depreciation on additional plant in service related to transmission, distribution, and environmental projects.

See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Georgia PSC Matters – Rate Plans” herein for additional information on the amortization of the other cost of removal regulatory liability, which became effective in July 2009.

Taxes Other Than Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$12.1	14.0	$20.5	8.4

In the third quarter 2010, taxes other than income taxes were $98.7 million compared to $86.6 million in the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $264.4 million compared to $243.9 million in the corresponding period in 2009. These increases were due to higher municipal franchise fees resulting from increased retail revenues in the third quarter and year-to-date 2010.

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

Allowance for Equity Funds Used During Construction

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$10.8	46.7	$38.4	58.0

In the third quarter 2010, AFUDC equity was $34.0 million compared to $23.2 million in the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $104.7 million compared to $66.3 million in the corresponding period in 2009. These increases were due to the increase in construction related to three new combined cycle units at Plant McDonough, two new nuclear generating units at Plant Vogtle, and ongoing environmental and transmission projects.

Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$7.9	3.7	$54.8	14.5

In the third quarter 2010, income taxes were $223.6 million compared to $215.7 million in the corresponding period in 2009. This increase was due to higher pre-tax earnings, partially offset by the intra-period tax allocation impact, which maintains an effective tax rate each quarter consistent with the estimated annual effective tax rate. The estimated annual effective tax rate declined from 2009 to 2010 primarily as a result of increased state investment tax credits.

For year-to-date 2010, income taxes were $432.8 million compared to $378.0 million in the corresponding period in 2009. This increase was due to higher pre-tax earnings, partially offset by a decrease in uncertain tax positions related to state income tax credits that remain subject to litigation and an increase in non-taxable AFUDC equity and state investment tax credits.

See FUTURE EARNINGS POTENTIAL – “Income Tax Matters” herein and Notes 3 and 5 to the financial statements of Georgia Power under “Income Tax Matters” and “Unrecognized Tax Benefits,” respectively, in Item 8 of the Form 10-K, Note (B) to the Condensed Financial Statements under “Income Tax Matters – Georgia State Income Tax Credits” herein, and Note (G) to the Condensed Financial Statements under “Effective Tax Rate” and “Unrecognized Tax Benefits” herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power’s future earnings potential. The level of Georgia Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include Georgia Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power’s service area. Changes in economic conditions impact sales for Georgia Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

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

Environmental Matters

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

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA alleging that Georgia Power and Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of their coal-fired generating facilities. The action against Georgia Power has been administratively closed since 2001, and the case has not been reopened. Georgia Power is not a party to the case involving Alabama Power. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims in the case against Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.

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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.

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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 information regarding the Industrial Boiler Maximum Achievable Control Technology regulations. On April 29, 2010, the EPA issued a proposed rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers. The EPA is required to finalize the rules by January 16, 2011. The impact of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time.

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 information regarding proposed sulfur dioxide (SO₂) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO₂, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO₂) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Georgia Power’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO₂ standard could result in significant additional compliance and operational costs for units that require new source permitting.

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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Georgia, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Georgia, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

These regulations could result in significant additional compliance and operational 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.

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Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Georgia Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.

The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Georgia Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational 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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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 and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational 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. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.

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Georgia PSC Matters

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 information regarding Georgia Power’s fuel cost recovery. As of September 30, 2010, Georgia Power had a total under recovered fuel cost balance of approximately $488 million compared to $665 million at December 31, 2009. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.

On March 11, 2010, the Georgia PSC voted to approve the stipulation among Georgia Power, the Georgia PSC Staff, and three customer groups with the exception that the under recovered fuel balance be collected over 42 months. The new rates, which became effective April 1, 2010, will result in an increase of approximately $373 million to Georgia Power’s total annual fuel cost recovery billings. Georgia Power is required to file its next fuel case by March 1, 2011.

Rate Plans

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

On August 27, 2009, the Georgia PSC approved an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail return on equity (ROE). In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. From July 1, 2009 through September 30, 2010, Georgia Power had amortized $161 million of the regulatory liability. Georgia Power currently expects to amortize approximately $40 million of the regulatory liability in the fourth quarter 2010; however, the final amount is subject to the limitations described previously and cannot be determined at this time.

In accordance with the 2007 Retail Rate Plan, Georgia Power filed a base rate case with the Georgia PSC on July 1, 2010. The filing includes a requested rate increase totaling $615 million, or 8.2% of retail revenues, to be effective January 1, 2011 based on a proposed retail ROE of 11.95%. The requested increase will be recovered through Georgia Power’s existing base rate tariffs as follows: $451 million, or 6.0%, through the traditional base rate tariffs; $115 million, or 1.5%, through the Environmental Compliance Cost Recovery (ECCR) tariff; $32 million through the Demand Side Management (DSM) tariffs; and $17 million through the Municipal Franchise Fee (MFF) tariff. The majority of the increase in retail revenues is being requested to cover the costs of environmental compliance and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. The remainder of the increase includes recovery of higher operation, maintenance, and other investment costs to meet the current and future demand for electricity.

Unlike rate plans based on traditional one-year test periods, the 2007 Retail Rate Plan was designed to operate for the three-year period ending December 31, 2010. The 2010 rate case request includes proposed enhancements to the structure of the 2007 Retail Rate Plan to fit the current economic climate, including a process of annual tariff compliance reviews that would allow it to continue to operate for multiple years (Proposed Alternate Rate Plan). The primary points of the Proposed Alternate Rate Plan include:

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§	Continuation of a plus or minus 100 basis point range for ROE.
§	Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.
	The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.
§	Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.
§	Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.
§	Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.

These proposed enhancements would become effective in 2012 with revenue requirements for each tariff updated through separate compliance filings based on Georgia Power’s budget for the upcoming year. Based on Georgia Power’s 2010 budget, earnings are currently projected to be slightly below the proposed ROE band in 2012 and within the band in 2013. However, updated budgets and revenue forecasts may eliminate, increase, or decrease the need for an ACR tariff adjustment in either year. In addition, Georgia Power currently estimates the ECCR tariff would increase by $120 million in 2012 and would decrease by $12 million in 2013. The CCCR tariff would begin recovering the costs of Plant McDonough Units 4, 5, and 6 with increases of $99 million in February 2012, $77 million in June 2012, and $76 million in February 2013. The DSM tariffs would increase by $17 million in 2012 and $18 million in 2013 to reflect the terms of the stipulated agreement in Georgia Power’s 2010 DSM Certification proceeding. Amounts recovered under the MFF tariff are based on amounts recovered under all other tariffs.

Hearings on Georgia Power’s direct testimony were held in October 2010. In direct testimony filed on October 22, 2010, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period that would result in a proposed increase of $436 million in 2011 using a 10.5% ROE. The Georgia PSC Staff recommendation would also allow additional increases of $181 million and $88 million in 2012 and 2013, respectively, to recover the costs associated with Plant McDonough Units 4, 5, and 6. These additional increases would be recovered through Georgia Power’s traditional base rate tariffs. While supporting the proposed DSM and MFF tariffs, the Georgia PSC Staff recommended against approval of the proposed ECCR, CCCR, and ACR tariffs. Georgia Power disagrees with the Georgia PSC Staff’s positions. Hearings on the Georgia PSC Staff and intervenor direct testimony will be held in November 2010. Georgia Power’s rebuttal hearings will occur in early December 2010. The Georgia PSC is scheduled to issue a final order in this matter on December 21, 2010.

The final outcome of these matters cannot now be determined.

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Legislation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Georgia Power in Item 7 of the Form 10-K for additional information.

Healthcare Reform

On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Georgia Power has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Georgia Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Georgia Power cannot be determined at this time.

Stimulus Funding

On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. Georgia Power will receive, and will match, $51 million under this agreement.

Income Tax Matters

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power had 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. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia Department of Revenue has appealed to the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Georgia Power’s cash flow. See Note 5 to the financial statements of Georgia Power under “Unrecognized Tax Benefits” in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot now be determined.

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Tax Method of Accounting for Repairs

Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $110 million for Georgia Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Bonus Depreciation

On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Georgia Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $130 million.

Construction

Nuclear

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” of Georgia Power in Item 7 of the Form 10-K for information regarding construction of two additional nuclear generating units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4).

In June 2009, the Southern Alliance for Clean Energy (SACE) 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 Financing Act. On May 5, 2010, the court dismissed as premature the plaintiffs’ claim challenging the Georgia Nuclear Energy Financing Act. The dismissal of the claim related to the Georgia Nuclear Energy Financing Act is subject to appeal and the plaintiffs are expected to re-file this claim in the future. In addition, on May 5, 2010, the court issued an order remanding the Georgia PSC’s certification order for inclusion of further findings of fact and conclusions of law by the Georgia PSC. In compliance with the court’s order, the Georgia PSC issued its order on remand to include further findings of fact and conclusions of law on June 23, 2010. On July 5, 2010, the SACE and the Fulton County Taxpayers Foundation, Inc. filed separate motions with the Georgia PSC for reconsideration of the order on remand. On August 17, 2010, the Georgia PSC voted to reaffirm its order. The SACE subsequently appealed to the Superior Court of Fulton County.

In August 2009 and June 2010, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors in response to 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.

On August 17, 2010, the Georgia PSC voted to approve Georgia Power’s semi-annual construction monitoring report including all construction and capital costs of $583 million made on Plant Vogtle Units 3 and 4 through December 31,

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2009. The Georgia PSC also approved an amendment to the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 that replaced certain index-based adjustments with fixed escalation factors. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost Recovery tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act. The filing includes a rate increase of approximately $218 million to recover financing costs associated with the construction of Plant Vogtle Units 3 and 4, effective January 1, 2011.

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 be determined at this time.

Other

In August 2009, Georgia Power filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. In September 2009, Georgia Power amended the report. As amended, the report included a request for an increase in the certified costs to construct Plant McDonough. On February 24, 2010, Georgia Power reached a stipulation agreement with the Georgia PSC staff that was approved by the Georgia PSC on March 16, 2010. The stipulation resolved the June 30, 2009 construction monitoring report, including the approval of actual expenditures and the requested increase in the certified amount.

On May 6, 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. In addition, on September 7, 2010, the Georgia PSC approved the March 31, 2010 construction monitoring report including actual project expenditures incurred through March 31, 2010.

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 and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Georgia Power’s financial statements.

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

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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, Unbilled Revenues, and Pension and Other Postretirement Benefits.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Georgia Power’s financial condition remained stable at September 30, 2010. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $1.7 billion for the first nine months of 2010, compared to $1.1 billion for the corresponding period in 2009. The $574.7 million increase in cash provided from operating activities in the first nine months of 2010 is primarily due to a $196.3 million increase in net income, fuel inventory reductions in 2010, and an increase in deferred income taxes primarily due to the change in the tax accounting method for repair costs as previously discussed. Net cash used for investing activities totaled $1.7 billion for the first nine months of 2010 and 2009 primarily due to gross property additions to utility plant. Net cash provided from financing activities totaled $535.3 million for the first nine months of 2010, compared to $497.7 million for the corresponding period in 2009. The $37.6 million increase is primarily due to higher issuance of long-term debt in 2010 partially offset by higher common stock dividends in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2010 include an increase of $1.2 billion in total property, plant, and equipment and an increase in paid in capital of $689.4 million reflecting equity contributions from Southern Company.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of 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, interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $874.8 million will be required through September 30, 2011 to fund maturities and announced repurchases of long-term debt. Georgia Power met its obligations to repurchase $462.5 million in pollution control revenue bonds subsequent to September 30, 2010 with a portion of its current cash and cash equivalents balance at September 30, 2010. No mandatory contributions to Georgia Power’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. 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

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projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; 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 prevailing market conditions, regulatory approval, 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.

On June 18, 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined construction and operating license for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.

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, 2010 cash and cash equivalents of approximately $589.8 million and unused committed credit arrangements with banks of approximately $1.7 billion. Of the cash and cash equivalents, approximately $574 million was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $595 million expire in 2011 and $1.1 billion expire in 2012. Of the credit arrangements that expire in 2011, $40 million contain provisions allowing two-year term loans executable at expiration and $220 million contain provisions allowing one-year term loans executable at expiration. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Georgia Power’s commercial paper program at September 30, 2010, and approximately $901 million was dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Subsequent to September 30, 2010, purchase obligations related to variable rate pollution control revenue bonds outstanding were reduced to $438 million as described under “Financing Activities” herein. See Note 6 to the financial statements of Georgia Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At September 30, 2010, Georgia Power had no commercial paper outstanding. During the third quarter 2010, Georgia Power had an average of $120 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $283 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

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Credit Rating Risk

Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At September 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $27 million. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.4 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.

On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch ratings of Georgia Power’s preferred stock, preference stock, and long-term debt payable to affiliated trusts decreased from A to A-. These ratings are not applicable to the collateral requirements described above.

On August 12, 2010, Moody’s downgraded the issuer and long-term debt ratings of Georgia Power (senior unsecured to A3 from A2). Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of Southern Company subsidiaries (including Georgia Power) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of Georgia Power to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of Georgia Power (to Baa2 from Baa1). Moody’s also downgraded the trust preferred securities rating of Georgia Power to Baa1 from A3. Moody’s announced that the ratings outlook for Georgia Power is stable.

Market Price Risk

Georgia Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 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 had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.

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

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2010 were as follows:

	Third Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(93	)	$	(75	)
Contracts realized or settled		19			69
Current period changes(a)		(47	)		(115	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(121	)	$	(121	)

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

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 was a decrease of $28 million and a decrease of $46 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At September 30, 2010, Georgia Power had a net hedge volume of 61 million mmBtu with a weighted average contract cost of approximately $1.99 per mmBtu above market prices, compared to 67 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $1.40 per mmBtu above market prices and compared to 65 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.16 per mmBtu above market prices. The natural gas hedges are recovered through the fuel cost recovery mechanism.

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

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.

Georgia Power uses over-the-counter contracts that are not exchange-traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:

	September 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(121	)		(84	)		(37	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(121	)	$	(84	)	$	(37	)	$	—

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 Note 1 under “Financial Instruments” and Note 11 to the financial statements of Georgia Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

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

Financing Activities

In March 2010, Georgia Power issued $350 million aggregate principal amount of Series 2010A Floating Rate Senior Notes due March 15, 2013. The net proceeds were used to repay at maturity $250 million aggregate principal amount of Series 2008A Floating Rate Senior Notes due March 17, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program.

In June 2010, Georgia Power issued $600 million aggregate principal amount of Series 2010B 5.40% Senior Notes due June 1, 2040. The net proceeds from the sale of the Series 2010B Senior Notes were used for the redemption of all of the $200 million aggregate principal amount of Georgia Power’s Series R 6.00% Senior Notes due October 15, 2033 and all of the $150 million aggregate principal amount of Georgia Power’s Series O 5.90% Senior Notes due April 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program.

In September 2010, Georgia Power issued $500 million aggregate principal amount Series 2010C 4.75% Senior Notes due September 1, 2040. The net proceeds were used to redeem all of the $250 million aggregate principal amount of Georgia Power’s Series X 5.70% Senior Notes due January 15, 2045, $125 million aggregate principal amount of Georgia Power’s Series W 6% Senior Notes due August 15, 2044, $100 million aggregate principal amount of Georgia Power’s Series T 5.75% Senior Public Income Notes due January 15, 2044, and $35 million aggregate principal amount of Savannah Electric and Power Company’s (Savannah Electric) Series G 5.75% Senior Notes due December 1, 2044 (which were assumed by Georgia Power upon its merger with Savannah Electric).

Also in September 2010, Georgia Power issued $500 million aggregate principal amount Series 2010D 1.30% Senior Notes due September 15, 2013. Subsequent to September 30, 2010, the net proceeds were used for the repurchase of all of the $114.3 million aggregate principal amount of outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Plant Vogtle Project), First Series 2009, due January 1, 2049; $40 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Plant Scherer Project), First Series 2009, due January 1, 2049; $173 million aggregate principal amount of the outstanding Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Plant Bowen Project), First Series 2009, due December 1, 2032; $89.2 million aggregate principal amount of the outstanding Development Authority of Monroe County Pollution Control Revenue Bonds (Georgia Power Plant Scherer Project), Second Series 2009, due October 1, 2048; and $46 million aggregate principal amount of the outstanding Development Authority of Burke County Pollution Control Revenue Bonds (Georgia Power Plant Vogtle Project), First Series 1996, due October 1, 2032, and for other general corporate purposes, including Georgia Power’s continuous construction program. The pollution control revenue bonds repurchased by Georgia Power are being held by Georgia Power and may be remarketed to investors in the future.

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.

84

GULF POWER COMPANY

85

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	396,671		$	329,597		$	1,021,530		$	858,038
Wholesale revenues, non-affiliates		31,211			25,752			86,041			70,418
Wholesale revenues, affiliates		37,995			3,661			88,386			19,748
Other revenues		17,578			18,631			47,381			54,816
Total operating revenues		483,455			377,641			1,243,338			1,003,020
Operating Expenses:
Fuel		237,003			163,302			585,167			435,050
Purchased power, non-affiliates		12,771			9,991			34,615			20,480
Purchased power, affiliates		20,282			29,399			51,725			58,020
Other operations and maintenance		67,178			57,422			202,202			194,896
Depreciation and amortization		34,032			23,452			90,651			69,828
Taxes other than income taxes		29,293			26,683			78,586			72,120
Total operating expenses		400,559			310,249			1,042,946			850,394
Operating Income		82,896			67,392			200,392			152,626
Other Income and (Expense):
Allowance for equity funds used during construction		1,424			6,810			4,504			17,335
Interest income		31			129			87			423
Interest expense, net of amounts capitalized		(13,764	)		(9,264	)		(38,286	)		(29,003	)
Other income (expense), net		(471	)		(266	)		(1,355	)		(1,369	)
Total other income and (expense)		(12,780	)		(2,591	)		(35,050	)		(12,614	)
Earnings Before Income Taxes		70,116			64,801			165,342			140,012
Income taxes		25,658			22,042			60,166			45,341
Net Income		44,458			42,759			105,176			94,671
Dividends on Preference Stock		1,551			1,551			4,652			4,652
Net Income After Dividends on Preference Stock	$	42,907		$	41,208		$	100,524		$	90,019

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2010		2009			2010			2009
	(in thousands)					(in thousands)
Net Income After Dividends on Preference Stock	$	42,907	$	41,208		$	100,524		$	90,019
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(414), $(542), and $(414), respectively		—		(659	)		(863	)		(659	)
Reclassification adjustment for amounts included in net income, net of tax of $90, $105, $286, and $314, respectively		143		166			455			500
Total other comprehensive income (loss)		143		(493	)		(408	)		(159	)
Comprehensive Income	$	43,050	$	40,715		$	100,116		$	89,860

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	105,176		$	94,671
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		95,491			74,407
Deferred income taxes		55,355			(2,177	)
Allowance for equity funds used during construction		(4,504	)		(17,335	)
Pension, postretirement, and other employee benefits		2,883			1,123
Stock based compensation expense		959			793
Hedge settlements		1,530			—
Other, net		1,040			(4,009	)
Changes in certain current assets and liabilities —
-Receivables		(67,814	)		40,388
-Fossil fuel stock		29,483			(54,511	)
-Materials and supplies		(1,363	)		(1,411	)
-Prepaid income taxes		(9,558	)		416
-Property damage cost recovery		34			10,831
-Other current assets		2,667			2,178
-Accounts payable		12,003			(13,022	)
-Accrued taxes		18,166			14,593
-Accrued compensation		2,695			(7,364	)
-Other current liabilities		10,776			8,627
Net cash provided from operating activities		255,019			148,198
Investing Activities:
Property additions		(203,911	)		(330,776	)
Investment in restricted cash from pollution control revenue bonds		—			(49,188	)
Distribution of restricted cash from pollution control revenue bonds		6,347			28,144
Cost of removal, net of salvage		(750	)		(6,758	)
Construction payables		(17,792	)		(11,721	)
Payments pursuant to long-term service agreements		(4,211	)		(5,462	)
Other investing activities		(295	)		17
Net cash used for investing activities		(220,612	)		(375,744	)
Financing Activities:
Decrease in notes payable, net		(88,733	)		(101,589	)
Proceeds —
Common stock issued to parent		50,000			135,000
Capital contributions from parent company		3,571			3,461
Pollution control revenue bonds		21,000			130,400
Senior notes		300,000			140,000
Redemptions —
Senior notes		(140,413	)		(1,033	)
Payment of preference stock dividends		(4,652	)		(4,652	)
Payment of common stock dividends		(78,225	)		(66,975	)
Other financing activities		(3,280	)		(1,613	)
Net cash provided from financing activities		59,268			232,999
Net Change in Cash and Cash Equivalents		93,675			5,453
Cash and Cash Equivalents at Beginning of Period		8,677			3,443
Cash and Cash Equivalents at End of Period	$	102,352		$	8,896
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $1,795 and $6,909 capitalized for 2010 and 2009, respectively)	$	28,394		$	29,123
Income taxes (net of refunds)	$	13,862		$	43,423

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	102,352		$	8,677
Restricted cash and cash equivalents		—			6,347
Receivables —
Customer accounts receivable		98,295			64,257
Unbilled revenues		64,894			60,414
Under recovered regulatory clause revenues		18,606			4,285
Other accounts and notes receivable		7,748			4,107
Affiliated companies		17,832			7,503
Accumulated provision for uncollectible accounts		(2,226	)		(1,913	)
Fossil fuel stock, at average cost		153,230			183,619
Materials and supplies, at average cost		40,049			38,478
Other regulatory assets, current		23,560			19,172
Prepaid expenses		29,874			44,760
Other current assets		927			3,634
Total current assets		555,141			443,340
Property, Plant, and Equipment:
In service		3,552,116			3,430,503
Less accumulated provision for depreciation		1,052,758			1,009,807
Plant in service, net of depreciation		2,499,358			2,420,696
Construction work in progress		227,643			159,499
Total property, plant, and equipment		2,727,001			2,580,195
Other Property and Investments		16,219			15,923
Deferred Charges and Other Assets:
Deferred charges related to income taxes		44,947			39,018
Other regulatory assets, deferred		221,691			190,971
Other deferred charges and assets		31,940			24,160
Total deferred charges and other assets		298,578			254,149
Total Assets	$	3,596,939		$	3,293,607

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

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GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2010			2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	185,000		$	140,000
Notes payable		—			90,331
Accounts payable —
Affiliated		59,361			47,421
Other		66,993			80,184
Customer deposits		35,695			32,361
Accrued taxes —
Accrued income taxes		2,816			1,955
Other accrued taxes		25,319			7,297
Accrued interest		14,959			10,222
Accrued compensation		12,032			9,337
Other regulatory liabilities, current		31,597			22,416
Liabilities from risk management activities		12,807			9,442
Other current liabilities		21,335			20,092
Total current liabilities		467,914			471,058
Long-term Debt		1,112,478			978,914
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		353,886			297,405
Accumulated deferred investment tax credits		8,495			9,652
Employee benefit obligations		110,708			109,271
Other cost of removal obligations		199,154			191,248
Other regulatory liabilities, deferred		42,481			41,399
Other deferred credits and liabilities		122,754			92,370
Total deferred credits and other liabilities		837,478			741,345
Total Liabilities		2,417,870			2,191,317
Preference Stock		97,998			97,998
Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - September 30, 2010: 3,642,717 shares
- December 31, 2009: 3,142,717 shares		303,060			253,060
Paid-in capital		539,466			534,577
Retained earnings		241,415			219,117
Accumulated other comprehensive loss		(2,870	)		(2,462	)
Total common stockholder’s equity		1,081,071			1,004,292
Total Liabilities and Stockholder’s Equity	$	3,596,939		$	3,293,607

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

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GULF POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009

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 given current economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. 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

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$1.7	4.1	$10.5	11.7

Gulf Power’s net income after dividends on preference stock for the third quarter 2010 was $42.9 million compared to $41.2 million for the corresponding period in 2009. The increase was primarily due to warmer weather in the third quarter 2010.

Gulf Power’s net income after dividends on preference stock for year-to-date 2010 was $100.5 million compared to $90.0 million for the corresponding period in 2009. The increase was primarily due to significantly colder weather in the first quarter 2010 and warmer weather in the third quarter 2010.

Retail Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$67.1	20.4	$163.5	19.1

In the third quarter 2010, retail revenues were $396.7 million compared to $329.6 million for the corresponding period in 2009. For year-to-date 2010, retail revenues were $1,021.5 million compared to $858.0 million for the corresponding period in 2009.

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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
	2010				2010
	(in millions)		(% change)		(in millions)			(% change)
Retail – prior year	$	329.6			$	858.0
Estimated change in –
Rates and pricing		22.2		6.7		56.0			6.5
Sales growth (decline)		0.8		0.3		(2.8	)		(0.2	)
Weather		6.5		2.0		18.3			2.1
Fuel and other cost recovery		37.6		11.4		92.0			10.7
Retail – current year	$	396.7		20.4	$	1,021.5			19.1

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2010 when compared to the corresponding periods in 2009 primarily due to revenues associated with higher projected environmental compliance costs in 2010.

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

Revenues attributable to changes in sales increased in the third quarter 2010 when compared to the corresponding period in 2009. KWH energy sales to industrial customers increased 5.2% primarily due to an increase in production for one large customer. Weather-adjusted KWH energy sales to commercial customers increased 3.0% primarily due to increased sales to certain large customers. Weather-adjusted KWH energy sales to residential customers remained flat.

Revenues attributable to changes in sales decreased for year-to-date 2010 when compared to the corresponding period in 2009. The decrease was primarily due to a decrease in KWH usage in the residential class. KWH energy sales to industrial customers and weather-adjusted KWH energy sales to commercial customers remained relatively flat.

Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the third quarter 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.

Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2010 when compared to the corresponding periods for 2009 primarily due to higher fuel and purchased power expenses in the third quarter of 2010. 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 effect on net income. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Retail Regulatory Matters” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and “Property Damage Reserve” and Note 3 to the financial

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

statements of Gulf Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$5.4	21.2	$15.6	22.2

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 and Georgia utilities. Revenues from these contracts have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

In the third quarter 2010, wholesale revenues from non-affiliates were $31.2 million compared to $25.8 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to an 8.1% increase in KWH energy sales to serve weather-related increases in non-territorial demand and a 6.8% increase in price related to energy rates.

For year-to-date 2010, wholesale revenues from non-affiliates were $86.0 million compared to $70.4 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to an 11.8% increase in KWH energy sales to serve weather-related increases in non-territorial demand and a 9.0% increase in price related to energy rates.

Wholesale Revenues – Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$34.4	937.8	$68.7	347.6

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 2010, wholesale revenues from affiliates were $38.0 million compared to $3.6 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 661.7% increase in KWH energy sales resulting from the dispatch of available Gulf Power resources to serve affiliate demand and a 36.3% increase in price related to energy rates.

For year-to-date 2010, wholesale revenues from affiliates were $88.4 million compared to $19.7 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 257.8% increase in KWH energy sales resulting from the dispatch of available Gulf Power resources to serve affiliate demand and a 25.1% increase in price related to energy rates.

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

Other Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(1.0)	(5.7)	$(7.4)	(13.6)

In the third quarter 2010, other revenues were $17.6 million compared to $18.6 million for the corresponding period in 2009. The decrease was primarily due to a $2.0 million decrease in revenues from other energy services, partially offset by higher franchise fees of $1.0 million.

For year-to-date 2010, other revenues were $47.4 million compared to $54.8 million for the corresponding period in 2009. The decrease was primarily due to a $9.7 million decrease in revenues from other energy services, partially offset by higher franchise fees of $2.4 million.

The decreased revenues from other energy services did not have a significant effect on net income since they were generally offset by related expenses. Franchise fees have no impact on net income.

Fuel and Purchased Power Expenses

	Third Quarter 2010						Year-to-Date 2010
	vs.						vs.
	Third Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	73.7			45.1		$	150.2			34.5
Purchased power – non-affiliates		2.8			27.8			14.1			69.0
Purchased power – affiliates		(9.1	)		(31.0	)		(6.3	)		(10.8	)
Total fuel and purchased power expenses	$	67.4					$	158.0

* 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 2010, total fuel and purchased power expenses were $270.0 million compared to $202.6 million for the corresponding period in 2009. The net increase in fuel and purchased power expenses was due to a $47.0 million increase related to total KWHs generated and purchased and a $20.4 million increase in the average cost of fuel and purchased power.

For year-to-date 2010, total fuel and purchased power expenses were $671.5 million compared to $513.5 million for the corresponding period in 2009. The net increase in fuel and purchased power expenses was due to a $116.9 million increase related to total KWHs generated and purchased and a $41.1 million increase as a result of an increase in the average cost of fuel and purchased power.

Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power’s fuel cost recovery and purchased power capacity cost recovery clauses. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Retail Regulatory Matters” herein for additional information. See also MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Purchased Power Capacity Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Purchased Power Capacity Recovery” in Item 8 of the Form 10-K for additional information.

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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	2010		2009		Change			2010		2009		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		5.09		4.59		10.9			5.04		4.46		13.0
Purchased power		7.93		7.98		(0.6	)		5.99		6.78		(11.7	)

In the third quarter 2010, fuel expense was $237.0 million compared to $163.3 million for the corresponding period in 2009. The increase was primarily due to a 16.4% increase in the average cost of coal and an 18.4% increase in KWHs generated as a result of increased demand, partially offset by a 4.4% decrease in the average cost of natural gas prices.

For year-to-date 2010, fuel expense was $585.2 million compared to $435.0 million for the corresponding period in 2009. The increase was primarily due to an 18.6% increase in the average cost of coal and a 7.4% increase in KWHs generated as a result of increased demand.

Non-Affiliates

In the third quarter 2010, purchased power expense from non-affiliates was $12.7 million compared to $9.9 million for the corresponding period in 2009. The increase was primarily due to a 752.9% increase in the volume of KWHs purchased, which was primarily due to a PPA which began in the fourth quarter 2009, partially offset by a 64.9% decrease in the average cost per KWH purchased.

For year-to-date 2010, purchased power expense from non-affiliates was $34.6 million compared to $20.5 million for the corresponding period in 2009. The increase was primarily due to a 576.9% increase in the volume of KWHs purchased, which was primarily due to a PPA which began in the fourth quarter 2009, partially offset by a 42.2% decrease in the average cost per KWH purchased.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Purchased Power Capacity Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Purchased Power Capacity Recovery” in Item 8 of the Form 10-K for additional information regarding the PPA that began in the fourth quarter 2009.

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

Affiliates

In the third quarter 2010, purchased power expense from affiliates was $20.3 million compared to $29.4 million for the corresponding period in 2009. The decrease was primarily due to a 74.9% decrease in the volume of KWHs purchased, partially offset by a 204.7% increase in the average cost per KWH purchased.

For year-to-date 2010, purchased power expense from affiliates was $51.7 million compared to $58.0 million for the corresponding period in 2009. The decrease was primarily due to a 31.0% decrease in the volume of KWHs purchased, partially offset by a 35.7% increase in the average cost per KWH purchased.

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

Other Operations and Maintenance Expenses

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$9.8	17.0	$7.3	3.7

In the third quarter 2010, other operations and maintenance expenses were $67.2 million compared to $57.4 million for the corresponding period in 2009. The increase was primarily due to increases in maintenance expense and labor.

For year-to-date 2010, other operations and maintenance expenses were $202.2 million compared to $194.9 million for the corresponding period in 2009. The increase was primarily due to increases in maintenance expense and labor, partially offset by a decrease in storm recovery costs.

Depreciation and Amortization

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$10.5	45.1	$20.8	29.8

In the third quarter 2010, depreciation and amortization was $34.0 million compared to $23.5 million for the corresponding period in 2009. For year-to-date 2010, depreciation and amortization was $90.6 million compared to $69.8 million for the corresponding period in 2009. These increases were primarily due to the addition of an environmental control project at Plant Crist being placed into service in December 2009 and other net additions to generation.

Taxes Other Than Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$2.6	9.8	$6.5	9.0

In the third quarter 2010, taxes other than income taxes were $29.3 million compared to $26.7 million for the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $78.6 million compared to $72.1 million for the corresponding period in 2009. These increases were primarily due to increases in property taxes, gross receipt taxes, and franchise fees. Gross receipt taxes and franchise fees have no impact on net income.

Allowance for Equity Funds Used During Construction

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(5.4)	(79.1)	$(12.8)	(74.0)

In the third quarter 2010, AFUDC equity was $1.4 million compared to $6.8 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $4.5 million compared to $17.3 million for the corresponding period in 2009. These decreases were primarily due to an environmental control project at Plant Crist being placed into service in December 2009.

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Interest Expense, Net of Amounts Capitalized

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$4.5	48.6	$9.3	32.0

In the third quarter 2010, interest expense, net of amounts capitalized was $13.8 million compared to $9.3 million for the corresponding period in 2009. For year-to-date 2010, interest expense, net of amounts capitalized was $38.3 million compared to $29.0 million for the corresponding period in 2009. These increases were primarily due to the change in capitalization of the AFUDC debt related to an environmental control project at Plant Crist being placed into service in December 2009 and an increase in long-term debt levels resulting from the issuance of additional senior notes in the first quarter 2010 to fund general corporate purposes, including Gulf Power’s continuous construction program.

Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$3.6	16.4	$14.8	32.7

In the third quarter 2010, income taxes were $25.7 million compared to $22.1 million for the corresponding period in 2009. For year-to-date 2010, income taxes were $60.1 million compared to $45.3 million for the corresponding period in 2009. These increases were primarily due to higher pre-tax earnings.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Gulf Power’s future earnings potential. The level of Gulf Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include Gulf Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power’s service area. Changes in economic conditions impact sales for Gulf Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.

Environmental Matters

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

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New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding notices of violation issued by the EPA relating to Gulf Power’s Plant Crist and a unit partially owned by Gulf Power at Plant Scherer and civil actions brought by the EPA against Alabama Power and Georgia Power alleging that these companies violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of their coal-fired generating facilities. Gulf Power is not a party to the cases involving Alabama Power and Georgia Power. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims in the case against Alabama Power, leaving only three claims for summary disposition or trial. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.

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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Gulf Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO₂) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO₂, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

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On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO₂) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Gulf Power’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO₂ standard could result in significant additional compliance and operational costs for units that require new source permitting.

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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Florida and Georgia, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Florida, Georgia, and Mississippi, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

These regulations could result in significant additional compliance and operational 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.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Gulf Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.

The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Gulf Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational 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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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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 and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational 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. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.

Florida PSC Matters

Retail Regulatory Matters

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In recent years, Gulf Power has experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and volatile price swings in natural gas. If, at anytime during the year, the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the year, 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, 2010 totaled $16.6 million, compared to $2.4 million at December 31, 2009. 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 changes in the billing factor will not have a significant effect on Gulf Power’s revenues or net income, but will affect cash flow.

In November 2010, the Florida PSC approved Gulf Power’s annual rate clause requests for its fuel, purchased power capacity, conservation, and environmental compliance cost recovery factors for 2011. The net effect of the approved changes is a 2.8% rate decrease for residential customers using 1,000 KWHs per month.

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

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Environmental Compliance Recovery

On July 22, 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million and is scheduled for completion in the fourth quarter 2014. Gulf Power’s portion of the cost, if approved by the Florida PSC, is expected to be recovered through its environmental compliance recovery clause. Hearings on the certificate request are scheduled to be held with the Mississippi PSC on January 25, 2011 with a final order expected by February 28, 2011. The final outcome of this matter cannot now be determined.

Legislation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Gulf Power in Item 7 of the Form 10-K for additional information.

Healthcare Reform

On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Gulf Power has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Gulf Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Gulf Power cannot be determined at this time.

Stimulus Funding

On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. Gulf Power will receive, and will match, $15.5 million under this agreement.

Income Tax Matters

Tax Method of Accounting for Repairs

Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $6 million for Gulf Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility

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industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Bonus Depreciation

On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Gulf Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $37 million.

Other Matters

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

The coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has not significantly impacted operations, but has had and may continue to have significant economic impacts on the affected areas within Gulf Power’s service territory.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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, Unbilled Revenues, and Pension and Other Postretirement Benefits.

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FINANCIAL CONDITION AND LIQUIDITY

Overview

Gulf Power’s financial condition remained stable at September 30, 2010. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.

Net cash provided from operating activities totaled $255.0 million for the first nine months of 2010 compared to $148.2 million for the corresponding period in 2009. The $106.8 million increase in cash provided from operating activities was primarily due to an increase in cash from fossil fuel stock resulting from an increase in generation and a decrease in cash payments related to fuel inventory as well as an increase in deferred income taxes related to fuel cost recovery. The increase was partially offset by a decrease in collections attributable to regulatory fuel clause revenues. Net cash used for investing activities totaled $220.6 million in the first nine months of 2010 compared to $375.7 million for the corresponding period in 2009. Net cash provided from financing activities totaled $59.3 million for the first nine months of 2010 compared to $233.0 million for the corresponding period in 2009. The decreases of $155.1 million in investing activities and $173.7 million in financing activities were primarily due to an environmental control project at Plant Crist being placed into service in December 2009. 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 2010 include increases in cash and cash equivalents of $93.7 million, customer accounts receivable of $34.0 million, and accumulated deferred income taxes of $56.5 million. Total property, plant, and equipment increased by $146.8 million, primarily due to environmental control projects. Notes payable decreased by $90.3 million. Securities due within one year increased by $45.0 million due to the redemption of long-term debt.

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, scheduled maturities of long-term debt, interest, derivative obligations, preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $185 million will be required through September 30, 2011 to fund maturities and announced redemptions of long-term debt. Gulf Power met its obligations to redeem $75 million in senior notes subsequent to September 30, 2010 with a portion of its current cash and cash equivalents balance at September 30, 2010. No mandatory contributions to Gulf Power’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

102

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

Sources of Capital

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

Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power had at September 30, 2010 cash and cash equivalents of approximately $102.3 million and unused committed credit arrangements with banks of $235 million. Of the cash and cash equivalents, approximately $12 million was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $50 million expire in 2010 and $185 million expire in 2011. Of these credit arrangements, $205 million contain provisions allowing one-year term loans executable at expiration. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. The 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. Subsequent to September 30, 2010, Gulf Power renewed an existing credit agreement totaling $30 million and increased an existing credit agreement by $5 million; both agreements contain provisions allowing a one-year term loan executable at expiration and extended the expiration date to 2011. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At September 30, 2010, Gulf Power had no commercial paper borrowings outstanding. During the third quarter 2010, Gulf Power had an average of $70 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $100 million. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At September 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $125 million. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $574 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.

103

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

On January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch rating of Gulf Power’s preferred and preference stock decreased from A- to BBB+. These ratings are not applicable to the collateral requirements described above.

On August 12, 2010, Moody’s downgraded the issuer and long-term debt ratings of Gulf Power (senior unsecured to A3 from A2). Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of Southern Company subsidiaries (including Gulf Power) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of Gulf Power to VMIG-2 from VMIG-1 and the preferred and preference stock ratings of Gulf Power (to Baa2 from Baa1). Moody’s announced that the ratings outlook for Gulf Power is stable.

Market Price Risk

Gulf Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 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 had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2010 were as follows:

	Third Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(15	)	$	(14	)
Contracts realized or settled		4			14
Current period changes(a)		(7	)		(18	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(18	)	$	(18	)

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

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 was a decrease of $3 million and a decrease of $4 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At September 30, 2010, Gulf Power had a net hedge volume of 14 million mmBtu with a weighted average contract cost of approximately $1.26 per mmBtu above market prices, compared to 9 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $1.61 per mmBtu above market prices and compared to 11 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.29 per mmBtu above market prices. Natural gas hedges are recovered through the fuel cost recovery clause.

104

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

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

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.

Gulf Power uses over-the-counter contracts that are not exchange-traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:

	September 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(18	)		(13	)		(5	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(18	)	$	(13	)	$	(5	)	$	—

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 Note 1 under “Financial Instruments” and Note 10 to the financial statements of Gulf Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

In the first nine months of 2010, Gulf Power issued to Southern Company 500,000 shares of common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of Gulf Power’s short-term debt and for other general corporate purposes.

In April 2010, Gulf Power issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 15, 2020. The net proceeds were used to repay at maturity $140 million aggregate principal amount of Series 2009A Floating Rate Senior Notes due June 28, 2010, to repay a portion of its outstanding short-term debt, and for general corporate purposes, including Gulf Power’s continuous construction program. Gulf Power settled $100 million of interest rate hedges related to the Series 2010A Senior Note issuance at a gain of approximately $1.5 million. The gain will be amortized to interest expense over 10 years.

In June 2010, Gulf Power incurred obligations in connection with the issuance of $21 million aggregate principal amount of the Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Plant Scherer Project), First Series 2010. The proceeds were used to fund pollution control and environmental improvement facilities at Plant Scherer.

In September 2010, Gulf Power issued $125 million aggregate principal amount of its Series 2010B 5.10% Senior Notes due October 1, 2040. The net proceeds were used to repay a portion of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power’s continuous construction program, and, subsequent to September 30, 2010, for the redemption of all of the $40 million aggregate principal amount of Gulf Power’s Series I 5.75% Senior

105

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

Notes due September 15, 2033 and $35 million aggregate principal amount of Gulf Power’s Series J 5.875% Senior Notes due April 1, 2044.

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.

106

MISSISSIPPI POWER COMPANY

107

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	230,977		$	231,894		$	620,658		$	608,761
Wholesale revenues, non-affiliates		78,409			81,242			223,499			235,089
Wholesale revenues, affiliates		13,025			13,404			31,636			30,785
Other revenues		4,672			4,140			11,749			11,449
Total operating revenues		327,083			330,680			887,542			886,084
Operating Expenses:
Fuel		154,607			148,115			388,979			393,912
Purchased power, non-affiliates		2,547			1,666			7,666			7,374
Purchased power, affiliates		10,902			21,946			60,113			65,346
Other operations and maintenance		65,953			61,138			205,055			182,500
Depreciation and amortization		20,106			17,707			57,567			53,382
Taxes other than income taxes		17,935			17,033			53,568			48,178
Total operating expenses		272,050			267,605			772,948			750,692
Operating Income		55,033			63,075			114,594			135,392
Other Income and (Expense):
Allowance for equity funds used during construction		1,490			—			2,018			387
Interest income		49			34			122			829
Interest expense, net of amounts capitalized		(4,886	)		(6,075	)		(17,011	)		(17,091	)
Other income (expense), net		1,099			474			3,272			2,852
Total other income and (expense)		(2,248	)		(5,567	)		(11,599	)		(13,023	)
Earnings Before Income Taxes		52,785			57,508			102,995			122,369
Income taxes		18,759			22,177			37,631			46,268
Net Income		34,026			35,331			65,364			76,101
Dividends on Preferred Stock		433			433			1,299			1,299
Net Income After Dividends on Preferred Stock	$	33,593		$	34,898		$	64,065		$	74,802

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2010		2009			2010		2009
	(in thousands)					(in thousands)
Net Income After Dividends on Preferred Stock	$	33,593	$	34,898		$	64,065	$	74,802
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $4, $(27), $8, and $-, respectively		7		(44	)		13		—
Comprehensive Income	$	33,600	$	34,854		$	64,078	$	74,802

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

108

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months
	Ended September 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	65,364		$	76,101
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		60,959			58,929
Deferred income taxes		(4,557	)		(27,430	)
Investment tax credits received		14,352			—
Allowance for equity funds used during construction		(2,018	)		(387	)
Pension, postretirement, and other employee benefits		6,657			5,817
Stock based compensation expense		1,053			822
Generation construction screening costs		(50,554	)		(21,955	)
Other, net		(720	)		618
Changes in certain current assets and liabilities —
-Receivables		(21,003	)		(6,482	)
-Under recovered regulatory clause revenues		—			54,994
-Fossil fuel stock		10,163			(42,838	)
-Materials and supplies		(222	)		(1,782	)
-Prepaid income taxes		—			1,061
-Other current assets		(2,503	)		(9,783	)
-Accounts payable		25,819			(26,354	)
-Accrued taxes		7,630			13,430
-Accrued compensation		427			(10,238	)
-Over recovered regulatory clause revenues		14,939			20,466
-Other current liabilities		(442	)		228
Net cash provided from operating activities		125,344			85,217
Investing Activities:
Property additions		(125,980	)		(72,661	)
Cost of removal, net of salvage		(7,613	)		(9,911	)
Construction payables		6,903			(3,949	)
Other investing activities		(6,693	)		(2,150	)
Net cash used for investing activities		(133,383	)		(88,671	)
Financing Activities:
Decrease in notes payable, net		—			(24,891	)
Proceeds —
Capital contributions from parent company		3,920			3,330
Senior notes issuances		—			125,000
Other long-term debt issuances		125,000			—
Redemptions —
Capital leases		(988	)		—
Senior notes		—			(40,000	)
Payment of preferred stock dividends		(1,299	)		(1,299	)
Payment of common stock dividends		(51,450	)		(51,375	)
Other financing activities		(614	)		(1,714	)
Net cash provided from financing activities		74,569			9,051
Net Change in Cash and Cash Equivalents		66,530			5,597
Cash and Cash Equivalents at Beginning of Period		65,025			22,413
Cash and Cash Equivalents at End of Period	$	131,555		$	28,010
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $1,482 and $117 capitalized for 2010 and 2009, respectively)	$	16,726		$	15,824
Income taxes (net of refunds)	$	11,345		$	48,008

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	131,555		$	65,025
Receivables —
Customer accounts receivable		45,923			36,766
Unbilled revenues		30,233			27,168
Other accounts and notes receivable		7,131			11,337
Affiliated companies		51,368			13,215
Accumulated provision for uncollectible accounts		(1,006	)		(940	)
Fossil fuel stock, at average cost		117,074			127,237
Materials and supplies, at average cost		28,014			27,793
Other regulatory assets, current		64,823			53,273
Prepaid income taxes		37,925			32,237
Other current assets		16,094			12,625
Total current assets		529,134			405,736
Property, Plant, and Equipment:
In service		2,370,635			2,316,494
Less accumulated provision for depreciation		975,536			950,373
Plant in service, net of depreciation		1,395,099			1,366,121
Construction work in progress		198,977			48,219
Total property, plant, and equipment		1,594,076			1,414,340
Other Property and Investments		6,120			7,018
Deferred Charges and Other Assets:
Deferred charges related to income taxes		13,638			8,536
Other regulatory assets, deferred		149,175			209,100
Other deferred charges and assets		30,767			27,951
Total deferred charges and other assets		193,580			245,587
Total Assets	$	2,322,910		$	2,072,681

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

110

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

	At September 30,		At December 31,
Liabilities and Stockholder’s Equity	2010		2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	206,409	$	1,330
Accounts payable —
Affiliated		58,410		49,209
Other		64,925		38,662
Customer deposits		12,142		11,143
Accrued taxes —
Accrued income taxes		25,823		10,590
Other accrued taxes		42,021		49,547
Accrued interest		4,405		5,739
Accrued compensation		14,212		13,785
Other regulatory liabilities, current		5,655		7,610
Over recovered regulatory clause liabilities		63,534		48,596
Liabilities from risk management activities		29,762		19,454
Other current liabilities		24,780		21,142
Total current liabilities		552,078		276,807
Long-term Debt		412,539		493,480
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		230,058		223,066
Deferred credits related to income taxes		12,121		13,937
Accumulated deferred investment tax credits		26,286		12,825
Employee benefit obligations		166,495		161,778
Other cost of removal obligations		107,615		97,820
Other regulatory liabilities, deferred		57,014		54,576
Other deferred credits and liabilities		49,214		47,090
Total deferred credits and other liabilities		648,803		611,092
Total Liabilities		1,613,420		1,381,379
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		331,122		325,562
Retained earnings		307,884		295,269
Accumulated other comprehensive income (loss)		13		—
Total common stockholder’s equity		676,710		658,522
Total Liabilities and Stockholder’s Equity	$	2,322,910	$	2,072,681

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

111

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009

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 given current economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Mississippi Power has various regulatory mechanisms that operate to address cost recovery. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

On June 3, 2010, the Mississippi PSC issued a certification of public convenience and necessity authorizing the acquisition, construction, and operation of a new electric generating plant located in Kemper County, Mississippi, which is scheduled to be placed into service in 2014.

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

RESULTS OF OPERATIONS

Net Income

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(1.3)	(3.7)	$(10.7)	(14.4)

Mississippi Power’s net income after dividends on preferred stock for the third quarter 2010 was $33.6 million compared to $34.9 million for the corresponding period in 2009. The decrease in net income after dividends on preferred stock for the third quarter 2010 was primarily due to a decrease in wholesale energy and capacity revenues from customers served outside Mississippi Power’s service territory and increases in operations and maintenance expenses and depreciation and amortization. The decrease in net income after dividends on preferred stock for the third quarter 2010 was partially offset by increases in AFUDC equity and territorial base revenues primarily resulting from warmer weather in the third quarter 2010 compared to the third quarter 2009 and a decrease in interest expense, net of amounts capitalized.

Mississippi Power’s net income after dividends on preferred stock for year-to-date 2010 was $64.1 million compared to $74.8 million for the corresponding period in 2009. The decrease in net income after dividends on preferred stock for year-to-date 2010 was primarily due to a decrease in wholesale energy and capacity revenues from customers served outside Mississippi Power’s service territory and increases in operations and maintenance expenses and depreciation and amortization. The decrease in net income after dividends on preferred stock for year-to-date 2010 was partially offset by increases in AFUDC equity and territorial base revenues primarily resulting from warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 compared to the corresponding period in 2009.

112

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

Retail Revenues

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(0.9)	(0.4)	$11.9	2.0

In the third quarter 2010, retail revenues were $231.0 million compared to $231.9 million for the corresponding period in 2009. For year-to-date 2010, retail revenues were $620.7 million compared to $608.8 million for the corresponding period in 2009.

Details of the change to retail revenues are as follows:

	Third Quarter						Year-to-Date
	2010						2010
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	231.9					$	608.8
Estimated change in —
Rates and pricing		—			—			0.2			—
Sales growth (decline)		(1.0	)		(0.5	)		(3.1	)		(0.5	)
Weather		3.9			1.7			13.2			2.2
Fuel and other cost recovery		(3.8	)		(1.6	)		1.6			0.3
Retail – current year	$	231.0			(0.4	)%	$	620.7			2.0	%

Revenues associated with changes in rates and pricing in the third quarter 2010 when compared to the corresponding period in 2009 were not material.

Revenues associated with changes in rates and pricing increased year-to-date 2010 when compared to the corresponding period in 2009 primarily due to an increase of $1.0 million related to the ECO Plan rate, partially offset by a decrease of $0.8 million related to System Restoration Rider (SRR) revenues pursuant to an order from the Mississippi PSC.

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 decreased in the third quarter 2010 when compared to the corresponding period in 2009. Weather-adjusted KWH energy sales to residential customers decreased 2.2% primarily due to the lack of growth in the number of residential customers in Mississippi Power’s service territory. KWH energy sales to industrial customers decreased 0.2% as a result of a change in operations for one of the larger industrial customers and a maintenance outage for another large customer.

Revenues attributable to changes in sales decreased for year-to-date 2010 when compared to the corresponding period in 2009. Weather-adjusted KWH energy sales to residential customers slightly increased due to increases in customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 3.0% primarily due to the declining number of commercial customers in Mississippi Power’s service territory. KWH energy sales to industrial customers increased 3.7% as a result of increased production for several large industrial customers due to improving economic conditions.

Revenues resulting from changes in weather increased in the third quarter 2010 as a result of warmer weather when compared to the corresponding period in 2009. For year-to-date 2010, revenues resulting from changes in weather increased as a result of warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.

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MISSISSIPPI 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 2010 when compared to the corresponding period in 2009 primarily as a result of lower recoverable fuel costs, partially offset by an increase in revenues related to ad valorem taxes. Fuel and other cost recovery revenues increased year-to-date 2010 when compared to the corresponding period in 2009 primarily as a result of an increase in revenues related to ad valorem taxes, partially offset by lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power’s service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(2.8)	(3.5)	$(11.6)	(4.9)

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 the availability of Southern Company system generation. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

In the third quarter 2010, wholesale revenues from non-affiliates were $78.4 million compared to $81.2 million for the corresponding period in 2009. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $5.0 million, partially offset by a $2.2 million increase in revenues from customers inside Mississippi Power’s service territory. The $5.0 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $6.3 million decrease in sales volume, partially offset by a $1.2 million increase associated with higher prices resulting from the higher marginal cost of fuel and a $0.1 million increase in capacity revenues. The $2.2 million increase in revenues from customers inside Mississippi Power’s service territory was primarily due to a $0.1 million increase in fuel revenues and a $2.1 million increase in wholesale base revenues resulting from warmer weather in the third quarter 2010 when compared to the corresponding period in 2009.

For year-to-date 2010, wholesale revenues from non-affiliates were $223.5 million compared to $235.1 million for the corresponding period in 2009. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $21.3 million, partially offset by a $9.7 million increase in revenues from customers inside Mississippi Power’s service territory. The $21.3 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $25.1 million decrease in sales volume, partially offset by a $3.5 million increase associated with higher prices resulting from the higher marginal cost of fuel and a $0.3 million increase in capacity revenues. The $9.7 million increase in revenues from customers inside Mississippi Power’s service territory was primarily due to a $4.4 million increase in fuel revenues and a $5.3 million increase in wholesale base revenues resulting from warmer weather in the second and third quarters 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.

Wholesale Revenues – Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(0.4)	(2.8)	$0.9	2.8

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.

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

In the third quarter 2010, wholesale revenues from affiliates were $13.0 million compared to $13.4 million for the corresponding period in 2009. The decrease was primarily due to a $5.1 million decrease in capacity revenues primarily due to affiliated companies purchasing capacity from third parties rather than from Mississippi Power, partially offset by a $4.7 million increase in energy revenues, of which $3.3 million was associated with higher prices and an increase of $1.4 million associated with increased sales volume.

For year-to-date 2010, wholesale revenues from affiliates were $31.6 million compared to $30.8 million for the corresponding period in 2009. The increase was primarily due to a $5.5 million increase in energy revenues, of which $4.4 million was associated with higher prices and $1.1 million associated with increased sales volume. This increase was partially offset as capacity revenues decreased $4.6 million primarily due to affiliated companies purchasing capacity from third parties rather than from Mississippi Power.

Fuel and Purchased Power Expenses

	Third Quarter 2010						Year-to-Date 2010
	vs.						vs.
	Third Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	6.5			4.4		$	(4.9	)		(1.3	)
Purchased power – non-affiliates		0.8			52.8			0.3			4.0
Purchased power – affiliates		(11.0	)		(50.3	)		(5.2	)		(8.0	)
Total fuel and purchased power expenses	$	(3.7	)				$	(9.8	)

In the third quarter 2010, total fuel and purchased power expenses were $168.0 million compared to $171.7 million for the corresponding period in 2009. The decrease was primarily due to a $9.9 million decrease in the cost of fuel and purchased power, partially offset by a $6.2 million increase related to the total KWHs generated and purchased.

For year-to-date 2010, total fuel and purchased power expenses were $456.8 million compared to $466.6 million for the corresponding period in 2009. The decrease was primarily due to a $10.0 million decrease in the cost of fuel and purchased power, partially offset by a $0.2 million increase 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.

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

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	2010		2009		Change			2010		2009		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		4.08		4.38		(6.8	)		4.21		4.34		(3.0	)
Purchased power		4.04		3.62		11.6			3.72		3.62		2.8

In the third quarter 2010, fuel expense was $154.6 million compared to $148.1 million for the corresponding period in 2009. The increase was primarily due to a 12.0% increase in generation from Mississippi Power facilities resulting from higher system load, partially offset by a 6.8% decrease in the price of fuel resulting from lower coal prices.

For year-to-date 2010, fuel expense was $388.9 million compared to $393.9 million for the corresponding period in 2009. The decrease was primarily due to a 3.0% decrease in the price of fuel resulting from lower coal prices, partially offset by a 1.8% increase in generation from Mississippi Power facilities resulting from higher system load.

Non-Affiliates

In the third quarter 2010, purchased power expense from non-affiliates was $2.5 million compared to $1.7 million for the corresponding period in 2009. The increase was primarily the result of a 249.5% increase in the average cost per KWH purchased, partially offset by a 56.3% decrease in the volume of KWH purchased. The decrease in the volume of KWH purchased was the result of higher cost opportunity purchases, while the increase in prices was due to a higher marginal cost of fuel.

For year-to-date 2010, purchased power expense from non-affiliates was $7.7 million compared to $7.4 million for the corresponding period in 2009. The increase was primarily the result of a 205.3% increase in the average cost per KWH purchased, partially offset by a 66.0% decrease in the volume of KWH purchased. The decrease in the volume of KWH purchased was a result of higher cost opportunity purchases, while the increase in prices was due to a higher marginal cost of fuel.

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

Affiliates

In the third quarter 2010, purchased power expense from affiliates was $10.9 million compared to $21.9 million for the corresponding period in 2009. The decrease was primarily due to a 48.1% decrease in the volume of KWH purchased and a 4.3% decrease in the average cost per KWH purchased.

For year-to-date 2010, purchased power expense from affiliates was $60.1 million compared to $65.3 million for the corresponding period in 2009. The decrease was primarily due to a 14.3% decrease in the average cost per KWH purchased, partially offset by a 7.3% increase in the volume of KWH purchased.

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

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

Other Operations and Maintenance Expenses

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$4.8	7.9	$22.5	12.4

In the third quarter 2010, other operations and maintenance expenses were $65.9 million compared to $61.1 million for the corresponding period in 2009. The increase was primarily due to increases in labor costs of $2.8 million, distribution maintenance for vegetation management costs of $0.4 million, and administrative and general expenses of $1.4 million.

For year-to-date 2010, other operations and maintenance expenses were $205.0 million compared to $182.5 million for the corresponding period in 2009. The increase was primarily due to a $7.8 million increase in generation maintenance expenses for several major outages, a $3.3 million increase in routine generation expenses, a $3.8 million increase in transmission and distribution expenses related to substation and overhead line maintenance and vegetation management costs, a $3.1 million increase in administrative and general expenses, and a $5.3 million increase in labor costs.

Depreciation and Amortization

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$2.4	13.5	$4.2	7.8

In the third quarter 2010, depreciation and amortization was $20.1 million compared to $17.7 million for the corresponding period in 2009. The increase was primarily due to a $1.6 million increase in ECO Plan amortization from the prior year and a $0.8 million increase in depreciation resulting from an increase in plant in service.

For year-to-date 2010, depreciation and amortization was $57.6 million compared to $53.4 million for the corresponding period in 2009. The increase was primarily due to a $2.2 million increase in ECO Plan amortization from the prior year and a $2.0 million increase in depreciation resulting from an increase in plant in service.

Taxes Other Than Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$0.9	5.3	$5.4	11.2

In the third quarter 2010, taxes other than income taxes were $17.9 million compared to $17.0 million for the corresponding period in 2009. The increase was primarily due to a $0.8 million increase in ad valorem taxes and a $0.1 million increase in payroll taxes.

For year-to-date 2010, taxes other than income taxes were $53.6 million compared to $48.2 million for the corresponding period in 2009. The increase was primarily due to increases in ad valorem taxes of $4.8 million, payroll taxes of $0.4 million, and franchise taxes of $0.2 million.

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

117

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

Allowance for Equity Funds Used During Construction

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$1.5	N/M	$1.6	N/M

N/M – Not meaningful

In the third quarter 2010, AFUDC equity was $1.5 million compared to $0 for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $2.0 million compared to $0.4 million for the corresponding period in 2009. These increases were due to the Kemper IGCC project.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(1.2)	(19.6)	$(0.1)	(0.5)

In the third quarter 2010, interest expense, net of amounts capitalized was $4.9 million compared to $6.1 million for the corresponding period in 2009. The decrease was primarily due to a $1.3 million increase in AFUDC debt primarily associated with the Kemper IGCC project, partially offset by a $0.2 million increase primarily related to higher interest expense related to a regulatory recovery mechanism for fuel and energy cost hedging and the issuance of new debt in September 2010.

For year-to-date 2010, interest expense, net of amounts capitalized was $17.0 million compared to $17.1 million for the corresponding period in 2009. The slight decrease was primarily due to a $1.4 million increase in AFUDC debt primarily associated with the Kemper IGCC project, partially offset by a $0.9 million increase in interest expense associated with the issuance of new debt in March 2009 and September 2010 and a $0.4 million increase in interest expense related to a regulatory recovery mechanism for fuel and energy cost hedging.

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.

Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(3.4)	(15.4)	$(8.7)	(18.7)

In the third quarter 2010, income taxes were $18.8 million compared to $22.2 million for the corresponding period in 2009. The decrease in income taxes was primarily due to a $1.7 million decrease resulting from lower pre-tax income, a $1.1 million decrease due to actualization of the 2009 tax return in the third quarter 2010, and a $0.6 million decrease due to an increase in AFUDC equity.

For year-to-date 2010, income taxes were $37.6 million compared to $46.3 million for the corresponding period in 2009. The decrease was primarily due to a $6.9 million decrease resulting from lower pre-tax income, a $1.1 million decrease due to actualization of the 2009 tax return in the third quarter 2010, a $1.1 million decrease in unrecognized tax benefits, a $0.8 million decrease due to an increase in AFUDC equity, partially offset by a $0.5 million increase due to a lower production activities deduction, and a $0.9 million increase due to a lower Mississippi manufacturing investment tax credit.

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MISSISSIPPI 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 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 all prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power’s service area. Changes in economic conditions impact sales for Mississippi Power and the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.

Environmental Matters

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

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding a civil action brought by the EPA alleging that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including one facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims. The ultimate outcome of this matter cannot now be determined.

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. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

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

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Mississippi Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO₂) regulations. On August 23, 2010, the EPA’s final revisions to the National Ambient Air Quality Standard for SO₂, which included the establishment of a new short-term standard, became effective. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO₂) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas within Mississippi Power’s service territory are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO₂ standard could result in significant additional compliance and operational costs for units that require new source permitting.

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 information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Alabama and Mississippi, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

These regulations could result in significant additional compliance and operational 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.

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

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Mississippi Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as if the materials technically constituted a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, a hazardous or other designation indicative of heightened risk could limit or eliminate beneficial reuse options. Comments on the proposed rules are due by November 19, 2010. Although its analysis is preliminary, Southern Company believes the EPA has significantly underestimated compliance costs in the proposed rule.

The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Mississippi Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational 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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.

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 and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational 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. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.

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

FERC and Mississippi PSC Matters

Wholesale Rate Filing

On October 22, 2010, Mississippi Power filed a request with the FERC for a revised wholesale electric tariff and revised rates. Prior to making this filing, Mississippi Power reached a settlement with all of its customers who take service under the tariff. This settlement agreement was filed with the FERC as part of the request. The settlement agreement provides for an increase in annual base wholesale revenues in the amount of approximately $4.1 million, effective January 1, 2011. In addition, the settlement agreement allows Mississippi Power to implement an emissions allowance cost clause, effective January 1, 2011. The emissions allowance cost clause contains an over and under recovery provision similar to the fuel recovery clause and is projected to collect $6.9 million in 2011. The settlement agreement also provides for collection of up to $2.8 million of 2010 emissions allowance expense for the period of September 1, 2010 through December 31, 2010 and allows Mississippi Power to defer the wholesale portion of the income tax expense associated with the change in taxability of the federal subsidy under the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Performance Evaluation Plan

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

In November 2009, the revised PEP was approved by the Mississippi PSC and Mississippi Power resumed annual evaluations. Mississippi Power filed its annual PEP filing for 2010 under the revised PEP, which resulted in a lower allowed return on investment but no rate change.

On March 15, 2010, Mississippi Power submitted its annual PEP lookback filing for 2009, which recommended no surcharge or refund. On October 26, 2010, Mississippi Power and the Mississippi Public Utilities Staff agreed and stipulated that no surcharge or refund is required. On November 2, 2010, the Mississippi PSC accepted the stipulation.

System Restoration Rider

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

In September 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 factors were in effect from November 2009 to March 2010. Beginning in April 2010, the SRR factors were reset to zero. On January 29, 2010, Mississippi Power submitted its 2010 SRR rate filing with the Mississippi PSC and expects to accrue approximately $3.0 million to the property damage reserve in 2010.

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.

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

On February 12, 2010, Mississippi Power submitted its 2010 ECO Plan notice which proposed an increase in annual revenues for Mississippi Power of approximately $3.9 million. Due to changes in ECO Plan cost projections, on August 20, 2010, Mississippi Power submitted a revised 2010 ECO Plan which reduced the requested increase in annual revenues to $1.7 million. In its 2010 ECO Plan filing, Mississippi Power proposed to change the true-up provision of the ECO Plan rate schedule to consider actual revenues collected in addition to actual costs. Hearings on the ECO Plan were held with the Mississippi PSC on October 5, 2010. On October 25, 2010, the Mississippi PSC held a public meeting to discuss the 2010 ECO Plan and issued an order approving the revised 2010 ECO Plan with the new rates effective in November 2010. Mississippi Power and the Mississippi Public Utilities Staff jointly agreed to defer the decision on the change in the true-up provision of the ECO Plan rate schedule. The ultimate outcome of the proposed changes to the true-up provision cannot be determined at this time.

On July 22, 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $625 million and is scheduled for completion in the fourth quarter 2014. Mississippi Power’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through its ECO Plan. On October 25, 2010, the Mississippi PSC held a public meeting to discuss Mississippi Power’s filing and issued a scheduling order for the request for a certificate of public convenience and necessity for the project. Hearings on the certificate request are scheduled to be held on January 25, 2011 with a final order expected by February 28, 2011. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. Mississippi Power establishes an annual retail fuel cost recovery factor that is approved by the Mississippi PSC. Mississippi Power is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred in November 2009. The Mississippi PSC approved the retail fuel cost recovery factor on December 15, 2009 with the new rates effective January 2010. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 11.3% of total 2009 retail revenues. As of September 30, 2010, the amount of over recovered retail fuel costs included in the balance sheet was $44.1 million compared to $29.4 million at December 31, 2009. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2010, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 20.9% of total 2009 MRA revenue. Effective February 1, 2010, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 16.9% of total 2009 MB revenue. As of September 30, 2010, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheet was $15.9 million and $3.5 million, respectively, compared to $16.8 million and $2.4 million, respectively, at December 31, 2009. Mississippi Power’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this decrease to the billing factor will not have a significant effect on Mississippi Power’s revenues or net income, but will decrease annual cash flow.

In October 2010, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of Mississippi Power’s fuel-related expenditures included in the retail fuel adjustment clause and energy cost management clause for 2010. The audit is scheduled to be completed in early 2011. The ultimate outcome of this matter cannot be determined at this time.

Depreciation Study

See Note 1 to the financial statements of Mississippi Power under “Depreciation and Amortization” in Item 8 of the Form 10-K for additional information. In September 2009, Mississippi Power filed a depreciation study, as of December 31,

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2008, with the Mississippi PSC and the FERC. The FERC accepted this study in October 2009. On April 20, 2010, the Mississippi PSC issued an order approving the depreciation rates effective January 1, 2010.

Integrated Coal Gasification Combined Cycle

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

On March 9, 2010, the Mississippi Department of Environmental Quality issued the PSD air permit modification for the Kemper IGCC, which modifies the original PSD air permit issued in October 2008. The Mississippi Chapter of the Sierra Club has requested a formal evidentiary hearing regarding the issuance of the modified permit.

In addition to the Internal Revenue Code Section 48A Phase I tax credits of $133 million certified by the IRS in May 2009, Mississippi Power filed an application in November 2009 with the DOE and in December 2009 with the IRS for certain tax credits available to projects using advanced coal technologies under the Energy Improvement and Extension Act of 2008. The DOE subsequently certified the Kemper IGCC, and on April 30, 2010, the IRS allocated $279 million of Phase II tax credits under Section 48A of the Internal Revenue Code to Mississippi Power. On September 30, 2010, Mississippi Power and the IRS executed the closing agreement for the Phase II tax credits. The utilization of these credits is dependent upon meeting the IRS certification requirements and completing the Kemper IGCC in a timely manner. 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 these credits. In order to remain eligible for the Phase II tax credits, Mississippi Power must capture and sequester at least 65% of the carbon dioxide produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits, and must meet the required in-service date, satisfy environmental and other permitting requirements, and have in place a binding contract for the steam turbine generator.

On April 29, 2010, the Mississippi PSC issued an order finding that Mississippi Power’s application to acquire, construct, and operate the Kemper IGCC did not satisfy the requirement of public convenience and necessity in the form that the project and the related cost recovery were originally proposed by Mississippi Power. The April 2010 order also approved recovery of $46 million of $50.5 million in prudent pre-construction costs incurred through March 2009. The remaining $4.5 million is associated with overhead costs and variable pay of SCS, which were recommended for exclusion from pre-construction costs by a consultant hired by the Mississippi Public Utilities Staff. An additional $3.5 million has been incurred for costs of this type from March 2009 through May 2010. The remaining $4.5 million, as well as additional pre-construction amounts incurred during the generation screening and evaluation process through May 2010 will be reviewed and addressed in a future proceeding.

On May 10, 2010, Mississippi Power filed a motion in response to the April 29, 2010 order of the Mississippi PSC relating to the Kemper IGCC, or in the alternative, for alteration or rehearing of such order.

On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order (1) approved the alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the costs of the lignite mine and equipment), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity; (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal; and (3) approved financing cost recovery on construction work in progress (CWIP) balances under the State of Mississippi Baseload Act of 2008 (Baseload Act), which provides for the accrual of allowance for funds used during construction in 2010 and 2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of government construction cost incentives received by

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Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted Mississippi Power’s motion and issued a certificate of public convenience and necessity authorizing acquisition, construction, and operation of the Kemper IGCC.

In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and will acquire mineral reserves located at the plant site in Kemper County. The estimated capital cost of the mine is approximately $214 million. On May 27, 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations. The agreement is effective June 1, 2010 through the end of the mine reclamation.

On June 17, 2010, the Sierra Club filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant a certificate of public convenience and necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, on July 6, 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. On July 20, 2010, the Chancery Court issued a stay of the proceeding pending the resolution of the jurisdictional issues raised in a motion filed by Mississippi Power on July 16, 2010 to confirm jurisdiction in the Mississippi Supreme Court. On October 7, 2010, the Mississippi Supreme Court denied Mississippi Power’s motion and dismissed the Sierra Club’s direct appeal. The appeal will now proceed in the Chancery Court.

On July 27, 2010, Mississippi Power and South Mississippi Electric Power Association (SMEPA) entered into an Asset Purchase Agreement whereby SMEPA will purchase an undivided 17.5% interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.

On August 19, 2010, the National Environmental Policy Act (NEPA) Record of Decision (ROD) by the DOE for the Clean Coal Power Initiative Round 2 (CCPI2) grants was noted in the Federal Register. The NEPA ROD and its accompanying final environmental impact statement were the final major hurdles necessary for Mississippi Power to receive grant funds of $245 million during the construction of the Kemper IGCC and $25 million during the initial operation of the Kemper IGCC.

As of September 30, 2010, Mississippi Power had spent a total of $195.5 million on the Kemper IGCC, including regulatory filing costs. Of this total, $156.4 million was included in CWIP (net of $24.8 million recorded as a receivable of CCPI2 grant funds), $11.5 million was recorded in other regulatory assets, $1.3 million was recorded in other deferred charges and assets, and $1.5 million was expensed. Upon receipt of the issuance of the final certificate order in May 2010, construction screening costs including regulatory filing costs totaled $129.0 million. As of May 31, 2010, construction related screening costs of $116.2 million were reclassified to CWIP while the non-capital related costs of $11.2 million and $0.6 million were classified in other regulatory assets and other deferred charges, respectively, and $1.0 million was previously expensed.

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

Legislation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Mississippi Power in Item 7 of the Form 10-K for additional information.

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Healthcare Reform

On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Mississippi Power has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of regulatory treatment, this change had no material impact on the financial statements of Mississippi Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Mississippi Power cannot be determined at this time.

Stimulus Funding

On April 8, 2010, Mississippi Power received notice that an award had been granted under the American Recovery and Reinvestment Act of 2009 (ARRA) grant application for smart grid workforce training. Under this agreement, Mississippi Power was to receive, and match, $2.6 million. Mississippi Power withdrew its application on September 17, 2010.

On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the ARRA. This funding will be used for transmission and distribution automation and modernization projects that must be completed by April 28, 2013. Mississippi Power will receive, and will match, $25 million under this agreement.

Income Tax Matters

Tax Method of Accounting for Repairs

Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $3 million for Mississippi Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

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Bonus Depreciation

On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Mississippi Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $16 million.

Other Matters

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

The coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has not significantly impacted operations, but has had and may continue to have significant economic impacts on the affected areas within Mississippi Power’s service territory.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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 the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, Plant Daniel Operating Lease, and Pension and Other Postretirement Benefits.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Mississippi Power’s financial condition remained stable at September 30, 2010. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See “Sources of Capital” and “Financing Activities” herein for additional information.

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Net cash provided from operating activities totaled $125.3 million for the first nine months of 2010, compared to $85.2 million for the corresponding period in 2009. The $40.1 million increase in cash provided from operating activities was primarily due to an increase in cash from fossil fuel stock of $53.0 million primarily resulting from a decrease in cash payments related to fuel inventory, an increase in accounts payable of $52.1 million primarily due to timing of cash payments, an increase of $22.9 million in deferred income taxes primarily due to fuel cost recovery and a change in the tax method of accounting for repair costs, and an increase of $14.4 million related to an investment tax credit on the Kemper IGCC. These increases in cash were partially offset by an increase in spending related to the Kemper IGCC generation construction screening costs of $28.6 million and a decrease in cash related to lower fuel rates effective in the first quarter 2010. Net cash used for investing activities totaled $133.4 million for the first nine months of 2010, compared to $88.7 million for the corresponding period in 2009. The $44.7 million increase in net cash used for investing activities was primarily due to an increase in property additions primarily related to the Kemper IGCC. Net cash provided from financing activities totaled $74.6 million for the first nine months of 2010, compared to $9.1 million for the corresponding period in 2009. The $65.5 million increase in net cash provided from financing activities was primarily due to a $24.9 million decrease in notes payable and the repayment of $40.0 million of senior notes both of which occurred in the third quarter 2009. 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 2010 include an increase in cash and cash equivalents of $66.5 million. Affiliated companies receivables increased $38.2 million primarily due to funds to be received from the DOE related to the Kemper IGCC. See Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K for additional information. Total property, plant, and equipment increased by $179.7 million primarily due to the increase in construction work in progress related to the Kemper IGCC. The expenditures associated with the Kemper IGCC project were reclassified from other regulatory assets, deferred to construction work in progress during the second quarter 2010 upon the Mississippi PSC issuance of the final certificate order for the project. Securities due within one year increased by $205.1 million primarily due to the reclassification of a long-term bank loan maturing in March 2011 and a new $125.0 million bank loan maturing in September 2011. Accounts payable, other increased $26.3 million primarily due to the timing of payments and accrued income taxes increased $15.2 million primarily due to the tax accrual for 2010.

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, interest, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $206.4 million will be required through September 30, 2011 to fund maturities of long-term debt. No mandatory contributions to Mississippi Power’s pension plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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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 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 Mississippi Power in Item 7 of the Form 10-K for additional information.

Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE but has yet to begin discussions with the DOE regarding the terms and conditions of any loan guarantee. There can be no assurance the DOE will issue federal loan guarantees to Mississippi Power. In addition, Mississippi Power has been awarded DOE CCPI2 grant funds of $245 million to be used for the construction of the Kemper IGCC and $25 million to be used for the initial operation of the Kemper IGCC. In the third quarter 2010, Mississippi Power recorded a receivable of $24.8 million associated with this grant.

Mississippi Power’s current liabilities sometimes exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Mississippi Power had at September 30, 2010 cash and cash equivalents of $131.6 million and unused committed credit arrangements with banks of $161 million. Of the cash and cash equivalents, approximately $125 million was held in various money market mutual funds. The money market mutual funds invest in a portfolio of highly-rated, short-term securities, and redemptions from the funds are available on a same day basis up to the full amount of the investment. Of the unused credit arrangements, $16 million expire in 2010 and $145 million expire in 2011. Of these credit arrangements, $41 million contain provisions allowing two-year term loans executable at expiration and $65 million contain provisions allowing one-year term loans executable at expiration. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Mississippi Power’s commercial paper program and $40 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Mississippi Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and other Southern Company subsidiaries. At September 30, 2010, Mississippi Power had no commercial paper borrowings outstanding. During the third quarter 2010, Mississippi Power had an average of $37 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $63 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Off-Balance Sheet Financing Arrangements” of Mississippi Power in Item 7 and Note 7 to the financial statements of Mississippi Power under “Operating Leases” in Item 8 of the Form 10-K for information related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel. In April 2010, Mississippi Power was required to notify the lessor, Juniper Capital L.P., if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the units or renew the lease. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be determined at this time.

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Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $381 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 January 22, 2010, Fitch applied new guidelines regarding the ratings of various hybrid capital instruments and preferred securities of companies in all sectors, including banks, insurers, non-bank financial institutions, and non-financial corporate entities, including utilities. As a result, the Fitch rating of Mississippi Power’s preferred stock decreased from A+ to A. These ratings are not applicable to the collateral requirements described above.

On August 12, 2010, Moody’s downgraded the issuer and long-term debt ratings of Mississippi Power (senior unsecured to A2 from A1). Moody’s also announced that it had downgraded the short-term ratings of a financing subsidiary of Southern Company that issues commercial paper for the benefit of Southern Company subsidiaries (including Mississippi Power) to P-2 from P-1. In addition, Moody’s announced that it had downgraded the variable rate demand obligation ratings of Mississippi Power to VMIG-2 from VMIG-1 and the preferred stock ratings of Mississippi Power (to Baa1 from A3). Moody’s announced that the ratings outlook for Mississippi Power is stable.

On September 3, 2010, Fitch downgraded the issuer and long-term debt ratings of Mississippi Power (senior unsecured to A+ from AA- and issuer default rating to A from A+). Fitch also announced that it had downgraded the short-term ratings of Mississippi Power to F1 from F1+. In addition, Fitch announced that it had downgraded the pollution control revenue bond ratings of Mississippi Power to A+ from AA- and the preferred stock ratings of Mississippi Power (to A- from A). Fitch announced that the ratings outlook for Mississippi Power is stable.

Market Price Risk

Mississippi Power’s market risk exposure relative to interest rate changes for the third quarter 2010 has not changed materially compared with the December 31, 2009 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.

In the second quarter 2010, Mississippi Power entered into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Mississippi Power had no material change in market risk exposure in the third quarter 2010 as a result of entering into these contracts.

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 had no material change in market risk exposure for the third quarter 2010 when compared with the December 31, 2009 reporting period.

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The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three and nine months ended September 30, 2010 were as follows:

	Third Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(48	)	$	(42	)
Contracts realized or settled		9			26
Current period changes(a)		(15	)		(38	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(54	)	$	(54	)

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

The change in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 was a decrease of $6 million and a decrease of $12 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to the price of natural gas. At September 30, 2010, Mississippi Power had a net hedge volume of 20 million mmBtu with a weighted average contract cost of approximately $2.80 per mmBtu above market prices, compared to 22 million mmBtu at June 30, 2010 with a weighted average contract cost of approximately $2.24 per mmBtu above market prices and compared to 23 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.83 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the energy cost management clause.

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.

Unrealized pre-tax gains and losses recognized in income for the three and nine months ended September 30, 2010 and 2009 for energy-related derivative contracts that are not hedges were not material.

Mississippi Power uses over-the-counter contracts that are not exchange-traded but are fair valued using prices which are actively quoted, and thus fall into Level 2. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:

	September 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(54	)		(30	)		(24	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(54	)	$	(30	)	$	(24	)	$	—

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 Note 1 under “Financial Instruments” and Note 10 to the financial statements of Mississippi Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

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Financing Activities

In September 2010, Mississippi Power entered into a one-year $125 million aggregate principal amount long-term floating rate bank loan that bears interest based on one-month LIBOR. The proceeds were used to repay a portion of Mississippi Power’s 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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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	261,551		$	133,032		$	568,877		$	318,521
Wholesale revenues, affiliates		93,062			147,921			287,603			420,923
Other revenues		2,217			2,416			5,314			6,040
Total operating revenues		356,830			283,369			861,794			745,484
Operating Expenses:
Fuel		120,466			58,820			294,658			176,332
Purchased power, non-affiliates		24,939			20,019			59,103			66,279
Purchased power, affiliates		31,454			20,915			79,874			49,977
Other operations and maintenance		34,614			29,094			111,499			97,033
Depreciation and amortization		29,361			23,190			87,362			74,727
Taxes other than income taxes		4,071			4,166			14,314			13,714
Total operating expenses		244,905			156,204			646,810			478,062
Operating Income		111,925			127,165			214,984			267,422
Other Income and (Expense):
Interest expense, net of amounts capitalized		(18,801	)		(21,438	)		(58,408	)		(64,589	)
Other income (expense), net		(113	)		2,699			198			2,465
Total other income and (expense)		(18,914	)		(18,739	)		(58,210	)		(62,124	)
Earnings Before Income Taxes		93,011			108,426			156,774			205,298
Income taxes		31,317			41,146			50,566			79,048
Net Income	$	61,694		$	67,280		$	106,208		$	126,250

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2010		2009			2010		2009
	(in thousands)					(in thousands)
Net Income	$	61,694	$	67,280		$	106,208	$	126,250
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $1,125, $(298), $1,536, and $4, respectively		1,759		(459	)		2,400		7
Reclassification adjustment for amounts included in net income, net of tax of $1,018, $948, $3,011, and $2,814, respectively		1,590		1,461			4,703		4,336
Total other comprehensive income (loss)		3,349		1,002			7,103		4,343
Comprehensive Income	$	65,043	$	68,282		$	113,311	$	130,593

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,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	106,208		$	126,250
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		97,469			83,890
Deferred income taxes		13,251			8,020
Convertible investment tax credits received		22,150			—
Deferred revenues		18,846			33,290
Mark-to-market adjustments		2,435			(406	)
Accumulated billings on construction contract		401			35,565
Accumulated costs on construction contract		(49	)		(39,890	)
Other, net		2,014			2,611
Changes in certain current assets and liabilities —
-Receivables		(35,537	)		(44,195	)
-Fossil fuel stock		6,097			2,215
-Materials and supplies		3,216			(4,110	)
-Prepaid income taxes		2,013			—
-Other current assets		598			396
-Accounts payable		(2,194	)		(20,777	)
-Accrued taxes		31,069			62,260
-Accrued interest		(12,194	)		(12,152	)
-Other current liabilities		21			(199	)
Net cash provided from operating activities		255,814			232,768
Investing Activities:
Property additions		(210,599	)		(47,696	)
Sale of property		4,000			52
Change in construction payables		31,021			6,915
Payments pursuant to long-term service agreements		(30,936	)		(26,118	)
Other investing activities		(248	)		(184	)
Net cash used for investing activities		(206,762	)		(67,031	)
Financing Activities:
Increase in notes payable, net		20,216			—
Proceeds — Capital contributions		3,908			2,068
Payment of common stock dividends		(80,325	)		(79,575	)
Net cash used for financing activities		(56,201	)		(77,507	)
Net Change in Cash and Cash Equivalents		(7,149	)		88,230
Cash and Cash Equivalents at Beginning of Period		7,152			37,894
Cash and Cash Equivalents at End of Period	$	3		$	126,124
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $7,704 and $441 capitalized for 2010 and 2009, respectively)	$	63,560		$	68,652
Income taxes (net of refunds)	$	(8,158	)	$	20,467

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	2010		2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	3	$	7,152
Receivables —
Customer accounts receivable		77,125		28,873
Other accounts receivable		1,890		2,064
Affiliated companies		34,792		38,561
Fossil fuel stock, at average cost		10,189		15,351
Materials and supplies, at average cost		32,416		31,607
Prepaid service agreements — current		20,459		44,090
Prepaid income taxes		3,245		5,177
Other prepaid expenses		2,577		3,176
Assets from risk management activities		6,103		4,901
Other current assets		—		6,754
Total current assets		188,799		187,706
Property, Plant, and Equipment:
In service		3,026,358		2,994,463
Less accumulated provision for depreciation		507,266		439,457
Plant in service, net of depreciation		2,519,092		2,555,006
Construction work in progress		361,223		153,982
Total property, plant, and equipment		2,880,315		2,708,988
Other Property and Investments:
Goodwill		1,839		1,794
Other intangible assets, net of amortization of $498 and $17 at September 30, 2010 and December 31, 2009, respectively		48,622		49,102
Total other property and investments		50,461		50,896
Deferred Charges and Other Assets:
Prepaid long-term service agreements		83,858		74,513
Other deferred charges and assets — affiliated		3,341		3,540
Other deferred charges and assets — non-affiliated		16,410		17,410
Total deferred charges and other assets		103,609		95,463
Total Assets	$	3,223,184	$	3,043,053

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	2010			2009
	(in thousands)
Current Liabilities:
Notes payable	$	139,164		$	118,948
Accounts payable —
Affiliated		80,438			58,493
Other		42,981			31,128
Accrued taxes —
Accrued income taxes		15,163			1,449
Other accrued taxes		14,248			2,576
Accrued interest		17,729			29,923
Liabilities from risk management activities		7,405			8,119
Other current liabilities		22			323
Total current liabilities		317,150			250,959
Long-term Debt		1,297,797			1,297,607
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		255,847			238,293
Deferred convertible investment tax credits		44,958			16,800
Deferred capacity revenues — affiliated		52,798			36,369
Other deferred credits and liabilities — affiliated		4,873			5,651
Other deferred credits and liabilities — non-affiliated		17,745			2,252
Total deferred credits and other liabilities		376,221			299,365
Total Liabilities		1,991,168			1,847,931
Common Stockholder’s Equity:
Common stock, par value $.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		868,370			864,462
Retained earnings		377,944			352,061
Accumulated other comprehensive loss		(14,298	)		(21,401	)
Total common stockholder’s equity		1,232,016			1,195,122
Total Liabilities and Stockholder’s Equity	$	3,223,184		$	3,043,053

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 2010 vs. THIRD QUARTER 2009
AND
YEAR-TO-DATE 2010 vs. YEAR-TO-DATE 2009

OVERVIEW

Southern Power and its wholly-owned subsidiaries construct, acquire, own, and manage generation assets and sell electricity at market-based prices in the wholesale market. Southern Power continues to execute its strategy through a combination of acquiring and constructing new power plants and by entering into PPAs with investor owned utilities, independent power producers, municipalities, and electric cooperatives.

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

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(5.6)	(8.3)	$(20.1)	(15.9)

Southern Power’s net income for the third quarter 2010 was $61.7 million compared to $67.3 million for the corresponding period in 2009. This decrease was primarily due to lower revenues associated with the expiration of affiliate PPAs in December 2009 and May 2010, higher operations and maintenance expenses, and higher depreciation and amortization. These decreases were partially offset by higher revenues on energy sales that were not covered by PPAs and lower interest expense, net of amounts capitalized.

Southern Power’s net income for year-to-date 2010 was $106.2 million compared to $126.3 million for the corresponding period in 2009. This decrease was primarily due to lower revenues associated with the expiration of affiliate PPAs in December 2009 and May 2010, higher operations and maintenance expenses, and higher depreciation and amortization. These decreases were partially offset by higher revenues on energy sales that were not covered by PPAs, higher tax benefits associated with the construction of Plant Nacogdoches, and lower interest expense, net of amounts capitalized.

Wholesale Revenues–Non-Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$128.6	96.6	$250.4	78.6

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.

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

Wholesale energy sales to non-affiliates for the third quarter 2010 were $261.6 million compared to $133.0 million for the corresponding period in 2009. The increase was mainly due to $132.8 million of higher energy and capacity revenues under existing non-affiliate PPAs and new non-affiliate PPAs that began in January, June, and July 2010 and $6.5 million of higher revenues from energy sales that were not covered by PPAs due to more favorable weather in the third quarter 2010 compared to the corresponding period in 2009. These increases were partially offset by $6.9 million of lower energy and capacity revenues associated with the expiration of a non-affiliate PPA in December 2009 and a $3.8 million decrease in revenues from power sales under the IIC.

Wholesale energy sales to non-affiliates for year-to-date 2010 were $568.9 million compared to $318.5 million for the corresponding period in 2009. The increase was mainly due to $220.9 million of higher energy and capacity revenues under existing non-affiliate PPAs and new non-affiliate PPAs that began in January, June, and July 2010. Also contributing to the increase was $65.5 million of higher revenues from energy sales that were not covered by PPAs due to more favorable weather year-to-date 2010 compared to the corresponding period in 2009. These increases were partially offset by $15.4 million of lower energy and capacity revenues associated with the expiration of a non-affiliate PPA in December 2009 and a $20.6 million decrease in revenues from power sales under the IIC.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K for additional information.

Wholesale Revenues–Affiliates

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(54.8)	(37.1)	$(133.3)	(31.7)

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 2010 were $93.1 million compared to $147.9 million for the corresponding period in 2009. The decrease was primarily the result of $95.6 million of lower energy and capacity revenues associated with the expiration of affiliate PPAs in December 2009 and May 2010. The decrease was partially offset by $22.6 million of higher energy and capacity revenues under existing affiliate PPAs and new affiliate PPAs that began in June 2010 and $18.2 million related to increased revenues from power sales under the IIC.

Wholesale revenues from affiliates for year-to-date 2010 were $287.6 million compared to $420.9 million for the corresponding period in 2009. The decrease was primarily the result of $222.6 million of lower energy and capacity revenues associated with the expiration of affiliate PPAs in December 2009 and in May 2010. The decrease was partially offset by $36.4 million of higher energy and capacity revenues under existing affiliate PPAs and new affiliate PPAs that began in June 2010 and $52.9 million related to increased revenues from power sales under the IIC.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K for additional information.

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

Fuel and Purchased Power Expenses

	Third Quarter 2010				Year-to-Date 2010
	vs.				vs.
	Third Quarter 2009				Year-to-Date 2009
	(change in millions)		(% change)		(change in millions)			(% change)
Fuel	$	61.7		104.8	$	118.4			67.1
Purchased power – non-affiliates		4.9		24.6		(7.2	)		(10.8	)
Purchased power – affiliates		10.5		50.4		29.8			59.8
Total fuel and purchased power expenses	$	77.1			$	141.0

Southern Power PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is generally accompanied by an increase or decrease in related fuel revenues and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.

In the third quarter 2010, total fuel and purchased power expenses were $176.9 million compared to $99.8 million for the corresponding period in 2009. Total fuel and purchased power expenses increased $43.7 million due to a 21.0% increase in the average cost of natural gas and a 69.1% increase in the average cost of purchased power. Additionally, total fuel and purchased power expenses increased $33.4 million due to an increase in KWHs generated and purchased.

For year-to-date 2010, total fuel and purchased power expenses were $433.6 million compared to $292.6 million for the corresponding period in 2009. Total fuel and purchased power expenses increased $78.0 million due to a 14.2% increase in the average cost of natural gas and a 42.4% increase in the average cost of purchased power. Additionally, total fuel and purchased power expenses increased $63.0 million due to an increase in KWHs generated and purchased.

In the third quarter 2010, fuel expense was $120.5 million compared to $58.8 million for the corresponding period in 2009. Fuel expense increased $20.7 million associated with a 21.0% increase in the average cost of natural gas and $40.9 million due to an increase in KWHs generated.

For year-to-date 2010, fuel expense was $294.7 million compared to $176.3 million for the corresponding period in 2009. Fuel expense increased $36.6 million associated with a 14.2% increase in the average cost of natural gas and $81.7 million due to an increase in KWHs generated.

In the third quarter 2010, purchased power expense was $56.4 million compared to $40.9 million for the corresponding period in 2009. Purchased power expenses increased $23.0 million due to an increase in the average cost of purchased power, partially offset by a $7.5 million decrease due to fewer KWHs purchased.

For year-to-date 2010, purchased power expense was $139.0 million compared to $116.3 million for the corresponding period in 2009. Purchased power expenses increased $41.4 million due to an increase in the average cost of purchased power, partially offset by an $18.7 million decrease due to fewer KWHs purchased.

Other Operations and Maintenance Expenses

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$5.5	19.0	$14.5	14.9

In the third quarter 2010, other operations and maintenance expenses were $34.6 million compared to $29.1 million for the corresponding period in 2009. This increase was primarily due to $3.6 million related to generating plant outages and maintenance, $0.5 million associated with a loss on the sale of property, and $0.5 million associated with an increase in information technology costs.

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

For year-to-date 2010, other operations and maintenance expenses were $111.5 million compared to $97.0 million for the corresponding period in 2009. This increase was primarily due to $4.1 million of additional expense associated with the passage of healthcare legislation in March 2010, $6.9 million related to generating plant outages and maintenance, $0.6 million associated with a loss on the sale of property, $0.5 million associated with an increase in information technology costs, and $1.1 million associated with employee benefits.

See FUTURE EARNINGS POTENTIAL – “Legislation” herein for additional information regarding healthcare legislation.

Depreciation and Amortization

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$6.2	26.6	$12.7	16.9

In the third quarter 2010, depreciation and amortization was $29.4 million compared to $23.2 million for the corresponding period in 2009. The increase was primarily related to $1.6 million associated with the acquisition of West Georgia Generating Company LLC (West Georgia) and the divestiture of DeSoto County Generating Company LLC (DeSoto) which resulted in an increase in property, plant, and equipment of approximately $120.2 million. The increase was also due to $1.8 million of equipment retirements, $2.3 million associated with changes in depreciation rates, and $0.5 million related to other increases in property, plant, and equipment.

For year-to-date 2010, depreciation and amortization was $87.4 million compared to $74.7 million for the corresponding period in 2009. The increase was primarily related to $4.8 million associated with the West Georgia/DeSoto acquisition/divestiture described above, $6.6 million of equipment retirements, and $1.2 million related to other increases in property, plant, and equipment.

See Note 1 to the financial statements of Southern Power under “Depreciation” and Note 2 to the financial statements of Southern Power under “West Georgia Generating Company, LLC Acquisition and DeSoto County Generating Company, LLC Divestiture” in Item 8 of the Form 10-K for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(2.6)	(12.3)	$(6.2)	(9.6)

In the third quarter 2010, interest expense, net of amounts capitalized was $18.8 million compared to $21.4 million for the corresponding period in 2009. This decrease was primarily related to $3.1 million of additional capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant, partially offset by $0.2 million associated with an increase in interest expense on commercial paper and $0.2 million associated with interest rate swaps on senior notes.

For year-to-date 2010, interest expense, net of amounts capitalized was $58.4 million compared to $64.6 million for the corresponding period in 2009. This decrease was primarily related to $7.3 million of additional capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant, partially offset by $0.5 million associated with an increase in interest expense on commercial paper and $0.5 million associated with interest rate swaps on senior notes.

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

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

Other Income (Expense), Net

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(2.8)	(104.2)	$(2.3)	(92.0)

In the third quarter 2010, other income (expense), net was $(0.1) million compared to $2.7 million for the corresponding period in 2009. For year-to-date 2010, other income (expense), net was $0.2 million compared to $2.5 million for the corresponding period in 2009. These decreases were primarily related to profit recognized in 2009 under a construction contract with the Orlando Utilities Commission (OUC) whereby Southern Power provided engineering, procurement, and construction services to build a combined cycle unit for the OUC.

Income Taxes

Third Quarter 2010 vs. Third Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)	(change in millions)	(% change)
$(9.8)	(23.9)	$(28.4)	(36.0)

In the third quarter 2010, income taxes were $31.3 million compared to $41.1 million for the corresponding period in 2009. The decrease was primarily due to $5.9 million associated with lower pre-tax earnings, $1.4 million related to an increase in the federal production activities deduction, and $0.8 million of tax benefits associated with the construction of Plant Nacogdoches.

For year-to-date 2010, income taxes were $50.6 million compared to $79.0 million for the corresponding period in 2009. The decrease was primarily due to $19.0 million associated with lower pre-tax earnings, $5.9 million of tax benefits associated with the construction of Plant Nacogdoches, and $1.8 million related to an increase in the federal production activities deduction.

See Note 1 to the financial statements of Southern Power under “Convertible Investment Tax Credits” in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements under “Effective Tax Rate” herein for additional information.

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, 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. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. Recessionary conditions have lowered demand and have negatively impacted capacity revenues under Southern Power’s PPAs where the amounts purchased are based on demand. Southern Power is unable to predict whether demand under these PPAs will return to pre-recession levels. The timing and extent of the economic recovery 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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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

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

Air Quality

On January 22, 2010, the EPA finalized revisions to the National Ambient Air Quality Standard for Nitrogen Dioxide (NO₂) by setting a new one-hour standard that became effective on April 12, 2010. The impact of this regulation will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time. Although none of the areas in which Southern Power operates generating assets are expected to be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO₂ standard could result in significant additional compliance and operational costs for units that require new source permitting.

Carbon Dioxide Litigation

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Environmental Statutes and Regulations” of Southern Power in Item 7 of the Form 10-K for information regarding the Industrial Boiler Maximum Achievable Control Technology regulations. On April 29, 2010, the EPA issued a proposed rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers. The EPA is required to finalize the rules by January 16, 2011. The impact of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time.

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Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Global Climate Issues” of Southern Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas and other emissions. On April 1, 2010, the EPA issued a final rule regulating greenhouse gas emissions from new motor vehicles under the Clean Air Act. The EPA has stated that, once this rule becomes effective on January 2, 2011, carbon dioxide and other greenhouse gases will become regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the Title V operating permit program, which both apply to power plants. As a result, the construction of new facilities or the major modification of existing facilities could trigger the requirement for a PSD permit and the installation of the best available control technology for carbon dioxide and other greenhouse gases. On May 13, 2010, the EPA issued a final rule, referred to as the Tailoring Rule, governing how these programs would be applied to stationary sources, including power plants. This rule establishes two phases for applying PSD and Title V requirements to greenhouse gas emissions sources. The first phase, beginning on January 2, 2011, will apply to sources and projects that would already be covered under PSD or Title V, whereas the second phase, beginning July 1, 2011, will apply to sources and projects that would not otherwise trigger those programs but for their greenhouse gas emissions. The final rules could result in significant additional compliance and operational costs that could affect results of operations, cash flows, and financial condition. The ultimate outcome of these final rules cannot be determined at this time and will depend on the outcome of any legal challenges.

Legislation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Income Tax Matters - Legislation” of Southern Power in Item 7 of the Form 10-K for additional information. On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (HCERA and, together with PPACA, the Acts), which makes various amendments to certain aspects of the PPACA, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (MPDIMA). Since the 2006 tax year, Southern Company has been receiving the federal subsidy related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date. Southern Power incurred a non-cash write-off of approximately $4 million to expense for the nine months ended September 30, 2010. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Southern Power cannot be determined at this time.

Income Tax Matters

Tax Method of Accounting for Repairs

Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $5 million for Southern Power. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the

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utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Bonus Depreciation

On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. Southern Power has estimated the cash flow reduction to tax payments for 2010 to be approximately $3 million.

Construction Projects

Cleveland County Units 1-4

In December 2008, Southern Power announced that it would 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 capacity of 720 MWs. The units are expected to go into commercial operation in 2012. Costs incurred through September 30, 2010 were $138.6 million. The total estimated construction cost is expected to be between $350 million and $400 million.

Nacogdoches

In October 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 is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in 2009 and the plant is expected to begin commercial operation in 2012. Costs incurred through September 30, 2010 were $211.8 million. The total estimated cost of the project is expected to be between $475 million and $500 million.

Power Sales Agreements

On October 15, 2010, Southern Power signed contract extensions with 10 Georgia Electric Membership Corporations (EMCs). These contracts are an extension of requirements service under agreements that were signed in 2008. The extensions have a requirements term of 10 years beginning in 2015 for eight EMCs, 10 years beginning in 2018 for one EMC, and seven years beginning in 2018 for one EMC. The EMCs are projected to purchase an incremental 625 MWs of capacity over the terms of the extensions.

Other Matters

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

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relief and property damage allegedly caused by greenhouse gas and other 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, Percentage of Completion, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Contingent Obligations, Depreciation, and Convertible Investment Tax Credits.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power’s financial condition remained stable at September 30, 2010. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet future capital and liquidity needs. See “Sources of Capital” herein for additional information on lines of credit.

Net cash provided from operating activities totaled $255.8 million for the first nine months of 2010, compared to $232.8 million for the corresponding period in 2009. The $23.0 million increase was mainly due to an increase in convertible investment tax credits. Net cash used for investing activities totaled $206.8 million for the first nine months of 2010, compared to $67.0 million for the corresponding period in 2009. The $139.8 million increase was primarily due to an increase in construction work in progress related to construction activities at Cleveland County and Nacogdoches. Net cash used for financing activities totaled $56.2 million for the first nine months of 2010, compared to $77.5 million for the corresponding period in 2009. The decrease in cash used for financing activities was primarily due to an increase in short-term borrowings in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant asset changes in the balance sheet for the first nine months of 2010 include an increase in customer accounts receivable due to seasonality and new PPAs that began in January, June, and July 2010, and an increase in construction work in progress due to Cleveland County and Nacogdoches construction activities.

Significant liability and stockholder’s equity changes in the balance sheet for the first nine months of 2010 include an increase in notes payable mainly related to Cleveland County and Nacogdoches construction activities and an increase in deferred convertible investment tax credits associated with the construction of Plant Nacogdoches.

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Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Power in Item 7 of the Form 10-K for a description of Southern Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. 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; new regulatory requirements for generating plants; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

Sources of Capital

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

Southern Power’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at September 30, 2010 committed credit arrangements with banks of $400 million, all of which 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. At September 30, 2010, Southern Power had $139 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.4% per annum. During the third quarter 2010, Southern Power had an average of $186 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $259 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At September 30, 2010, 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 $355 million. At September 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.1 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 Southern Power’s ability to access capital markets, particularly the short-term debt market.

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In addition, through the acquisition of Plant Rowan, Southern Power assumed PPAs with Duke Energy and North Carolina Municipal Power Agency No. 1 (NCMPA1) that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power’s credit. The Duke Energy PPA defines the downgrade to be below BBB- or Baa3. The NCMPA1 PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade for both PPAs.

Market Price Risk

Southern Power is exposed to market risks, including changes in interest rates and certain energy-related commodity prices and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power’s policies in areas such as counterparty exposure and 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 for the third quarter 2010 has not changed materially compared with the December 31, 2009 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

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

The changes in fair value of energy-related derivative contracts for the three and nine months ended September 30, 2010 were as follows:

	Third Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(1.2	)	$	(3.5	)
Contracts realized or settled		3.3			3.8
Current period changes(a)		(4.1	)		(2.3	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(2.0	)	$	(2.0	)

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

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The changes in the fair value positions of the energy-related derivative contracts for the three and nine months ended September 30, 2010 were a decrease of $0.8 million and an increase of $1.5 million, respectively, which is due to both power and natural gas positions. This change is attributable to both the volume and prices of power and natural gas as follows:

	September 30,		June 30,		December 31,
	2010		2010		2009
Power (net sold)
MWHs(in millions)		0.7		0.7		2.7
Weighted average contract cost per MWH above (below) market prices(in dollars)	$	5.22	$	6.77	$	(0.36	)
Natural gas (net purchase)
Commodity – million mmBtu		9.3		5.6		8.3
Location basis – million mmBtu		—		—		2.0
Commodity – Weighted average contract cost per mmBtu above (below) market prices(in dollars)	$	0.69	$	1.31	$	0.29
Location basis – Weighted average contract cost per mmBtu above (below) market prices(in dollars)	$	—	$	—	$	(0.04	)

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

	September 30,			December 31,
Asset (Liability) Derivatives	2010			2009
	(in millions)
Cash flow hedges	$	1.5		$	(2.5	)
Not designated		(3.5	)		(1.0	)
Total fair value	$	(2.0	)	$	(3.5	)

Gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated as hedges are recognized in the statements of income as incurred.

Total net unrealized pre-tax gains (losses) recognized in income for the three and nine months ended September 30, 2010 for energy-related derivative contracts that are not hedges were $(3.7) million and $(2.4) million, respectively, and will continue to be marked to market until the settlement date. For the three and nine months ended September 30, 2009, the total net unrealized pre-tax gains (losses) recognized in the statements of income were $2 million and $1 million, respectively.

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. The maturities of the energy-related derivative contracts at September 30, 2010 were as follows:

	September 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
				(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(2.0	)		(1.3	)		(1.0	)		0.3
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(2.0	)	$	(1.3	)	$	(1.0	)	$	0.3

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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 Note 1 under “Financial Instruments” and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

Southern Power did not issue or redeem any long-term securities during the nine months ended September 30, 2010.

150

NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

INDEX TO APPLICABLE NOTES TO
FINANCIAL STATEMENTS BY REGISTRANT

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(A) INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2009 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, 2010 and 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 Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

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

Affiliate Transactions

In January 2010, Gulf Power purchased turbine rotor assembly parts owned by Georgia Power and Southern Power for approximately $4 million and $6 million, respectively. In June 2010, Mississippi Power purchased a turbine rotor assembly part from Gulf Power for approximately $6 million. In September 2010, Georgia Power purchased a compressor rotor assembly part owned by Gulf Power for approximately $4 million. In September 2010, Southern Power purchased turbine rotor assembly parts owned by Georgia Power, Gulf Power, and Mississippi Power for approximately $6 million, $1 million, and $7 million, respectively. These affiliate transactions were in accordance with FERC and state PSC rules and guidelines.

Variable Interest Entities

Effective January 1, 2010, the traditional operating companies and Southern Power adopted new accounting guidance which modified the consolidation model and expanded disclosures related to variable interest entities (VIE). The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the traditional operating companies or Southern Power consolidating any VIEs that were not already consolidated under previous guidance, nor deconsolidating any VIEs.

Mississippi Power is required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC (Liberty Fuels) in conjunction with the construction of Kemper IGCC described in Note (B) under “State PSC Matters — Mississippi Power — Integrated Coal Gasification Combined Cycle” herein. Liberty Fuels qualifies as a VIE for which Mississippi Power is the primary beneficiary. As of September 30, 2010, Liberty Fuels has not had a material impact on the financial position and results of operations of Mississippi Power.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Southern Power has certain wholly-owned subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.

(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 and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against 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 U.S. 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.

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).

Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for certain costs. As a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. If Southern Company’s claims for indemnification with respect to these costs are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. As a result of the $202 million settlement in March 2009 of another suit related to Mirant (MC Asset Recovery litigation), the maximum amount Southern Company can assert by proof of claim in the Mirant bankruptcy is capped at $9.5 million. See Note 5 to the financial statements of Southern Company under “Effective Tax Rate” in Item 8 of the Form 10-K for more information regarding the MC Asset Recovery litigation settlement. By settlement agreement, dated as of July 7, 2010, substantially all the claims filed by Southern Company against Mirant have been resolved. Pursuant to the agreement, Southern Company was given allowed unsecured claims against Mirant in the aggregate amount of approximately $8.8 million, which claims will be treated pursuant to the terms of the Mirant plan of reorganization. The parties also released each other from any other claims arising from events or conduct prior to the effective date of Mirant’s plan of reorganization, with certain limited exceptions. The settlement has been approved by the bankruptcy court. This matter is now concluded.

153

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including facilities co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely 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. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting.

On September 2, 2010, following the end of discovery, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to the facility co-owned by Mississippi Power. The parties each filed motions for summary judgment on September 30, 2010. The court has set a trial date for October 2011 for any remaining claims.

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

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, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the

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dismissal of the plaintiffs’ claim, and remanding the case to the district court. In November 2009, the defendants, including Southern Company, sought rehearing en banc. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. 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 some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

Other Litigation

Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, in October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. On August 27, 2010, the plaintiffs petitioned the U.S. Supreme Court for a writ of mandamus directing the U.S. Court of Appeals for the Fifth Circuit to reinstate the plaintiffs’ appeal. Southern Company is not currently a party to this litigation, but the traditional operating companies and Southern Power were named as defendants in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

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

Georgia Power’s environmental remediation liability as of September 30, 2010 was $13.8 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

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Sites Inventory and CERCLA NPL are anticipated; however, they are not expected to have a material impact on Georgia Power’s financial statements.

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, in April 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. 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 $62.2 million as of September 30, 2010. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates.

In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. Amounts expensed related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of PRPs. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan.

The final outcome of these matters cannot 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.

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 market power within its retail service territory. The ability to charge market-based rates in other markets was 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 have been subject to refund to a cost-based rate level.

In December 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that any subsidiary of Southern Company possesses or has exercised any market power. The agreement likewise does not require Southern Company to make any refunds related to sales during the 15-month refund period. The agreement does provide for the traditional operating companies and Southern Power to donate a total of $1.7 million to nonprofit organizations in the states in which they operate for the purpose of offsetting the electricity bills of low-income retail customers. The joint offer of settlement

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was filed on March 2, 2010. On July 13, 2010, the FERC issued an order approving the filed settlement, finding it to be fair, reasonable, and in the public interest. The traditional operating companies and Southern Power made the related donations. This matter is now concluded.

Intercompany Interchange Contract

Southern Company’s generation fleet in its retail service territory is operated under the Intercompany Interchange Contract (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 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. 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. 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 were submitted challenging the audit report’s findings of Southern Company’s compliance. The proceeding remains open pending a decision from the FERC regarding the audit report.

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.

Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and the related cases have been dismissed. These agreements have not resulted in any material effects on Southern Company’s or Mississippi Power’s financial statements.

In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network, 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. On August 24, 2010, the defendants filed a motion to dismiss the suit. The plaintiff has opposed this motion. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the

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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 approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley, Hatch, and Vogtle from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April 2008. On May 5, 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay.

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 U.S. Court of Appeals for the Federal Circuit 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, 2010 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.

Income Tax Matters

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power had 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. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia Department of Revenue has appealed to the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s or Georgia Power’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers. 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. See Note 5 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K under “Unrecognized Tax Benefits” and Note (G) herein for additional information. The ultimate outcome of this matter cannot now be determined.

Tax Method of Accounting for Repairs

Southern Company submitted a change in the tax accounting method for repair costs associated with Southern Company’s generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method is expected to result in net positive cash flow for 2010 of approximately $117 million for Alabama Power, $110 million for Georgia Power, $6 million for Gulf Power, $3 million for Mississippi Power, $5 million for Southern Power, and $243 million for Southern Company on a consolidated basis. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this issue. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this issue, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. See Note (G) herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

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Bonus Depreciation

On September 27, 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired in 2010 and placed in service in 2010 or, in certain limited cases, 2011. The estimated cash flow reduction to tax payments for 2010 are approximately $102 million for Alabama Power, $130 million for Georgia Power, $37 million for Gulf Power, $16 million for Mississippi Power, $3 million for Southern Power, and $309 million for Southern Company on a consolidated basis.

State PSC Matters

Alabama Power

Nuclear Outage Accounting Order

On August 17, 2010, the Alabama PSC approved a change to the nuclear maintenance outage accounting process associated with routine refueling activities. Currently, Alabama Power accrues nuclear outage operations and maintenance expenses for the two units of Plant Farley during the 18-month cycle for the outages. In accordance with the new order, nuclear outage expenses will be deferred when the charges actually occur and then amortized over the subsequent 18-month period.

The initial result of implementation of the new accounting order is that no nuclear maintenance outage expenses will be recognized from January 2011 through December 2011, which will decrease nuclear outage operations and maintenance expenses in 2011 from 2010 by approximately $50 million. During the fall of 2011, actual nuclear outage expenses associated with one unit of Plant Farley will be deferred to a regulatory asset account; beginning in January 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. During the spring of 2012, actual nuclear outage expenses associated with the other unit of Plant Farley will be deferred to a regulatory asset account; beginning in July 2012 these deferred costs will be amortized to nuclear operations and maintenance expense over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period.

Natural Disaster Cost Recovery

See Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery.

Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expense to cover the cost of damages from major storms to its transmission and distribution facilities, referred to as the NDR.

On August 20, 2010, the Alabama PSC approved an order enhancing the NDR that eliminated the $75 million authorized limit and allows Alabama Power to make additional accruals to the NDR. The order also allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power’s ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

The structure of the monthly Rate NDR charge to customers is not altered and continues to include a component to maintain the $75 million base reserve.

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In September 2010, Alabama Power accrued an additional $40 million to the NDR, resulting in an accumulated balance of approximately $118 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The additional accruals are reflected as operations and maintenance expense in the Condensed Statements of Income herein.

Georgia Power

Rate Plans

See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” and of Southern Company under “Retail Regulatory Matters – Georgia Power – Retail Rate Plans” and “– Cost of Removal” in Item 8 of the Form 10-K for information regarding the 2007 Retail Rate Plan.

On August 27, 2009, the Georgia PSC approved an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail return on equity (ROE). In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. From July 1, 2009 through September 30, 2010, Georgia Power had amortized $161 million of the regulatory liability. Georgia Power currently expects to amortize approximately $40 million of the regulatory liability in the fourth quarter 2010; however, the final amount is subject to the limitations described previously and cannot be determined at this time.

In accordance with the 2007 Retail Rate Plan, Georgia Power filed a base rate case with the Georgia PSC on July 1, 2010. The filing includes a requested rate increase totaling $615 million, or 8.2% of retail revenues, to be effective January 1, 2011 based on a proposed retail ROE of 11.95%. The requested increase will be recovered through Georgia Power’s existing base rate tariffs as follows: $451 million, or 6.0%, through the traditional base rate tariffs; $115 million, or 1.5%, through the Environmental Compliance Cost Recovery (ECCR) tariff; $32 million through the Demand Side Management (DSM) tariffs; and $17 million through the Municipal Franchise Fee (MFF) tariff. The majority of the increase in retail revenues is being requested to cover the costs of environmental compliance and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability. The remainder of the increase includes recovery of higher operation, maintenance, and other investment costs to meet the current and future demand for electricity.

Unlike rate plans based on traditional one-year test periods, the 2007 Retail Rate Plan was designed to operate for the three-year period ending December 31, 2010. The 2010 rate case request includes proposed enhancements to the structure of the 2007 Retail Rate Plan to fit the current economic climate, including a process of annual tariff compliance reviews that would allow it to continue to operate for multiple years (Proposed Alternate Rate Plan). The primary points of the Proposed Alternate Rate Plan include:

§	Continuation of a plus or minus 100 basis point range for ROE.
§	Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.
	The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.

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§	Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.
§	Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.
§	Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.

These proposed enhancements would become effective in 2012 with revenue requirements for each tariff updated through separate compliance filings based on Georgia Power’s budget for the upcoming year. Based on Georgia Power’s 2010 budget, earnings are currently projected to be slightly below the proposed ROE band in 2012 and within the band in 2013. However, updated budgets and revenue forecasts may eliminate, increase, or decrease the need for an ACR tariff adjustment in either year. In addition, Georgia Power currently estimates the ECCR tariff would increase by $120 million in 2012 and would decrease by $12 million in 2013. The CCCR tariff would begin recovering the costs of Plant McDonough Units 4, 5, and 6 with increases of $99 million in February 2012, $77 million in June 2012, and $76 million in February 2013. The DSM tariffs would increase by $17 million in 2012 and $18 million in 2013 to reflect the terms of the stipulated agreement in Georgia Power’s 2010 DSM Certification proceeding. Amounts recovered under the MFF tariff are based on amounts recovered under all other tariffs.

Hearings on Georgia Power’s direct testimony were held in October 2010. In direct testimony filed on October 22, 2010, the Georgia PSC Staff proposed various adjustments based on a traditional one-year test period that would result in a proposed increase of $436 million in 2011 using a 10.5% ROE. The Georgia PSC Staff recommendation would also allow additional increases of $181 million and $88 million in 2012 and 2013, respectively, to recover the costs associated with Plant McDonough Units 4, 5, and 6. These additional increases would be recovered through Georgia Power’s traditional base rate tariffs. While supporting the proposed DSM and MFF tariffs, the Georgia PSC Staff recommended against approval of the proposed ECCR, CCCR, and ACR tariffs. Georgia Power disagrees with the Georgia PSC Staff’s positions. Hearings on the Georgia PSC Staff and intervenor direct testimony will be held in November 2010. Georgia Power’s rebuttal hearings will occur in early December 2010. The Georgia PSC is scheduled to issue a final order in this matter on December 21, 2010.

The final outcome of these matters cannot now be determined.

Fuel Cost Recovery

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

On March 11, 2010, the Georgia PSC voted to approve the stipulation among Georgia Power, the Georgia PSC Staff, and three customer groups with the exception that the under recovered fuel balance be collected over 42 months. The new rates, which became effective April 1, 2010, will result in an increase of approximately $373 million to Georgia Power’s total annual fuel cost recovery billings. Georgia Power is required to file its next fuel case by March 1, 2011.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Construction – Nuclear,” respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power’s construction of two additional nuclear generating units on the site of Plant Vogtle (Plant Vogtle Units 3 and 4).

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In June 2009, the Southern Alliance for Clean Energy (SACE) 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 Financing Act. On May 5, 2010, the court dismissed as premature the plaintiffs’ claim challenging the Georgia Nuclear Energy Financing Act. The dismissal of the claim related to the Georgia Nuclear Energy Financing Act is subject to appeal and the plaintiffs are expected to re-file this claim in the future. In addition, on May 5, 2010, the court issued an order remanding the Georgia PSC’s certification order for inclusion of further findings of fact and conclusions of law by the Georgia PSC. In compliance with the court’s order, the Georgia PSC issued its order on remand to include further findings of fact and conclusions of law on June 23, 2010. On July 5, 2010, the SACE and the Fulton County Taxpayers Foundation, Inc. filed separate motions with the Georgia PSC for reconsideration of the order on remand. On August 17, 2010, the Georgia PSC voted to reaffirm its order. The SACE subsequently appealed to the Superior Court of Fulton County.

In August 2009 and June 2010, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors in response to 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.

On August 17, 2010, the Georgia PSC voted to approve Georgia Power’s semi-annual construction monitoring report including all construction and capital costs of $583 million made on Plant Vogtle Units 3 and 4 through December 31, 2009. The Georgia PSC also approved an amendment to the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 that replaced certain index-based adjustments with fixed escalation factors. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

On September 3, 2010, Georgia Power filed with the Georgia PSC the Nuclear Construction Cost Recovery tariff, as authorized in April 2009 under the Georgia Nuclear Energy Financing Act. The filing includes a rate increase of approximately $218 million to recover financing costs associated with the construction of Plant Vogtle Units 3 and 4, effective January 1, 2011.

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 be determined at this time.

Other

In August 2009, Georgia Power filed its quarterly construction monitoring report for Plant McDonough Units 4, 5, and 6 for the quarter ended June 30, 2009. In September 2009, Georgia Power amended the report. As amended, the report included a request for an increase in the certified costs to construct Plant McDonough. On February 24, 2010, Georgia Power reached a stipulation agreement with the Georgia PSC staff that was approved by the Georgia PSC on March 16, 2010. The stipulation resolved the June 30, 2009 construction monitoring report, including the approval of actual expenditures and the requested increase in the certified amount.

On May 6, 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. In addition, on September 7, 2010, the Georgia PSC approved the March 31, 2010 construction monitoring report including actual project expenditures incurred through March 31, 2010.

On September 21, 2010, the Georgia PSC approved Georgia Power’s offer to place 562 MWs of wholesale capacity into retail rate base. A portion of the capacity will go into retail rate base in January 2015, with the remainder going into retail rate base starting April 1, 2016.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Mississippi Power

Integrated Coal Gasification Combined Cycle

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

On March 9, 2010, the Mississippi Department of Environmental Quality issued the PSD air permit modification for the Kemper IGCC, which modifies the original PSD air permit issued in October 2008. The Mississippi Chapter of the Sierra Club has requested a formal evidentiary hearing regarding the issuance of the modified permit.

In addition to the Internal Revenue Code Section 48A Phase I tax credits of $133 million certified by the IRS in May 2009, Mississippi Power filed an application in November 2009 with the DOE and in December 2009 with the IRS for certain tax credits available to projects using advanced coal technologies under the Energy Improvement and Extension Act of 2008. The DOE subsequently certified the Kemper IGCC, and on April 30, 2010, the IRS allocated $279 million of Phase II tax credits under Section 48A of the Internal Revenue Code to Mississippi Power. On September 30, 2010, Mississippi Power and the IRS executed the closing agreement for the Phase II tax credits. The utilization of these credits is dependent upon meeting the IRS certification requirements and completing the Kemper IGCC in a timely manner. 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 these credits. In order to remain eligible for the Phase II tax credits, Mississippi Power must capture and sequester at least 65% of the carbon dioxide produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits, and must meet the required in-service date, satisfy environmental and other permitting requirements, and have in place a binding contract for the steam turbine generator.

On April 29, 2010, the Mississippi PSC issued an order finding that Mississippi Power’s application to acquire, construct, and operate the Kemper IGCC did not satisfy the requirement of public convenience and necessity in the form that the project and the related cost recovery were originally proposed by Mississippi Power. The April 2010 order also approved recovery of $46 million of $50.5 million in prudent pre-construction costs incurred through March 2009. The remaining $4.5 million is associated with overhead costs and variable pay of SCS, which were recommended for exclusion from pre-construction costs by a consultant hired by the Mississippi Public Utilities Staff. An additional $3.5 million has been incurred for costs of this type from March 2009 through May 2010. The remaining $4.5 million, as well as additional pre-construction amounts incurred during the generation screening and evaluation process through May 2010 will be reviewed and addressed in a future proceeding.

On May 10, 2010, Mississippi Power filed a motion in response to the April 29, 2010 order of the Mississippi PSC relating to the Kemper IGCC, or in the alternative, for alteration or rehearing of such order.

On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order (1) approved the alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the costs of the lignite mine and equipment), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity; (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal; and (3) approved financing cost recovery on construction work in progress (CWIP) balances under the State of Mississippi Baseload Act of 2008 (Baseload Act), which provides for the accrual of allowance for funds used during construction in 2010 and 2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, Mississippi

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Power filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted Mississippi Power’s motion and issued a certificate of public convenience and necessity authorizing acquisition, construction, and operation of the Kemper IGCC.

In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and will acquire mineral reserves located at the plant site in Kemper County. The estimated capital cost of the mine is approximately $214 million. On May 27, 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a subsidiary of The North American Coal Corporation, which will develop, construct, and manage the mining operations. The agreement is effective June 1, 2010 through the end of the mine reclamation.

On June 17, 2010, the Sierra Club filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant a certificate of public convenience and necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, on July 6, 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. On July 20, 2010, the Chancery Court issued a stay of the proceeding pending the resolution of the jurisdictional issues raised in a motion filed by Mississippi Power on July 16, 2010 to confirm jurisdiction in the Mississippi Supreme Court. On October 7, 2010, the Mississippi Supreme Court denied Mississippi Power’s motion and dismissed the Sierra Club’s direct appeal. The appeal will now proceed in the Chancery Court.

On July 27, 2010, Mississippi Power and South Mississippi Electric Power Association (SMEPA) entered into an Asset Purchase Agreement whereby SMEPA will purchase an undivided 17.5% interest in the Kemper IGCC. The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions.

On August 19, 2010, the National Environmental Policy Act (NEPA) Record of Decision (ROD) by the DOE for the Clean Coal Power Initiative Round 2 (CCPI2) grants was noted in the Federal Register. The NEPA ROD and its accompanying final environmental impact statement were the final major hurdles necessary for Mississippi Power to receive grant funds of $245 million during the construction of the Kemper IGCC and $25 million during the initial operation of the Kemper IGCC.

As of September 30, 2010, Mississippi Power had spent a total of $195.5 million on the Kemper IGCC, including regulatory filing costs. Of this total, $156.4 million was included in CWIP (net of $24.8 million recorded as a receivable of CCPI2 grant funds), $11.5 million was recorded in other regulatory assets, $1.3 million was recorded in other deferred charges and assets, and $1.5 million was expensed. Upon receipt of the issuance of the final certificate order in May 2010, construction screening costs including regulatory filing costs totaled $129.0 million. As of May 31, 2010, construction related screening costs of $116.2 million were reclassified to CWIP while the non-capital related costs of $11.2 million and $0.6 million were classified in other regulatory assets and other deferred charges, respectively, and $1.0 million was previously expensed.

The ultimate outcome of these matters cannot now be determined.

164

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(C) FAIR VALUE MEASUREMENTS

As of September 30, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of September 30, 2010:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	8
Interest rate derivatives		—		17		—		17
Foreign currency derivatives		—		5		—		5
Nuclear decommissioning trusts(a)(b)		758		390		—		1,148
Cash equivalents and restricted cash		1,082		—		—		1,082
Other investments		21		51		13		85
Total	$	1,861	$	471	$	13	$	2,345
Liabilities:
Energy-related derivatives	$	—	$	256	$	—	$	256
Interest rate derivatives		—		2		—		2
Total	$	—	$	258	$	—	$	258
Alabama Power
Assets:
Nuclear decommissioning trusts:(a)
Domestic equity	$	304	$	55	$	—	$	359
U.S. Treasury and government agency securities		20		8		—		28
Corporate bonds		—		86		—		86
Mortgage and asset backed securities		—		32		—		32
Other		—		10		—		10
Cash equivalents and restricted cash		319		—		—		319
Total	$	643	$	191	$	—	$	834
Liabilities:
Energy-related derivatives	$	—	$	54	$	—	$	54

165

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, 2010:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Georgia Power
Assets:
Nuclear decommissioning trusts:(a)
Domestic equity	$	434	$	1	$	—	$	435
U.S. Treasury and government agency securities		—		26		—		26
Municipal bonds		—		38		—		38
Corporate bonds		—		76		—		76
Mortgage and asset backed securities		—		41		—		41
Other		—		17		—		17
Cash equivalents		574		—		—		574
Total	$	1,008	$	199	$	—	$	1,207
Liabilities:
Energy-related derivatives	$	—	$	121	$	—	$	121
Gulf Power
Assets:
Cash equivalents	$	12	$	—	$	—	$	12
Liabilities:
Energy-related derivatives	$	—	$	18	$	—	$	18
Mississippi Power
Assets:
Foreign currency derivatives	$	—	$	5	$	—	$	5
Cash equivalents		125		—		—		125
Total	$	125	$	5	$	—	$	130
Liabilities:
Energy-related derivatives	$	—	$	54	$	—	$	54
Southern Power
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	9

(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 sections for Alabama Power and Georgia Power in this table.

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

“Other investments” include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.

For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and significant unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics.

A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts’ judgment are also obtained when available.

As of September 30, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

	Fair		Unfunded	Redemption	Redemption
As of September 30, 2010:	Value		Commitments	Frequency	Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Corporate bonds – commingled funds	$	35	None	Daily		1 to 3 days
Other – commingled funds		17	None	Daily	Not applicable
Trust owned life insurance		81	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		1,082	None	Daily	Not applicable
Other:
Deferred compensation – money market funds		1	None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Trust owned life insurance	$	81	None	Daily	15 days
Cash equivalents and restricted cash:
Money market funds		319	None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Corporate bonds – commingled funds	$	35	None	Daily		1 to 3 days
Other – commingled funds		17	None	Daily	Not applicable
Cash equivalents:
Money market funds		574	None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	12	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	125	None	Daily	Not applicable

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The commingled funds in the nuclear decommissioning trusts invest primarily in a diversified portfolio of investment high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset rate date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity.

Alabama Power’s nuclear decommissioning trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the tables above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.

Southern Company, Alabama Power, and Georgia Power account for investment securities held in the nuclear decommissioning trust funds at fair value. For the three months and nine months ended September 30, 2010, the increase in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $43 million and $27 million, respectively, for Alabama Power, $51 million and $25 million, respectively, for Georgia Power, and $94 million and $52 million, respectively, for Southern Company.

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investments in the money market funds.

Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at September 30, 2010 were as follows:

	Level 3
	Other
	Three Months Ended			Nine Months Ended
	September 30, 2010			September 30, 2010
	(in millions)
Beginning balance	$	19		$	35
Total gains (losses) — realized/unrealized:
Included in earnings		(1	)		(1	)
Included in OCI		(5	)		(1	)
Transfers out of Level 3		—			(20	)
Ending balance at September 30, 2010	$	13		$	13

Transfers in and out of the levels of fair value hierarchy are recognized as of the end of the reporting period. At March 31, 2010, the value of one of the investments was reclassified from Level 3 to Level 1 because the securities began trading on the public market. The reclassification is reflected in the table above as a transfer out of Level 3 at its fair value.

168

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 30, 2010, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
Southern Company	$	20,089	$	21,479
Alabama Power	$	6,183	$	6,679
Georgia Power	$	8,800	$	9,371
Gulf Power	$	1,297	$	1,386
Mississippi Power	$	617	$	657
Southern Power	$	1,298	$	1,424

The fair values were based on closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

(D) STOCKHOLDERS’ EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to 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 were as follows:

	Three Months		Three Months		Nine Months		Nine Months
	Ended		Ended		Ended		Ended
	September 30, 2010		September 30, 2009		September 30, 2010		September 30, 2009
	(in thousands)
As reported shares		835,953		798,418		828,947		789,675
Effect of options		5,882		1,760		4,273		1,584
Diluted shares		841,835		800,178		833,220		791,259

Stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive were 6.7 million and 25.5 million for the three months ended September 30, 2010 and 2009, respectively, and 13.7 million and 37.7 million for the nine months ended September 30, 2010 and 2009, respectively. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options would have increased by 0.4 million and 2.2 million shares for the three months ended September 30, 2010 and 2009, respectively, and 0.8 million and 3.3 million shares for the nine months ended September 30, 2010 and 2009, respectively.

169

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Changes in Stockholders’ Equity

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

									Preferred and
	Number of					Common			Preference		Total
	Common Shares					Stockholders’			Stock of		Stockholders’
	Issued		Treasury			Equity			Subsidiaries		Equity
	(in thousands)					(in millions)
Balance at December 31, 2009		820,152		(505	)	$	14,878		$	707	$	15,585
Net income after dividends on preferred and preference stock		—		—			1,822			—		1,822
Other comprehensive income (loss)		—		—			16			—		16
Stock issued		18,994		—			650			—		650
Cash dividends on common stock		—		—			(1,114	)		—		(1,114	)
Other		—		30			3			—		3
Balance at September 30, 2010		839,146		(475	)	$	16,255		$	707	$	16,962
Balance at December 31, 2008		777,616		(424	)	$	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		23,078		—			692			—		692
Cash dividends on common stock		—		—			(1,018	)		—		(1,018	)
Other		—		(58	)		(2	)		—		(2	)
Balance at September 30, 2009		800,694		(482	)	$	14,362		$	707	$	15,069

(E) FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants’ commercial paper borrowings and the traditional operating companies’ variable rate pollution control revenue bonds. See Note 6 to the financial statements of 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.

The following table outlines the credit arrangements by company as of September 30, 2010:

					Executable										Expires Within One
					Term-Loans				Expires						Year(a)
																	No
					One		Two								Term		Term
Company	Total		Unused		Year		Years		2010		2011		2012		Out		Out
	(in millions)
Southern Company	$	950	$	950	$	—	$	—	$	—	$	—	$	950	$	—	$	—
Alabama Power		1,271		1,271		372		—		60		446		765		372		134
Georgia Power		1,715		1,703		220		40		—		595		1,120		260		335
Gulf Power		235		235		205		—		50		185		—		205		30
Mississippi Power		161		161		65		41		16		145		—		106		55
Southern Power		400		400		—		—		—		—		400		—		—
Other		60		60		60		—		—		60		—		60		—
Total	$	4,792	$	4,780	$	922	$	81	$	126	$	1,431	$	3,235	$	1,003	$	554

(a) Reflects facilities expiring on or before September 30, 2011.

170

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Subsequent to September 30, 2010, Gulf Power renewed an existing credit agreement totaling $30 million and increased an existing credit agreement by $5 million; both agreements contain provisions allowing a one-year term loan executable at expiration and extended the expiration date to 2011.

(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 mandatory contributions to the plan are expected for the years ending December 31, 2010 and 2011, although management may consider making discretionary contributions. 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 net periodic benefit costs for the three and nine months ended September 30, 2010 and 2009 were as follows:

	Southern			Alabama			Georgia			Gulf			Mississippi
PENSION PLANS	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended September 30, 2010
Service cost	$	43		$	10		$	13		$	2		$	2
Interest cost		98			25			36			5			4
Expected return on plan assets		(138	)		(42	)		(54	)		(6	)		(5	)
Net amortization		11			3			4			—			1
Net cost (income)	$	14		$	(4	)	$	(1	)	$	1		$	2
Nine Months Ended September 30, 2010
Service cost	$	129		$	31		$	40		$	6		$	6
Interest cost		293			73			109			13			13
Expected return on plan assets		(413	)		(126	)		(164	)		(18	)		(16	)
Net amortization		32			8			11			1			2
Net cost (income)	$	41		$	(14	)	$	(4	)	$	2		$	5
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

171

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Southern			Alabama			Georgia			Gulf			Mississippi
POSTRETIREMENT BENEFITS	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended September 30, 2010
Service cost	$	6		$	2		$	3		$	—		$	—
Interest cost		25			7			11			1			2
Expected return on plan assets		(15	)		(7	)		(8	)		—			—
Net amortization		5			2			2			—			—
Net cost (income)	$	21		$	4		$	8		$	1		$	2
Nine Months Ended September 30, 2010
Service cost	$	19		$	5		$	7		$	1		$	1
Interest cost		75			20			33			3			4
Expected return on plan assets		(47	)		(19	)		(23	)		(1	)		(1	)
Net amortization		15			5			8			—			—
Net cost (income)	$	62		$	11		$	25		$	3		$	4
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

(G) EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

Effective Tax Rate

Southern Company’s effective tax rate was 33.1% for the nine months ended September 30, 2010, as compared to 36.5% for the corresponding period in 2009. Southern Company’s effective tax rate is lower than the statutory rate primarily due to its employee stock plans dividend deduction and AFUDC equity, which is not taxable. 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 decreased for the nine months ended September 30, 2010 as compared to September 30, 2009 primarily due to the $202 million charge for the MC Asset Recovery settlement, which occurred in the first quarter 2009. Southern Company is currently evaluating potential recovery of the settlement payment through various means including insurance, claims in U.S. Bankruptcy Court, and other avenues. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. Additionally, Georgia Power’s effective tax rate decreased for the nine months ended September 30, 2010 compared to September 30, 2009 from 34.7% to 32.3% primarily due to the recognition of additional Georgia state tax credits and additional AFUDC equity. Southern Power’s effective tax rate decreased for the nine months ended September 30, 2010 compared to September 30, 2009 from 38.5% to 32.3% primarily due to tax benefits associated with the construction of its biomass facility.

172

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Unrecognized Tax Benefits

Changes during 2010 for unrecognized tax benefits were as follows:

	Southern			Alabama		Georgia			Gulf		Mississippi		Southern
	Company			Power		Power			Power		Power		Power
	(in millions)
Unrecognized tax benefits as of December 31, 2009	$	199		$	6	$	181		$	2	$	3	$	—
Tax positions from current periods		37			1		35			—		—		1
Tax position increases from prior periods		67			31		32			1		—		1
Tax position decreases from prior periods		(32	)		—		(28	)		—		—		—
Reductions due to expired statute of limitations		—			—		—			—		—		—
Balance as of September 30, 2010	$	271		$	38	$	220		$	3	$	3	$	2

The tax positions increase from current periods relates primarily to the Georgia state tax credits litigation and other miscellaneous uncertain tax positions. The tax positions increase from prior periods relates primarily to the tax accounting method change for repairs and other miscellaneous uncertain tax positions. The tax position decrease from prior periods relates primarily to the Georgia state tax credits litigation. See Note (B) under “Income Tax Matters – Georgia State Income Tax Credits” and “Tax Method of Accounting for Repairs” herein for additional information.

The impact on Southern Company’s effective tax rate, if recognized, was as follows:

							As of
							December 31,
	As of September 30, 2010						2009
	Georgia				Southern		Southern
	Power		Other		Company		Company
	(in millions)
Tax positions impacting the effective tax rate	$	191	$	15	$	206	$	199
Tax positions not impacting the effective tax rate		29		36		65		—
Balance of unrecognized tax benefits	$	220	$	51	$	271	$	199

The tax positions impacting the effective tax rate primarily relate to Georgia state tax credit litigation at Georgia Power and the production activities deduction tax position. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note (B) under “Income Tax Matters – Georgia State Income Tax Credits” and “Tax Method of Accounting for Repairs” herein for additional information.

Accrued interest for unrecognized tax benefits was as follows:

	Georgia		Other		Southern
	Power		Registrants		Company
	(in millions)
Interest accrued as of December 31, 2009	$	20	$	1	$	21
Interest reclassified due to settlements		—		—		—
Interest accrued during the period		5		1		6
Balance as of September 30, 2010	$	25	$	2	$	27

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

It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of Southern Company’s and Georgia Power’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the Georgia state tax credits litigation would substantially reduce the balances. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

173

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(H) DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company’s policies in areas such as counterparty exposure and risk management practices. Each company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, 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 has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

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

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

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

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

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

174

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At September 30, 2010, 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, 2010:	MWH		Date		Date		mmBtu		Date		Date
	(in millions)						(in millions)
Southern Company		0.7		2010		2011		138		2014		2014
Alabama Power		—		—		—		34		2014		—
Georgia Power		—		—		—		61		2014		—
Gulf Power		—		—		—		14		2014		—
Mississippi Power		—		—		—		20		2014		—
Southern Power		0.7		2010		2011		9		2012		2014

In addition to the volumes discussed in the table above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 5 million mmBtu for Southern Company, 3 million mmBtu for Georgia Power, and less than 1 million mmBtu for each of the other registrants.

For the next 12-month period ending September 30, 2011, Southern Company and Southern Power expect to reclassify $5 million in gains from OCI to revenue and $2 million in losses from OCI to fuel expense with respect to cash flow hedges. Such amounts are immaterial for all other 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. Derivatives related to existing fixed rate securities are accounted for as fair value hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

For cash flow hedges, the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings. For fair value hedges, the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings, providing an offset with any difference representing ineffectiveness.

At September 30, 2010, the following interest rate derivatives were outstanding:

									Fair Value
								Hedge	Gain (Loss)
	Notional			Interest Rate	Interest Rate			Maturity	September 30,
	Amount			Received	Paid			Date	2010
	(in millions)								(in millions)
Cash flow hedges of existing debt
Southern Company	$	300	3-month LIBOR + 0.40% spread			1.24	%*	October 2011	$	(2	)
Fair value hedges of existing debt
Southern Company		350	4.15%		3-month LIBOR + 1.96%* spread			May 2014		17
Total	$	650							$	15

* Weighted Average

175

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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, 2011, 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, 2011			Amortized Through
	(in millions)
Southern Company	$	(18	)		2037
Alabama Power		1			2035
Georgia Power		(5	)		2037
Gulf Power		(1	)		2020
Southern Power		(11	)		2016

Foreign Currency Derivatives

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At September 30, 2010, the following foreign currency derivatives were outstanding:

				Fair Value
				Gain (Loss)
	Notional		Hedge	September 30,
	Amount	Forward Rate	MaturityDate	2010
	(in millions)			(in millions)
Cash flow hedges of forecasted transactions
Southern Company	YEN780	85.45 Yen per Dollar*	Various through May 2011	$	—
Fair value hedges of firm commitments
Mississippi Power	EUR36.7	1.228 Dollars per Euro*	Various through June 2012		5
Total				$	5

* Weighted Average

176

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Derivative Financial Statement Presentation and Amounts

At September 30, 2010, the fair value of energy-related derivatives, interest rate derivatives and foreign currency derivatives were reflected in the balance sheets as follows:

Asset Derivatives at September 30, 2010
	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 in cash flow and fair value hedges
Energy-related derivatives:
Other current assets*	$	5	$	—	$	—	$	—	$	—	$	—
Assets from risk management activities		—		—		—		—		—		5
Interest rate derivatives:
Other current assets		7		—		—		—		—		—
Other deferred charges and assets		10		—		—		—		—		—
Foreign currency derivatives:
Other current assets		3		—		—		—		3		—
Other deferred charges and assets		2		—		—		—		2		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	27	$	—	$	—	$	—	$	5	$	5
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets*	$	2	$	—	$	—	$	—	$	—	$	—
Assets from risk management activities		—		—		—		—		—		2
Other deferred charges and assets		1		—		—		—		—		—
Total derivatives not designated as hedging instruments	$	3	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	30	$	—	$	—	$	—	$	5	$	7

* Southern Company includes “Assets from risk management activities” in “Other current assets” where applicable.

177

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Liability Derivatives at September 30, 2010
	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	$	167	$	40	$	84	$	13	$	30
Other deferred credits and liabilities		80		14		37		5		24
Total derivatives designated as hedging instruments for regulatory purposes	$	247	$	54	$	121	$	18	$	54		N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities	$	2	$	—	$	—	$	—	$	—	$	2
Other deferred credits and liabilities		1		—		—		—		—		1
Interest rate derivatives:
Liabilities from risk management activities		2		—		—		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	5	$	—	$	—	$	—	$	—	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	5	$	—	$	—	$	—	$	—	$	5
Other deferred credits and liabilities		1		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	6	$	—	$	—	$	—	$	—	$	6
Total liability derivatives	$	258	$	54	$	121	$	18	$	54	$	9

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

At September 30, 2010, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheet 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	$	(167	)	$	(40	)	$	(84	)	$	(13	)	$	(30	)
Other regulatory assets, deferred		(80	)		(14	)		(37	)		(5	)		(24	)
Total energy-related derivative gains (losses)	$	(247	)	$	(54	)	$	(121	)	$	(18	)	$	(54	)

For the three months and nine months ended September 30, 2010, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were $9 million and $17 million, respectively. These amounts were offset with changes in the fair value of the hedged debt.

For the three months and nine months ended September 30, 2010, the pre-tax gains from foreign currency derivatives designated as fair value hedging instruments on Mississippi Power’s statements of income were $5 million. These amounts were offset with changes in the fair value of the purchase commitment related to equipment purchases.

178

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months ended September 30, 2010 and September 30, 2009, 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
	2010			2009				2010			2009
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	3		$	(1	)	Fuel	$	—		$	—
Interest rate derivatives		(1	)		(3	)	Interest expense		(7	)		(12	)
Total	$	2		$	(4	)		$	(7	)	$	(12	)
Alabama Power
Interest rate derivatives	$	—		$	(1	)	Interest expense	$	—		$	(3	)
Georgia Power
Interest rate derivatives	$	—		$	(1	)	Interest expense	$	(3	)	$	(6	)
Gulf Power
Interest rate derivatives	$	—		$	(1	)	Interest expense	$	—		$	—
Southern Power
Energy-related derivatives	$	3		$	(1	)	Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(3	)		(2	)
Total	$	3		$	(1	)		$	(3	)	$	(2	)

For the nine months ended September 30, 2010 and September 30, 2009, 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
	2010			2009				2010			2009
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	4		$	—		Fuel	$	—		$	—
Interest rate derivatives		(3	)		(6	)	Interest expense		(24	)		(34	)
Total	$	1		$	(6	)		$	(24	)	$	(34	)
Alabama Power
Interest rate derivatives	$	—		$	(5	)	Interest expense	$	(1	)	$	(9	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense	$	(13	)	$	(17	)
Gulf Power
Interest rate derivatives	$	(1	)	$	(1	)	Interest expense	$	(1	)	$	(1	)
Southern Power
Energy-related derivatives	$	4		$	—		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(8	)		(7	)
Total	$	4		$	—			$	(8	)	$	(7	)

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

179

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months ended September 30, 2010 and September 30, 2009, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

Derivatives not Designated	Unrealized Gain (Loss) Recognized in Income
as Hedging Instruments	Statements of Income Location	Amount
		2010			2009
		(in millions)
Southern Company
Energy-related derivatives	Wholesale revenues	$	(1	)	$	4
	Fuel		(1	)		(1	)
	Purchased power		(1	)		(1	)
Total		$	(3	)	$	2
Southern Power
Energy-related derivatives	Wholesale revenues	$	(1	)	$	4
	Fuel		(1	)		(1	)
	Purchased power		(1	)		(1	)
Total		$	(3	)	$	2

For the nine months ended September 30, 2010 and September 30, 2009, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

Derivatives not Designated	Unrealized Gain (Loss) Recognized in Income
as Hedging Instruments	Statements of Income Location	Amount
		2010			2009
		(in millions)
Southern Company
Energy-related derivatives	Wholesale revenues	$	—		$	9
	Fuel		(1	)		(4	)
	Purchased power		(1	)		(4	)
Total		$	(2	)	$	1
Southern Power
Energy-related derivatives	Wholesale revenues	$	—		$	9
	Fuel		(1	)		(4	)
	Purchased power		(1	)		(4	)
Total		$	(2	)	$	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, 2010, the fair value of derivative liabilities with contingent features, by registrant, was as follows:

	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power
	(in millions)
Derivative liabilities	$	51	$	9	$	33	$	2	$	6	$	1

At September 30, 2010, 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, was $51 million for each registrant.

180

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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.

(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. Revenues from sales by Southern Power to the traditional operating companies were $93 million and $288 million for the three months and nine months ended September 30, 2010, respectively, and $148 million and $421 million for the three months and nine months ended September 30, 2009, 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, renewable energy projects, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2010:
Operating revenues	$	5,066	$	357	$	(124	)	$	5,299	$	40		$	(19	)	$	5,320
Segment net income (loss)*		757		61		—			818		(1	)		—			817
Nine Months Ended September  30, 2010:
Operating revenues	$	13,127	$	862	$	(367	)	$	13,622	$	122		$	(59	)	$	13,685
Segment net income (loss)*		1,713		106		—			1,819		4			(1	)		1,822
Total assets at September 30, 2010	$	51,329	$	3,223	$	(176	)	$	54,376	$	1,092		$	(573	)	$	54,895
Three Months Ended September  30, 2009:
Operating revenues	$	4,543	$	283	$	(169	)	$	4,657	$	43		$	(18	)	$	4,682
Segment net income (loss)*		726		67		—			793		(2	)		(1	)		790
Nine Months Ended September  30, 2009:
Operating revenues	$	11,881	$	745	$	(471	)	$	12,155	$	130		$	(52	)	$	12,233
Segment net income (loss)*		1,449		126		—			1,575		(182	)		1			1,394
Total assets at December 31, 2009	$	48,403	$	3,043	$	(143	)	$	51,303	$	1,223		$	(480	)	$	52,046

* 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, 2010	$	4,573	$	566	$	160	$	5,299
Three Months Ended September 30, 2009		3,997		519		141		4,657
Nine Months Ended September 30, 2010	$	11,603	$	1,581	$	438	$	13,622
Nine Months Ended September 30, 2009		10,355		1,408		392		12,155

181

PART II — OTHER INFORMATION

Item 1.  Legal Proceedings.

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

Item 1A.  Risk Factors.

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

182

Item 6. Exhibits.

(4) Instruments Describing Rights of Security Holders, Including Indentures
Southern Company
(a)1	-	Sixth Supplemental Indenture to the Senior Note Indenture dated as of September 17, 2010, providing for the issuance of the Series 2010A 2.375% Senior Notes due September 15, 2015. (Designated in Form 8-K dated September 13, 2010, File No. 1-3526, as Exhibit 4.2.)
Alabama Power
(b)1	-	Forty-Fourth Supplemental Indenture to Senior Note Indenture dated as of October 5, 2010, providing for the issuance of the Series 2010A 3.375% Senior Notes due October 1, 2020. (Designated in Form 8-K dated September 27, 2010, File No. 1-3164, as Exhibit 4.2.)
Georgia Power
(c)1	-	Forty-Second Supplemental Indenture to Senior Note Indenture dated as of August 31, 2010, providing for the issuance of the Series 2010C 4.75% Senior Notes due September 1, 2040. (Designated in Form 8-K dated August 26, 2010, File No. 1-6468, as Exhibit 4.2.)
(c)2	-	Forty-Third Supplemental Indenture to Senior Note Indenture dated as of September 23, 2010, providing for the issuance of the Series 2010D 1.30% Senior Notes due September 15, 2013. (Designated in Form 8-K dated September 20, 2010, File No. 1-6468, as Exhibit 4.2.)
Gulf Power
(d)1	-	Seventeenth Supplemental Indenture to Senior Note Indenture dated as of September 17, 2010, providing for the issuance of the Series 2010B 5.10% Senior Notes due October 1, 2040. (Designated in Form 8-K dated September 9, 2010, File No. 001-31737, as Exhibit 4.2.)
(10) Material Contracts
Southern Company
(a)1	-	Base Salaries of Named Executive Officers.
(a)2	-	Restricted Stock Award Agreement between Southern Company and W. Paul Bowers dated July 27, 2010.
Alabama Power
(b)1	-	Base Salaries of Named Executive Officers.
(b)2	-	Deferred Compensation Agreement between Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and SCS and Philip C. Raymond dated September 15, 2010.
(b)3	-	Consulting Agreement between Jerry L. Stewart and SCS dated October 11, 2010.

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Gulf Power
(d)1	-	Base Salaries of Named Executive Officers.
(d)2	-	Deferred Compensation Agreement between Southern Company, Georgia Power, Gulf Power, and Southern Nuclear and Bentina C. Terry dated August 1, 2010.
(d)3	-	Deferred Compensation Agreement between Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and SCS and Philip C. Raymond dated September 15, 2010. See Exhibit 10(b)2 herein.
Mississippi Power
(e)1	-	Base Salaries of Named Executive Officers.
(e)2	-	Retention Agreement between Edward Day, VI and SCS dated January 22, 2008, Amendment to Retention Agreement dated December 12, 2008, and Amendment of Retention Agreement dated July 29, 2010.
(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, 2009, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.)
(a)2	-	Power of Attorney for Art P. Beattie.
Alabama Power
(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)
(b)2	-	Power of Attorney for Philip C. Raymond.
Georgia Power
(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)
Gulf Power
(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 001-31737 as Exhibit 24(d) and incorporated herein by reference.)
(d)2	-	Power of Attorney for Richard S. Teel.
Mississippi Power
(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.)
(e)2	-	Power of Attorney for Edward Day, VI.

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(e)3	-	Power of Attorney for Moses H. Feagin.
Southern Power
(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)
(f)2	-	Power of Attorney for Oscar C. Harper.
(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.

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Southern Power
(f)1	-	Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(f)2	-	Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(32) Section 906 Certifications
Southern Company
(a)	-	Certificate of Southern Company’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Alabama Power
(b)	-	Certificate of Alabama Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Georgia Power
(c)	-	Certificate of Georgia Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Gulf Power
(d)	-	Certificate of Gulf Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Mississippi Power
(e)	-	Certificate of Mississippi Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
Southern Power
(f)	-	Certificate of Southern Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

186

(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

187

THE SOUTHERN COMPANY

SIGNATURES

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

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

Date: November 5, 2010

188

ALABAMA POWER COMPANY

SIGNATURES

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

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

Date: November 5, 2010

189

GEORGIA POWER COMPANY

SIGNATURES

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

	GEORGIA POWER COMPANY
By	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/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 5, 2010

190

GULF POWER COMPANY

SIGNATURES

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

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

Date: November 5, 2010

191

MISSISSIPPI POWER COMPANY

SIGNATURES

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

	MISSISSIPPI POWER COMPANY
By	Edward Day, VI
	President and Chief Executive Officer (Principal Executive Officer)
By	Moses H. Feagin
	Vice President, Treasurer, and Chief Financial Officer (Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 5, 2010

192

SOUTHERN POWER COMPANY

SIGNATURES

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

	SOUTHERN POWER COMPANY
By	Oscar C. Harper
	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/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 5, 2010

193