Mississippi Power (MSPWP) 10-Q 2009 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

OR

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

For the transition period from                    to                    

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
1-3526	The Southern Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000	58-0690070
1-3164	Alabama Power Company (An Alabama Corporation) 600 North 18th Street Birmingham, Alabama 35291 (205) 257-1000	63-0004250
1-6468	Georgia Power Company (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526	58-0257110
0-2429	Gulf Power Company (A Florida Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111	59-0276810
001-11229	Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Gulfport, Mississippi 39501 (228) 864-1211	64-0205820
333-98553	Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000	58-2598670

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

     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 June 30, 2009
The Southern Company	Par Value $5 Per Share		796,051,643
Alabama Power Company	Par Value $40 Per Share		25,475,000
Georgia Power Company	Without Par Value		9,261,500
Gulf Power Company	Without Par Value		3,142,717
Mississippi Power Company	Without Par Value		1,121,000
Southern Power Company	Par Value $0.01 Per Share		1,000

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

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2009

		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		34
	Condensed Statements of Comprehensive Income		34
	Condensed Statements of Cash Flows		35
	Condensed Balance Sheets		36
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		38
	Georgia Power Company
	Condensed Statements of Income		54
	Condensed Statements of Comprehensive Income		54
	Condensed Statements of Cash Flows		55
	Condensed Balance Sheets		56
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		58
	Gulf Power Company
	Condensed Statements of Income		73
	Condensed Statements of Comprehensive Income		73
	Condensed Statements of Cash Flows		74
	Condensed Balance Sheets		75
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		77
	Mississippi Power Company
	Condensed Statements of Income		93
	Condensed Statements of Comprehensive Income		93
	Condensed Statements of Cash Flows		94
	Condensed Balance Sheets		95
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		97
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		115
	Condensed Consolidated Statements of Comprehensive Income		115
	Condensed Consolidated Statements of Cash Flows		116
	Condensed Consolidated Balance Sheets		117
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		119
	Notes to the Condensed Financial Statements		132
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		32
Item 4.	Controls and Procedures		32
Item 4T.	Controls and Procedures		32

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2009

		Page
		Number
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		162
Item 1A.	Risk Factors		162
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Submission of Matters to a Vote of Security Holders		162
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits		166
	Signatures		170

4

DEFINITIONS

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

5

DEFINITIONS
(continued)

Term	Meaning
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
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, storm damage cost recovery and repairs, fuel cost recovery and other rate actions, environmental regulations and expenditures, retail return on equity projections, access to sources of capital, projections for postretirement benefit and nuclear decommissioning trust contributions, financing activities, completion of construction projects, plans and estimated costs for new generation resources, impacts of adoption of new accounting rules, potential exemptions from ad valorem taxation of the Kemper IGCC project, unrecognized tax benefits related to leveraged lease transactions, impact of the American Recovery and Reinvestment Act of 2009, estimated sales and purchases under new power sale and purchase agreements, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, environmental laws including regulation of water quality and emissions of sulfur, nitrogen, mercury, carbon, soot, or particulate matter and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

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

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

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

• available sources and costs of fuels;

• effects of inflation;

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

• investment performance of Southern Company’s employee benefit plans;

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and storm restoration cost recovery and including Georgia Power’s pending accounting order request;

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

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

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

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

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

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

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

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

• the ability of Southern Company and its subsidiaries to obtain additional generating capacity at competitive prices;

• catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, droughts, pandemic health events such as an avian or other influenza, or other similar occurrences;

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

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

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

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

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 Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	3,293,012		$	3,449,878		$	6,357,671		$	6,455,492
Wholesale revenues		437,750			591,802			889,164			1,105,464
Other electric revenues		128,403			141,162			251,201			271,352
Other revenues		25,999			32,345			53,435			65,789
Total operating revenues		3,885,164			4,215,187			7,551,471			7,898,097
Operating Expenses:
Fuel		1,449,138			1,622,074			2,855,405			3,074,017
Purchased power		133,188			197,260			240,832			290,164
Other operations and maintenance		831,214			914,998			1,702,295			1,811,815
MC Asset Recovery litigation settlement		—			—			202,000			—
Depreciation and amortization		377,341			358,745			767,099			702,630
Taxes other than income taxes		208,089			198,042			407,969			387,314
Total operating expenses		2,998,970			3,291,119			6,175,600			6,265,940
Operating Income		886,194			924,068			1,375,871			1,632,157
Other Income and (Expense):
Allowance for equity funds used during construction		47,500			35,486			90,112			76,071
Interest income		4,870			1,188			11,778			10,993
Equity in income (losses) of unconsolidated subsidiaries		680			1,097			(296	)		1,425
Leveraged lease income (losses)		8,676			(70,879	)		18,117			(59,954	)
Gain on disposition of lease termination		26,300			—			26,300			—
Loss on extinguishment of debt		(17,184	)		—			(17,184	)		—
Interest expense, net of amounts capitalized		(232,830	)		(228,948	)		(458,557	)		(446,057	)
Other income (expense), net		(3,681	)		(4,483	)		(16,531	)		(3,569	)
Total other income and (expense)		(165,669	)		(266,539	)		(346,261	)		(421,091	)
Earnings Before Income Taxes		720,525			657,529			1,029,610			1,211,066
Income taxes		225,717			224,952			392,886			403,090
Consolidated Net Income		494,808			432,577			636,724			807,976
Dividends on Preferred and Preference Stock of Subsidiaries		16,195			16,195			32,390			32,390
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	478,613		$	416,382		$	604,334		$	775,586
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.61		$	0.54		$	0.77		$	1.01
Diluted EPS	$	0.60		$	0.54		$	0.77		$	1.00
Average number of shares of common stock outstanding (in thousands)
Basic		790,748			769,122			785,303			767,636
Diluted		792,068			773,140			786,865			771,727
Cash dividends paid per share of common stock	$	0.4375		$	0.4200		$	0.8575		$	0.8225

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 Six Months
	Ended June 30,
	2009			2008
	(in thousands)
Operating Activities:
Consolidated net income	$	636,724		$	807,976
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		895,354			831,790
Deferred income taxes and investment tax credits		(13,807	)		(79,033	)
Deferred revenues		(26,295	)		57,768
Allowance for equity funds used during construction		(90,112	)		(76,071	)
Equity in income (losses) of unconsolidated subsidiaries		296			(1,425	)
Leveraged lease income (losses)		(18,117	)		59,954
Gain on disposition of lease termination		(26,300	)		—
Loss on extinguishment of debt		17,184			—
Pension, postretirement, and other employee benefits		(10,939	)		24,596
Stock option expense		18,956			15,734
Hedge settlements		(16,167	)		17,289
Other, net		27,948			(3,969	)
Changes in certain current assets and liabilities —
-Receivables		74,770			(317,403	)
-Fossil fuel stock		(375,888	)		(121,823	)
-Materials and supplies		(20,079	)		(28,609	)
-Other current assets		(96,394	)		(54,536	)
-Accounts payable		14,711			161,703
-Accrued taxes		(140,308	)		181,105
-Accrued compensation		(298,670	)		(185,500	)
-Other current liabilities		66,748			121,337
Net cash provided from operating activities		619,615			1,410,883
Investing Activities:
Property additions		(2,192,959	)		(1,983,177	)
Investment in restricted cash from pollution control revenue bonds		(49,478	)		(161	)
Distribution of restricted cash from pollution control revenue bonds		59,741			32,908
Nuclear decommissioning trust fund purchases		(823,416	)		(405,999	)
Nuclear decommissioning trust fund sales		788,690			399,119
Proceeds from property sales		339,903			5,495
Cost of removal, net of salvage		(63,705	)		(40,757	)
Change in construction payables		128,101			3,174
Other investing activities		8,063			(34,547	)
Net cash used for investing activities		(1,805,060	)		(2,023,945	)
Financing Activities:
Increase (decrease) in notes payable, net		148,090			(151,513	)
Proceeds —
Long-term debt issuances		1,785,474			1,684,935
Common stock issuances		539,088			235,454
Redemptions —
Long-term debt		(199,929	)		(361,263	)
Redeemable preferred stock		—			(125,000	)
Payment of common stock dividends		(670,226	)		(630,594	)
Payment of dividends on preferred and preference stock of subsidiaries		(32,465	)		(33,273	)
Other financing activities		(19,327	)		(12,267	)
Net cash provided from financing activities		1,550,705			606,479
Net Change in Cash and Cash Equivalents		365,260			(6,583	)
Cash and Cash Equivalents at Beginning of Period		416,581			200,550
Cash and Cash Equivalents at End of Period	$	781,841		$	193,967
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $38,594 and $39,434 capitalized for 2009 and 2008, respectively)	$	386,729		$	389,466
Income taxes (net of refunds)	$	468,278		$	280,902

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 June 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	781,841		$	416,581
Restricted cash and cash equivalents		96,540			102,537
Receivables —
Customer accounts receivable		1,149,309			1,053,674
Unbilled revenues		453,022			320,439
Under recovered regulatory clause revenues		547,927			646,318
Other accounts and notes receivable		335,712			301,028
Accumulated provision for uncollectible accounts		(27,273	)		(26,326	)
Fossil fuel stock, at average cost		1,387,738			1,018,314
Materials and supplies, at average cost		773,721			756,746
Vacation pay		134,958			140,283
Prepaid expenses		364,463			301,570
Other regulatory assets, current		322,790			275,424
Other current assets		68,622			51,044
Total current assets		6,389,370			5,357,632
Property, Plant, and Equipment:
In service		51,880,917			50,618,219
Less accumulated depreciation		18,739,799			18,285,800
Plant in service, net of depreciation		33,141,118			32,332,419
Nuclear fuel, at amortized cost		546,217			510,274
Construction work in progress		3,810,611			3,035,795
Total property, plant, and equipment		37,497,946			35,878,488
Other Property and Investments:
Nuclear decommissioning trusts, at fair value		940,499			864,396
Leveraged leases		599,569			897,338
Miscellaneous property and investments		227,196			226,757
Total other property and investments		1,767,264			1,988,491
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,010,624			972,781
Unamortized debt issuance expense		215,437			207,763
Unamortized loss on reacquired debt		260,614			270,919
Deferred under recovered regulatory clause revenues		364,728			606,483
Other regulatory assets, deferred		2,553,505			2,636,217
Other deferred charges and assets		357,561			428,432
Total deferred charges and other assets		4,762,469			5,122,595
Total Assets	$	50,417,049		$	48,347,206

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 June 30,			At December 31,
Liabilities and Stockholders’ Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,095,586		$	616,415
Notes payable		1,093,217			953,437
Accounts payable		1,419,534			1,249,694
Customer deposits		319,842			302,495
Accrued taxes —
Accrued income taxes		95,345			195,922
Unrecognized tax benefits		150,344			131,641
Other accrued taxes		301,852			396,206
Accrued interest		222,382			195,500
Accrued vacation pay		168,273			178,519
Accrued compensation		162,969			446,718
Liabilities from risk management activities		267,977			260,977
Other current liabilities		365,441			298,711
Total current liabilities		5,662,762			5,226,235
Long-term Debt		17,921,409			16,816,438
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		6,151,050			6,080,104
Deferred credits related to income taxes		261,840			259,156
Accumulated deferred investment tax credits		443,128			455,398
Employee benefit obligations		2,029,596			2,057,424
Asset retirement obligations		1,217,956			1,182,769
Other cost of removal obligations		1,327,726			1,320,558
Other regulatory liabilities, deferred		217,020			261,970
Other deferred credits and liabilities		319,029			329,534
Total deferred credits and other liabilities		11,967,345			11,946,913
Total Liabilities		35,551,516			33,989,586
Redeemable Preferred Stock of Subsidiaries		374,496			374,496
Stockholders’ Equity:
Common Stockholders’ Equity:
Common stock, par value $5 per share —
Authorized — 1 billion shares
Issued — June 30, 2009: 796,509,669 Shares;
— December 31, 2008: 777,615,751 Shares
Treasury — June 30, 2009: 458,026 Shares;
— December 31, 2008: 423,477 Shares
Par value		3,982,521			3,888,041
Paid-in capital		2,356,636			1,892,802
Treasury, at cost		(13,299	)		(12,279	)
Retained earnings		7,546,424			7,611,977
Accumulated other comprehensive loss		(88,612	)		(104,784	)
Total Common Stockholders’ Equity		13,783,670			13,275,757
Preferred and Preference Stock of Subsidiaries		707,367			707,367
Total Stockholders’ Equity		14,491,037			13,983,124
Total Liabilities and Stockholders’ Equity	$	50,417,049		$	48,347,206

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 Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Consolidated Net Income	$	494,808		$	432,577		$	636,724		$	807,976
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1,744), $2,571, $(982), and $(11,417), respectively		(2,811	)		4,338			(1,664	)		(17,913	)
Reclassification adjustment for amounts included in net income, net of tax of $4,630, $2,371, $8,463, and $4,149, respectively		7,370			3,733			13,468			6,508
Marketable securities:
Change in fair value, net of tax of $1,204, $(319), $1,295, and $(2,456), respectively		2,935			(925	)		3,669			(4,026	)
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $221, $277, $443, and $536, respectively		349			471			699			882
Total other comprehensive income (loss)		7,843			7,617			16,172			(14,549	)
Dividends on preferred and preference stock of subsidiaries		(16,195	)		(16,195	)		(32,390	)		(32,390	)
Comprehensive Income	$	486,456		$	423,999		$	620,506		$	761,037

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

13

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

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

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$62.2	14.9	$(171.3)	(22.1)

Southern Company’s second quarter 2009 net income after dividends on preferred and preference stock of subsidiaries was $478.6 million ($0.61 per share) compared to $416.4 million ($0.54 per share) for the second quarter 2008. The increase for the second quarter 2009 when compared to the corresponding period in 2008 was primarily the result of an increase in customer charges at Alabama Power, increased recognition of environmental compliance cost recovery revenues at Georgia Power, lower operations and maintenance expenses, a 2008 charge related to tax treatment of leveraged lease investments, and a gain on the early termination of two international leveraged lease investments. The increase for the second quarter 2009 was partially offset by a decrease in revenues from lower KWH sales, a decrease in revenues from market-response rates to large commercial and industrial customers, and higher depreciation and amortization.

Southern Company’s year-to-date 2009 net income after dividends on preferred and preference stock of subsidiaries was $604.3 million ($0.77 per share) compared to $775.6 million ($1.01 per share) for year-to-date 2008. The decrease for year-to-date 2009 when compared to the corresponding period in 2008 was primarily the result of a litigation settlement with MC Asset Recovery, LLC (MC Asset Recovery), a decrease in revenues from lower KWH sales, a decrease in revenues from market-response rates to large commercial and industrial customers, and higher depreciation and amortization. The decrease for year-to-date 2009 was partially offset by an increase in customer charges at Alabama Power, increased recognition of environmental compliance cost recovery revenues at Georgia Power, lower operations and maintenance expenses, a 2008 charge related to tax treatment of leveraged lease investments, and a gain on the early termination of two international leveraged lease investments.

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

Retail Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(156.9)	(4.5)	$(97.8)	(1.5)

In the second quarter 2009, retail revenues were $3.29 billion compared to $3.45 billion for the corresponding period in 2008.

For year-to-date 2009, retail revenues were $6.36 billion compared to $6.46 billion for the corresponding period in 2008.

Details of the change to retail revenues are as follows:

	Second Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	3,449.9					$	6,455.5
Estimated change in —
Rates and pricing		7.7			0.2			85.7			1.3
Sales growth (decline)		(82.6	)		(2.4	)		(139.1	)		(2.2	)
Weather		8.3			0.3			4.4			0.1
Fuel and other cost recovery		(90.3	)		(2.6	)		(48.8	)		(0.7	)
Retail – current year	$	3,293.0			(4.5	)%	$	6,357.7			(1.5	)%

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

Revenues attributable to changes in sales declined in the second quarter and for year-to-date 2009 when compared to the corresponding periods in 2008 due to decreases in weather-adjusted retail KWH sales of 6.8% and 6.5%, respectively, resulting primarily from recessionary economic conditions. For the second quarter 2009, weather-adjusted residential KWH sales decreased 1.6%, weather-adjusted commercial KWH sales decreased 0.5%, and weather-adjusted industrial KWH sales decreased 17.7%. For year-to-date 2009, weather-adjusted residential KWH sales decreased 1.0%, weather-adjusted commercial KWH sales decreased 0.9%, and weather-adjusted industrial KWH sales decreased 17.3%. Reduced demand in the primary metals and chemical sectors contributed to the decreases in weather-adjusted industrial KWH sales in the second quarter and for year-to-date 2009 when compared to the corresponding periods in 2008. Reduced demand in the stone, clay, and glass sector also contributed to the second quarter 2009 decrease in weather-adjusted industrial KWH sales.

Revenues resulting from changes in weather increased in the second quarter 2009 and for year-to-date 2009 as a result of more favorable weather when compared to the corresponding periods in 2008.

Fuel and other cost recovery revenues decreased $90.3 million in the second quarter 2009 and $48.8 million for year-to-date 2009 when compared to the corresponding periods in 2008. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

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

Wholesale Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(154.0)	(26.0)	$(216.3)	(19.6)

In the second quarter 2009, wholesale revenues were $437.8 million compared to $591.8 million for the corresponding period in 2008. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $143.3 million in the second quarter 2009 when compared to the corresponding period in 2008. Excluding wholesale fuel revenues, wholesale revenues decreased $10.7 million in the second quarter 2009 when compared to the corresponding period in 2008. The decrease was primarily the result of fewer short-term opportunity sales due to lower energy prices, partially offset by additional revenues associated with Plant Franklin Unit 3 at Southern Power which went into service in June 2008.

For year-to-date 2009, wholesale revenues were $889.2 million compared to $1.11 billion for the corresponding period in 2008. Wholesale fuel revenues, which are generally offset by wholesale fuel expenses and do not affect net income, decreased $225.2 million for year-to-date 2009 when compared to the corresponding period in 2008. Excluding wholesale fuel revenues, wholesale revenues increased $8.9 million for year-to-date 2009 when compared to the corresponding period in 2008. The increase was primarily the result of additional revenues associated with Plant Franklin Unit 3 at Southern Power, returns on new and existing wholesale contracts, and changes in mark-to-market positions on sales of uncontracted generating capacity. Fewer short-term opportunity sales due to lower energy prices partially offset this increase.

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

Other Electric Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(12.8)	(9.0)	$(20.2)	(7.4)

In the second quarter 2009, other electric revenues were $128.4 million compared to $141.2 million for the corresponding period in 2008. The decrease was primarily the result of a $15.3 million decrease in co-generation revenues due to lower gas prices and a decline in sales volume, partially offset by a $4.4 million increase in transmission revenues.

For year-to-date 2009, other electric revenues were $251.2 million compared to $271.4 million for the corresponding period in 2008. The decrease was the result of a $21.6 million decrease in co-generation revenues due to lower gas prices and a decline in sales volume.

Revenues from co-generation are generally offset by related expenses 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

Other Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(6.3)	(19.6)	$(12.4)	(18.8)

In the second quarter 2009, other revenues were $26.0 million compared to $32.3 million for the corresponding period in 2008. The decrease was primarily the result of a $6.4 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers as a result of increased competition in the industry when compared to the corresponding period in 2008.

For year-to-date 2009, other revenues were $53.4 million compared to $65.8 million for the corresponding period in 2008. The decrease was primarily the result of a $12.1 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers as a result of increased competition in the industry when compared to the corresponding period in 2008.

Fuel and Purchased Power Expenses

	Second Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Second Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(172.9	)		(10.7	)	$	(218.6	)		(7.1	)
Purchased power		(64.1	)		(32.5	)		(49.3	)		(17.0	)
Total fuel and purchased power expenses	$	(237.0	)				$	(267.9	)

Fuel and purchased power expenses for the second quarter 2009 were $1.58 billion compared to $1.82 billion for the corresponding period in 2008. The decrease was primarily the result of a $204.3 million net decrease related to total KWHs generated and purchased and a $32.7 million net decrease in the average cost of fuel and purchased power when compared to the corresponding period in 2008. The net decrease in the average cost of fuel and purchased power for the second quarter 2009 resulted from lower fossil fuel prices when compared to the corresponding period in 2008.

For year-to-date 2009, fuel and purchased power expenses were $3.10 billion compared to $3.36 billion for the corresponding period in 2008. The decrease was primarily the result of a $326.3 million net decrease related to total KWHs generated and purchased, partially offset by a $58.4 million net increase in the average cost of fuel and purchased power, primarily related to a 23.7% increase in the cost of coal per net KWH generated, when compared to the corresponding period in 2008.

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

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

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

	Second Quarter		Second Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2009		2008		Change			2009		2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		3.29		3.29		—			3.34		3.18		5.0
Purchased power		7.79		9.61		(18.9	)		6.31		8.28		(23.8	)

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

Other Operations and Maintenance Expenses

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(83.8)	(9.2)	$(109.5)	(6.0)

In the second quarter 2009, other operations and maintenance expenses were $831.2 million compared to $915.0 million for the corresponding period in 2008. The decrease was primarily the result of a $28.2 million decrease in fossil and hydro expenses mainly due to less planned spending on outages and maintenance; a $27.2 million decrease in transmission and distribution expenses mainly due to lower maintenance expenses; a $10.8 million decrease in administrative and general expenses primarily related to employee medical expenses; a $5.8 million decrease in expenses related to lower advertising, litigation, and property insurance costs; a $5.5 million decrease in expenses primarily related to lower sales volume at SouthernLINC Wireless; and a $5.3 million decrease in expenses related to customer service and sales.

For year-to-date 2009, other operations and maintenance expenses were $1.70 billion compared to $1.81 billion for the corresponding period in 2008. The decrease was primarily the result of a $53.2 million decrease in fossil and hydro expenses mainly due to less planned spending on outages and maintenance; a $41.2 million decrease in transmission and distribution expenses mainly due to lower maintenance and metering expenses; a $13.1 million decrease in expenses related to lower advertising, litigation, and property insurance costs; a $10.1 million decrease in expenses primarily related to lower sales volume at SouthernLINC Wireless; and a $6.9 million decrease in expenses related to customer service and sales. This decrease was partially offset by a $16.3 million increase in administration and general expenses largely related to the $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition program at Georgia Power under which 579 employees elected to resign their positions effective March 31, 2009. In the second quarter 2009, approximately one-third of the $29.4 million charge was offset by lower salary and employee benefits costs, and the other two-thirds will be offset during the remainder of the year. This charge is not expected to have a material impact on Southern Company’s financial statements for the year ending December 31, 2009.

MC Asset Recovery Litigation Settlement

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(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. See Note (B) to the Condensed Financial Statements under “Mirant Matters – MC Asset Recovery Litigation” herein for additional information.

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

Depreciation and Amortization

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$18.6	5.2	$64.5	9.2

In the second quarter 2009, depreciation and amortization was $377.3 million compared to $358.7 million for the corresponding period in 2008. The increase was primarily the result of an increase in plant in service related to environmental, transmission, and distribution projects at Georgia Power; an increase in depreciation rates at Southern Power; and the completion of Southern Power’s Plant Franklin Unit 3 in June 2008.

For year-to-date 2009, depreciation and amortization was $767.1 million compared to $702.6 million for the corresponding period in 2008. The increase was primarily the result of an increase in plant in service related to environmental, transmission, and distribution projects at Alabama Power and Georgia Power; an increase in depreciation rates at Southern Power; and the completion of Southern Power’s Plant Franklin Unit 3 in June 2008.

Taxes Other Than Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$10.1	5.1	$20.7	5.3

In the second quarter 2009, taxes other than income taxes were $208.1 million compared to $198.0 million for the corresponding period in 2008.

For year-to-date 2009, taxes other than income taxes were $408.0 million compared to $387.3 million for the corresponding period in 2008.

The second quarter and year-to-date 2009 increases were primarily the result of increases in state and municipal public utility license tax bases at Alabama Power, higher ad valorem taxes at Georgia Power, and increases in franchise fees at Gulf Power. Increases in franchise fees are associated with increases in revenues from retail energy sales.

Allowance for Equity Funds Used During Construction

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$12.0	33.9	$14.0	18.5

In the second quarter 2009, allowance for equity funds used during construction (AFUDC) was $47.5 million compared to $35.5 million for the corresponding period in 2008.

For year-to-date 2009, AFUDC was $90.1 million compared to $76.1 million for the corresponding period in 2008.

The second quarter and year-to-date 2009 increases were primarily the result of additional investments in environmental projects mainly at Alabama Power and Gulf Power.

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

Leveraged Lease Income (Losses)

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$79.6	112.2	$78.1	130.2

In the second quarter 2009, leveraged lease income (losses) was $8.7 million compared to $(70.9) million for the corresponding period in 2008.

For year-to-date 2009, leveraged lease income (losses) was $18.1 million compared to $(60.0) million for the corresponding period in 2008.

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

Gain on Disposition of Lease Termination

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$26.3	N/M	$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

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$17.2	N/M	$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

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$3.9	1.7	$12.5	2.8

In the second quarter 2009, interest expense, net of amounts capitalized was $232.8 million compared to $228.9 million for the corresponding period in 2008. The increase when compared to the corresponding period in 2008 was not material.

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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 2009, interest expense, net of amounts capitalized was $458.6 million compared to $446.1 million for the corresponding period in 2008. The increase was primarily due to a $53.0 million increase associated with $2.46 billion in additional debt outstanding at June 30, 2009 compared to June 30, 2008. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Southern Company in Item 7 of the Form 10-K and herein for additional information. Partially offsetting this increase was $30.2 million related to lower average interest rates on existing variable rate debt and an $11.2 million decrease related to other interest charges.

Other Income (Expense), Net

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$0.8	17.9	$(12.9)	N/M

N/M — Not Meaningful

In the second quarter 2009, other income (expense), net was $(3.7) million compared to $(4.5) million for the corresponding period in 2008. The decrease in expense when compared to the corresponding period in 2008 is not material.

For year-to-date 2009, other income (expense), net was $(16.5) million compared to $(3.6) million for the corresponding period in 2008. The increase in expense was primarily the result of the first quarter 2008 recognition of a $6.4 million fee received for participating in an asset auction and a $6.0 million gain on the sale of an undeveloped tract of land to the Orlando Utilities Commission.

Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$0.7	0.3	$(10.2)	(2.5)

In the second quarter 2009, income taxes were $225.7 million compared to $225.0 million for the corresponding period in 2008. The increase was the result of taxes on higher pre-tax earnings, largely offset by lower tax expenses associated with the early termination of one of the international leveraged lease investments and the extinguishment of the associated debt discussed previously under “Gain on Disposition of Lease Termination” and “Loss on Extinguishment of Debt.” See Note (G) to the Condensed Financial Statements under “Effective Tax Rate” herein for details regarding the impact of the early lease termination on the effective tax rate.

For year-to-date 2009, income taxes were $392.9 million compared to $403.1 million for the corresponding period in 2008. The decrease was primarily the result of lower tax expenses associated with the early termination of one of the international leveraged lease investments and the extinguishment of the associated debt discussed previously under “Gain on Disposition of Lease Termination” and “Loss on Extinguishment of Debt.” See Note (G) to the Condensed Financial Statements under “Effective Tax Rate” herein for details regarding the impact of the MC Asset Recovery litigation settlement and the early lease termination on the effective tax rate.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company’s future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. 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

21

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

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, and the successful remarketing of capacity as current contracts expire. Recent recessionary conditions have negatively impacted sales for the traditional operating companies and have negatively impacted wholesale capacity revenues at Southern Power. The current economic recession is expected to continue to have a negative impact on energy sales, particularly to industrial customers. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

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

Water Quality

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

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Southern Company in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives and is expected to now be considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on

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

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

FERC and State PSC Matters

Market-Based Rate Authority

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

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past several years, the traditional operating companies have experienced higher than expected fuel costs for coal, natural gas, and uranium. These higher fuel costs have resulted in under recovered fuel costs included in the balance sheets of approximately $882 million at June 30, 2009 as compared to $1.2 billion at December 31, 2008. Operating revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes to the billing factors will have no significant effect on Southern Company’s revenues or net income but will affect cash flow. The traditional operating companies continuously monitor the under recovered fuel cost balance in light of these higher fuel costs. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Alabama Power Retail Regulatory Matters,” “Georgia Power Retail Regulatory Matters,” and “Gulf Power Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

On March 10, 2009, the Georgia PSC granted Georgia Power’s request to delay its fuel case filing until September 4, 2009. The extension was requested as a result of difficulty in establishing a forward-looking fuel rate due to volatile coal and gas prices, uncertain sales forecasts, and a continuing decline in the State of Georgia’s economy. The ultimate outcome of this matter cannot now be determined.

23

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

Retail Rate Matters

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

The economic recession has significantly reduced Georgia Power’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. Despite stringent efforts to reduce expenses, current projections indicate Georgia Power’s retail ROE will be less than 10.25% in both 2009 and 2010. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations. Under Georgia Power’s proposal, the regulatory liability would be amortized ratably over the 18-month period from July 1, 2009 through December 31, 2010 as a reduction to operating expenses. Even if the Georgia PSC approves the accounting order request as filed, Georgia Power currently expects its retail ROE will remain below the 10.25% low end of its allowed retail ROE range in 2009 and 2010. The accounting order request is subject to the review and approval of the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Southern Company. Southern Company estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $225 million and $275 million. Southern Company and its subsidiaries have also filed an application under the ARRA for a grant of approximately $360 million to be used primarily for the advanced metering infrastructure program and other transmission and distribution automation and modernization projects. Southern Company continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Construction Projects

Integrated Coal Gasification Combined Cycle

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

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

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

24

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

Power expects the Kemper IGCC to be a qualifying project under the law and the gasification portion of the Kemper IGCC to be exempt from ad valorem taxation.

On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures. The Mississippi PSC’s determination of prudence for Mississippi Power’s pre-construction costs is scheduled to occur by May 2010. As of June 30, 2009, Mississippi Power had spent a total of $56.4 million associated with Mississippi Power’s generation resource planning, evaluation, and screening activities, including regulatory filing costs. Costs incurred for the six months ended June 30, 2009 totaled $14.1 million as compared to $13.0 million for the six months ended June 30, 2008. Of the total $56.4 million, $51.9 million was deferred in other regulatory assets, $3.7 million was related to land purchases capitalized, and $0.8 million was previously expensed.

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

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

The ultimate outcome of these matters cannot now be determined.

Nuclear

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

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

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

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

25

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

Nuclear Relicensing

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

Other Matters

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

New Accounting Standards

Variable Interest Entities

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

26

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition remained stable at June 30, 2009. Throughout the turmoil in the financial markets, Southern Company and its subsidiaries have maintained adequate access to capital without drawing on any committed bank credit arrangements used to support commercial paper programs and variable rate pollution control revenue bonds. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Southern Company and its subsidiaries have been and expect to continue to be subject to higher costs as existing facilities are replaced or renewed. Total committed credit fees for Southern Company and its subsidiaries currently average less than¹/4 of 1% per year. Southern Company’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Southern Company experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Southern Company’s investments in pension and nuclear decommissioning trust funds stabilized during the second quarter 2009. Southern Company expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. Southern Company does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.

For the first six months of 2009, net cash provided from operating activities totaled $620 million, a decrease of $791 million from the corresponding period in 2008. Significant changes in operating cash flow for the first six months of 2009 as compared to the corresponding period in 2008 include a reduction to net income as previously discussed and increased outflows of funds used for federal tax and property tax payments of $321 million and fuel purchases of $254 million. These uses of funds were partially offset by increased cash inflows as a result of higher fuel rates included in customer billings. Net cash used for investing activities totaled $1.8 billion for the first six months of 2009 as compared to $2.0 billion for the corresponding period in 2008. While the cash outflows in each of these periods were primarily related to property additions to utility plant, the decrease in the current period as compared to the corresponding period in 2008 was primarily due to approximately $340 million in cash received from the early termination of two leveraged lease investments. For the first six months of 2009, net cash provided from financing activities totaled $1.6 billion as compared to $606 million for the corresponding period in 2008 primarily due to higher levels of short-term borrowings, the issuance of new long-term debt, and common stock issuances.

Significant balance sheet changes for the first six months of 2009 include an increase of $365 million in cash and cash equivalents primarily due to cash received from the early termination of two leveraged lease investments; an increase of $1.6 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; and purchases of nuclear fuel. Other significant changes include an increase in long-term debt, excluding amounts due within one year, of $1.1 billion used primarily for construction expenditures and general corporate purposes.

The market price of Southern Company’s common stock at June 30, 2009 was $31.16 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $17.32 per share, representing a market-to-book ratio of 180%, compared to $37.00, $17.08, and 217%, respectively, at the end of 2008. The dividend for the second quarter 2009 was $0.4375 per share compared to $0.42 per share in the second quarter 2008.

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

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for its construction programs and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $1.1 billion will be required through June 30, 2010 to fund maturities and announced redemptions of long-term debt. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

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

Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities), to meet liquidity needs. At June 30, 2009, Southern Company and its subsidiaries had approximately $782 million of cash and cash equivalents and approximately $4.7 billion of unused credit arrangements with banks, of which $484 million expire in 2009, $965 million expire in 2010, $25 million expire in 2011, and $3.2 billion expire in 2012. Approximately $44 million of the credit facilities expiring in 2009 and 2010 allow for the execution of term loans for an additional two-year period, and $501 million contain provisions allowing one-year term loans. At June 30, 2009, approximately $1.3 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds and such credit facilities also serve as liquidity support for the commercial paper programs. Subsequent to June 30, 2009, financings at Georgia Power increased the total amount of variable rate pollution control bonds requiring liquidity support to $1.5 billion. See Note 6 to the financial statements of Southern Company under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. The traditional operating companies may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of each of the traditional operating companies. At June 30, 2009, the Southern Company system had outstanding commercial paper of $1.1 billion. Management believes that the

28

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

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

Off-Balance Sheet Financing Arrangements

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

Credit Rating Risk

Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At June 30, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $413 million. At June 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.0 billion. In addition, certain nuclear fuel agreements could require collateral of up to $251 million in the event of a rating change to below investment grade for Southern Company. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Southern Company’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Company is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation, the traditional operating companies continue to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, during 2009, Southern Power is exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, Southern Company’s subsidiaries may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. As such, the traditional operating companies have no material change in market risk exposure when compared with the December 31, 2008 reporting period.

29

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

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

	Second Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(423	)	$	(285	)
Contracts realized or settled		127			187
Current period changes(a)		(6	)		(204	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(302	)	$	(302	)

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

The changes in the fair value positions of the energy-related derivative contracts for the three months and six months ended June 30, 2009 were an increase of $121 million and a decrease of $17 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At June 30, 2009, Southern Company had a net hedge volume of 173 million mmBtu (includes location basis of 2 million mmBtu) with a weighted average contract cost approximately $1.78 per mmBtu above market prices, compared to 173 million mmBtu (includes location basis of 2 million mmBtu) at March 31, 2009 with a weighted average contract cost approximately $2.53 per mmBtu above market prices and compared to 149 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $1.97 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the traditional operating companies’ fuel cost recovery clauses.

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

	June 30, 2009			December 31, 2008
	(in millions)
Regulatory hedges	$	(305	)	$	(288	)
Cash flow hedges		—			(1	)
Not designated		3			4
Total fair value	$	(302	)	$	(285	)

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

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

30

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

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

	June 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(302	)		(234	)		(66	)		(2	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(302	)	$	(234	)	$	(66	)	$	(2	)

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

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

Financing Activities

In the first six months of 2009, Southern Company issued $350 million of Series 2009A 4.15% Senior Notes due May 15, 2014, and its subsidiaries issued $1.3 billion of senior notes and incurred obligations of $183 million related to the issuance of pollution control revenue bonds. Southern Company also issued 14 million shares of common stock for $399 million through the Southern Investment Plan and employee and director stock plans. In addition, during the three months ended June 30, 2009, Southern Company issued 5 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 $140 million, net of $1.4 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.

Subsequent to June 30, 2009, Georgia Power incurred obligations in connection with the issuance of $154.3 million of variable rate pollution control revenue bonds. The proceeds of the bonds were used to retire $154.3 million of fixed rate pollution control revenue bonds. Also, subsequent to June 30, 2009, Georgia Power issued a notice to redeem on August 21, 2009 its $55 million of Series D 5.50% Senior Insured Quarterly Notes due November 15, 2017.

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

Subsequent to June 30, 2009, Southern Company used a portion of the cash received from the early termination of two leveraged lease investments to extinguish $252.7 million of debt which included all debt related to leveraged lease investments and to pay make-whole redemption premiums of $17.2 million associated with such debt.

In 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.

31

PART I

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” herein for each registrant and Notes 1 and 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Financial Instruments” in Item 8 of the Form 10-K. Also, see Note (E) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.

     (a) Evaluation of disclosure controls and procedures.

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

     (b) Changes in internal controls.

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 second quarter 2009 that have materially affected or are reasonably likely to materially affect Southern Company’s internal control over financial reporting.

Item 4T. Controls and Procedures.

     (a) Evaluation of disclosure controls and procedures.

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

     (b) Changes in internal controls.

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

32

ALABAMA POWER COMPANY

33

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	1,119,606		$	1,147,786		$	2,177,743		$	2,182,040
Wholesale revenues, non-affiliates		153,912			169,971			312,607			340,011
Wholesale revenues, affiliates		52,493			96,421			136,845			180,113
Other revenues		40,505			55,635			79,087			104,328
Total operating revenues		1,366,516			1,469,813			2,706,282			2,806,492
Operating Expenses:
Fuel		447,486			523,348			930,719			976,497
Purchased power, non-affiliates		26,123			38,450			41,667			49,669
Purchased power, affiliates		56,570			75,789			98,130			164,496
Other operations and maintenance		278,298			306,543			555,157			616,093
Depreciation and amortization		126,487			130,630			269,903			255,267
Taxes other than income taxes		82,039			75,614			162,320			151,385
Total operating expenses		1,017,003			1,150,374			2,057,896			2,213,407
Operating Income		349,513			319,439			648,386			593,085
Other Income and (Expense):
Allowance for equity funds used during construction		19,153			9,235			35,878			20,539
Interest income		4,148			4,258			8,270			8,900
Interest expense, net of amounts capitalized		(76,768	)		(69,646	)		(148,975	)		(138,622	)
Other income (expense), net		(4,491	)		(6,707	)		(10,863	)		(13,929	)
Total other income and (expense)		(57,958	)		(62,860	)		(115,690	)		(123,112	)
Earnings Before Income Taxes		291,555			256,579			532,696			469,973
Income taxes		105,357			93,798			190,366			167,226
Net Income		186,198			162,781			342,330			302,747
Dividends on Preferred and Preference Stock		9,866			9,866			19,732			19,732
Net Income After Dividends on Preferred and Preference Stock	$	176,332		$	152,915		$	322,598		$	283,015

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2009			2008		2009			2008
	(in thousands)					(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	176,332		$	152,915	$	322,598		$	283,015
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(700), $1,171, $(1,586), and $(1,039), respectively		(1,152	)		1,927		(2,609	)		(1,710	)
Reclassification adjustment for amounts included in net income, net of tax of $1,178, $443, $2,239, and $628, respectively		1,938			728		3,683			1,033
Total other comprehensive income (loss)		786			2,655		1,074			(677	)
Comprehensive Income	$	177,118		$	155,570	$	323,672		$	282,338

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

34

ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months
	Ended June 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	342,330		$	302,747
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		311,868			297,792
Deferred income taxes and investment tax credits, net		5,182			20,648
Allowance for equity funds used during construction		(35,878	)		(20,539	)
Pension, postretirement, and other employee benefits		(16,568	)		(12,958	)
Stock option expense		3,168			2,520
Tax benefit of stock options		42			460
Other, net		638			14,499
Changes in certain current assets and liabilities —
-Receivables		206,523			34,056
-Fossil fuel stock		(59,418	)		(21,879	)
-Materials and supplies		(9,094	)		(6,887	)
-Other current assets		(62,618	)		(42,632	)
-Accounts payable		(133,138	)		(68,407	)
-Accrued taxes		25,199			64,490
-Accrued compensation		(56,429	)		(47,094	)
-Other current liabilities		18,302			26,481
Net cash provided from operating activities		540,109			543,297
Investing Activities:
Property additions		(641,598	)		(714,878	)
Investment in restricted cash from pollution control revenue bonds		(290	)		(161	)
Distribution of restricted cash from pollution control revenue bonds		32,758			19,687
Nuclear decommissioning trust fund purchases		(124,057	)		(180,522	)
Nuclear decommissioning trust fund sales		124,057			180,522
Cost of removal, net of salvage		(13,004	)		(18,157	)
Other investing activities		(1,583	)		(11,489	)
Net cash used for investing activities		(623,717	)		(724,998	)
Financing Activities:
Increase (decrease) in notes payable, net		(24,995	)		24,980
Proceeds —
Common stock issued to parent		—			150,000
Capital contributions from parent company		11,510			12,178
Gross excess tax benefit of stock options		81			858
Pollution control revenue bonds		53,000			—
Senior notes issuances		500,000			600,000
Redemptions —
Preferred stock		—			(125,000	)
Senior notes		—			(250,000	)
Payment of preferred and preference stock dividends		(19,740	)		(21,142	)
Payment of common stock dividends		(261,400	)		(245,650	)
Other financing activities		(6,114	)		(5,523	)
Net cash provided from financing activities		252,342			140,701
Net Change in Cash and Cash Equivalents		168,734			(41,000	)
Cash and Cash Equivalents at Beginning of Period		28,181			73,616
Cash and Cash Equivalents at End of Period	$	196,915		$	32,616
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $15,005 and $9,322 capitalized for 2009 and 2008, respectively)	$	122,624		$	126,502
Income taxes (net of refunds)	$	203,248		$	124,050

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

35

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At June 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	196,915		$	28,181
Restricted cash and cash equivalents		47,611			80,079
Receivables —
Customer accounts receivable		375,523			350,410
Unbilled revenues		137,895			98,921
Under recovered regulatory clause revenues		125,583			153,899
Other accounts and notes receivable		34,923			44,645
Affiliated companies		21,122			70,612
Accumulated provision for uncollectible accounts		(9,125	)		(8,882	)
Fossil fuel stock, at average cost		375,978			322,089
Materials and supplies, at average cost		313,297			305,880
Vacation pay		52,825			52,577
Prepaid expenses		146,665			88,219
Other regulatory assets, current		78,371			74,825
Other current assets		17,451			12,915
Total current assets		1,915,034			1,674,370
Property, Plant, and Equipment:
In service		17,897,911			17,635,129
Less accumulated provision for depreciation		6,429,812			6,259,720
Plant in service, net of depreciation		11,468,099			11,375,409
Nuclear fuel, at amortized cost		244,057			231,862
Construction work in progress		1,419,838			1,092,516
Total property, plant, and equipment		13,131,994			12,699,787
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		57,071			50,912
Nuclear decommissioning trusts, at fair value		420,053			403,966
Miscellaneous property and investments		65,735			62,782
Total other property and investments		542,859			517,660
Deferred Charges and Other Assets:
Deferred charges related to income taxes		380,116			362,596
Prepaid pension costs		186,893			166,334
Deferred under recovered regulatory clause revenues		—			180,874
Other regulatory assets, deferred		710,265			732,367
Other deferred charges and assets		198,258			202,018
Total deferred charges and other assets		1,475,532			1,644,189
Total Assets	$	17,065,419		$	16,536,006

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

36

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At June 30,			At December 31,
Liabilities and Stockholder's Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	250,000		$	250,079
Notes payable		—			24,995
Accounts payable —
Affiliated		169,684			178,708
Other		252,902			358,176
Customer deposits		84,880			77,205
Accrued taxes —
Accrued income taxes		35,767			18,299
Other accrued taxes		73,653			30,372
Accrued interest		69,044			56,375
Accrued vacation pay		44,217			44,217
Accrued compensation		43,219			91,856
Liabilities from risk management activities		87,888			83,873
Other current liabilities		45,075			53,777
Total current liabilities		1,156,329			1,267,932
Long-term Debt		6,156,915			5,604,791
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,248,530			2,243,117
Deferred credits related to income taxes		89,884			90,083
Accumulated deferred investment tax credits		168,668			172,638
Employee benefit obligations		396,440			396,923
Asset retirement obligations		476,038			461,284
Other cost of removal obligations		657,939			634,792
Other regulatory liabilities, deferred		57,749			79,151
Other deferred credits and liabilities		40,428			45,857
Total deferred credits and other liabilities		4,135,676			4,123,845
Total Liabilities		11,448,920			10,996,568
Redeemable Preferred Stock		341,716			341,716
Preference Stock		343,412			343,412
Common Stockholder’s Equity:
Common stock, par value $40 per share —
Authorized - 40,000,000 shares
Outstanding - 25,475,000 shares		1,019,000			1,019,000
Paid-in capital		2,106,259			2,091,462
Retained earnings		1,814,987			1,753,797
Accumulated other comprehensive loss		(8,875	)		(9,949	)
Total common stockholder’s equity		4,931,371			4,854,310
Total Liabilities and Stockholder’s Equity	$	17,065,419		$	16,536,006

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

37

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

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

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$23.4	15.3	$39.6	14.0

Alabama Power’s financial performance remained stable in the second quarter 2009 despite the continued challenges of a recessionary economy. Alabama Power’s net income after dividends on preferred and preference stock for the second quarter 2009 was $176.3 million compared to $152.9 million for the corresponding period in 2008. The increase was primarily due to the corrective rate package providing for adjustments associated with customer charges effective in January 2009 and a decrease in other operations and maintenance expenses primarily due to a reduction in transmission and distribution, steam power, and administrative and general expenses. The increase was partially offset by a decrease in retail revenues attributable to a decline in KWH sales and an increase in interest expense, net of amounts capitalized.

Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2009 was $322.6 million compared to $283.0 million for the corresponding period in 2008. The increase was primarily due to the corrective rate package providing for adjustments associated with customer charges effective in January 2009 and a decrease in other operations and maintenance expenses primarily related to steam power. The increase was partially offset by a decrease in retail revenues attributable to a decline in KWH sales, increases in income taxes, and an increase in depreciation related to property, plant, and equipment associated with environmental mandates and transmission and distribution projects.

38

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

Retail Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(28.2)	(2.5)	$(4.3)	(0.2)

In the second quarter 2009, retail revenues were $1.12 billion compared to $1.15 billion for the corresponding period in 2008. For year-to-date 2009, retail revenues were $2.18 billion compared to $2.18 billion for the corresponding period in 2008.

Details of the change to retail revenues are as follows:

	Second Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	1,147.8					$	2,182.0
Estimated change in —
Rates and pricing		40.8			3.5			90.4			4.1
Sales growth (decline)		(40.5	)		(3.5	)		(72.8	)		(3.3	)
Weather		3.4			0.3			2.7			0.1
Fuel and other cost recovery		(31.9	)		(2.8	)		(24.6	)		(1.1	)
Retail – current year	$	1,119.6			(2.5	)%	$	2,177.7			(0.2	)%

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

Revenues attributable to changes in sales declined in the second quarter 2009 when compared to the corresponding period in 2008 due to a recessionary economy. Additionally, based on a change in the historical trend in the timing of customers’ meter readings, Alabama Power changed the estimate related to the meter read date assumption used in the unbilled revenue calculation. This change in estimate resulted in a one-time increase in revenue of $13.4 million and a 1.8% increase in retail KWH energy sales for the quarter. Industrial KWH energy sales decreased 24.3% due to a decline in demand across all industrial segments. Weather-adjusted residential KWH energy sales decreased 1.9% driven by a decline in customer demand related to customer energy efficiency efforts in addition to a recessionary economy. Weather-adjusted commercial KWH energy sales decreased 1.0% due to a decline in customer demand.

For year-to-date 2009, revenues attributable to changes in sales declined due to a recessionary economy when compared to the corresponding period in 2008. Industrial KWH energy sales decreased 23.0% due to a decline in demand across all industrial segments. Weather-adjusted residential KWH energy sales decreased 2.3% driven by a decline in customer demand related to customer energy efficiency efforts in addition to a recessionary economy. Weather-adjusted commercial KWH energy sales decreased 1.7% due to a decline in customer demand.

39

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

Revenues resulting from changes in weather were relatively insignificant in the second quarter and year-to-date 2009 when compared to the corresponding periods in 2008.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2009 when compared to the corresponding periods in 2008 primarily due to decreases in fuel costs. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not impact net income.

Wholesale Revenues – Non-Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(16.1)	(9.4)	$(27.4)	(8.1)

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

In the second quarter 2009, wholesale revenues from non-affiliates were $153.9 million compared to $170.0 million for the corresponding period in 2008. This decrease was due to a 7.0% decrease in KWH sales and a 2.6% reduction in price.

For year-to-date 2009, wholesale revenues from non-affiliates were $312.6 million compared to $340.0 million for the corresponding period in 2008. This decrease was due to a 5.1% reduction in price and a 3.1% decrease in KWH sales.

Wholesale Revenues – Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(43.9)	(45.6)	$(43.3)	(24.0)

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 second quarter 2009, wholesale revenues from affiliates were $52.5 million compared to $96.4 million for the corresponding period in 2008. This decrease was primarily due to a 43.2% decrease in fuel prices.

For year-to-date 2009, wholesale revenues from affiliates were $136.8 million compared to $180.1 million for the corresponding period in 2008. This decrease was due to a 34.3% decrease in fuel prices, partially offset by a 15.7% increase in KWH sales.

40

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

Other Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(15.1)	(27.2)	$(25.2)	(24.2)

In the second quarter 2009, other revenues were $40.5 million compared to $55.6 million for the corresponding period in 2008. This decrease was primarily due to a $17.2 million decrease in revenues from gas-fueled co-generation steam facilities resulting from lower gas prices and a decline in sales volume.

For year-to-date 2009, other revenues were $79.1 million compared to $104.3 million for the corresponding period in 2008. This decrease was primarily due to a $26.6 million decrease in revenues from gas-fueled co-generation steam facilities resulting from lower gas prices and a decline in sales volume.

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

	Second Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Second Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(75.9	)		(14.5	)	$	(45.8	)		(4.7	)
Purchased power – non-affiliates		(12.3	)		(32.1	)		(8.0	)		(16.1	)
Purchased power – affiliates		(19.2	)		(25.4	)		(66.4	)		(40.3	)
Total fuel and purchased power expenses	$	(107.4	)				$	(120.2	)

In the second quarter 2009, total fuel and purchased power expenses were $530.2 million compared to $637.6 million for the corresponding period in 2008. This decrease was primarily due to a $71.8 million decrease in total KWHs generated and purchased and a $35.6 million decrease in the cost of energy primarily resulting from a decrease in the average cost of natural gas.

For year-to-date 2009, total fuel and purchased power expenses were $1.07 billion compared to $1.19 billion for the corresponding period in 2008. This decrease was primarily due to a $151.6 million decrease in total KWHs generated and purchased, partially offset by a $31.4 million increase in the cost of energy primarily resulting from an increase in the average cost of coal.

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.

41

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:

	Second Quarter		Second Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2009		2008		Change			2009		2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		2.78		2.72		2.2			2.85		2.66		7.1
Purchased power		6.01		8.61		(30.2	)		6.06		6.97		(13.1	)

In the second quarter 2009, fuel expense was $447.4 million compared to $523.3 million for the corresponding period in 2008. The total decline in fuel expense was driven by a decrease in generation and lower natural gas prices. The decrease was primarily related to a 21.0% decrease in KWHs generated by coal and a 49.8% decrease in the average cost of KWHs generated by natural gas, resulting in a change in the fuel mix.

For year-to-date 2009, fuel expense was $930.6 million compared to $976.4 million for the corresponding period in 2008. Total fuel expense decreased due to a 38.3% decrease in the average cost of KWHs generated by natural gas and an 8.9% decrease in total KWHs generated. These decreases were partially offset by a 22.9% increase in the average cost of KWHs generated by coal.

Non-Affiliates

In the second quarter 2009, purchased power expense from non-affiliates was $26.2 million compared to $38.5 million for the corresponding period in 2008. This decrease was primarily related to a 21.0% decrease in price.

For year-to-date 2009, purchased power expense from non-affiliates was $41.7 million compared to $49.7 million for the corresponding period in 2008. This decrease was primarily related to a 22.2% decrease in price, partially offset by a 7.8% volume increase in the KWHs purchased due to the availability of lower-priced market energy alternatives.

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

Affiliates

In the second quarter 2009, purchased power expense from affiliates was $56.6 million compared to $75.8 million for the corresponding period in 2008. This decrease was primarily related to a 26.9% decrease in price.

For year-to-date 2009, purchased power expense from affiliates was $98.1 million compared to $164.5 million for the corresponding period in 2008. This decrease was primarily related to a 33.2% decrease in the amount of energy purchased and a 10.8% decrease in price.

42

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

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

Other Operations and Maintenance Expenses

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(28.2)	(9.2)	$(60.9)	(9.9)

In the second quarter 2009, other operations and maintenance expenses were $278.3 million compared to $306.5 million for the corresponding period in 2008. This decrease was primarily a result of a $10.9 million decrease in transmission and distribution expenses related to a reduction in overhead line clearing costs, an $8.6 million decrease in steam power expense associated with fewer scheduled outages, and a $7.2 million decrease in administrative and general expenses primarily related to a reduction in employee medical and other expenses.

For year-to-date 2009, other operations and maintenance expenses were $555.2 million compared to $616.1 million for the corresponding period in 2008. This decrease was primarily a result of a $44.5 million decrease in steam power expense associated with fewer scheduled outages and a $15.0 million decrease in transmission and distribution expenses related to a reduction in overhead line clearing.

Depreciation and Amortization

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(4.1)	(3.2)	$14.6	5.7

In the second quarter 2009, depreciation and amortization was $126.5 million compared to $130.6 million for the corresponding period in 2008. This change was the result of an increase in property, plant, and equipment primarily related to environmental mandates and transmission and distribution projects. This was offset by an adjustment to depreciation of $8.4 million, resulting from the offer of settlement to the FERC discussed below.

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

For year-to-date 2009, depreciation and amortization was $269.9 million compared to $255.3 million for the corresponding period in 2008. This change was the result of an increase in property, plant, and equipment primarily related to environmental mandates and transmission and distribution projects.

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

43

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

Taxes Other than Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$6.4	8.5	$10.9	7.2

In the second quarter 2009, taxes other than income taxes were $82.0 million compared to $75.6 million in the corresponding period in 2008. For year-to-date 2009, taxes other than income taxes were $162.3 million compared to $151.4 million for the corresponding period in 2008. These increases were primarily due to increases in state and municipal public utility license tax bases.

Allowance for Equity Funds Used During Construction

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$9.9	107.4	$15.3	74.7

In the second quarter 2009, allowance for equity funds used during construction (AFUDC) was $19.1 million compared to $9.2 million for the corresponding period in 2008. For year-to-date 2009, AFUDC was $35.8 million compared to $20.5 million for the corresponding period in 2008. These increases were primarily due to increases in the amount of construction work in progress at generating facilities related to environmental mandates.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$7.1	10.2	$10.4	7.5

In the second quarter 2009, interest expense, net of amounts capitalized was $76.7 million compared to $69.6 million for the corresponding period in 2008. For year-to-date 2009, interest expense, net of amounts capitalized was $149.0 million compared to $138.6 million for the corresponding period in 2008. These increases were primarily due to the issuance of additional long-term debt. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” herein for additional information.

Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$11.6	12.3	$23.1	13.8

In the second quarter 2009, income taxes were $105.4 million compared to $93.8 million for the corresponding period in 2008. For year-to-date 2009, income taxes were $190.3 million compared to $167.2 million for the corresponding period in 2008. These increases were primarily due to higher pre-tax income and a decrease in the tax benefit from the production activities deduction, partially offset by the increase in non-taxable AFUDC.

44

ALABAMA 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 Alabama Power’s future earnings potential. The level of Alabama Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power’s primary business of selling electricity. These factors include Alabama Power’s ability to maintain a constructive regulatory environment that continues to allow for the recovery of prudently incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining energy sales, which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power’s service area. Recent recessionary conditions have negatively impacted sales and are expected to continue to have a negative impact, particularly to industrial customers. The timing and extent of the economic recovery will impact future earnings.

For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

Environmental Matters

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

Water Quality

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

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Alabama Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative

45

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

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

FERC and Alabama PSC Matters

Market-Based Rate Authority

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

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Retail Fuel Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s under recovered fuel costs as of June 30, 2009 totaled $102.1 million as compared to $305.8 million at December 31, 2008. These under recovered fuel costs at June 30, 2009 are included in under recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of the recovery of the under recovered fuel costs.

46

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

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

Natural Disaster Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Cost Recovery” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery. At June 30, 2009, Alabama Power had accumulated a balance of $30.6 million in the target reserve for future storms, which is included in the Condensed Balance Sheets herein under “Other Regulatory Liabilities.”

Steam Service

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

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Alabama Power. Alabama Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $75 million and $90 million. Southern Company and its subsidiaries have also filed an application under the ARRA for a grant, of which approximately $120 million relates to Alabama Power, to be used primarily for the advanced metering infrastructure program and other transmission and distribution automation and modernization projects. Alabama Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Other Matters

Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power’s business activities are subject to extensive governmental regulation related to public health and the environment. 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

47

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

States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials 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.

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, and Unbilled Revenues.

New Accounting Standards

Variable Interest Entities

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Alabama Power’s financial condition remained stable at June 30, 2009. Throughout the turmoil in the financial markets, Alabama Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper programs and variable rate pollution control revenue bonds. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Alabama Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees currently average less than¹/4 of 1% per year for Alabama Power. Alabama Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Alabama Power experienced no material

48

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

counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Alabama Power’s investments in pension and nuclear decommissioning trust funds stabilized during the second quarter 2009. Alabama Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012. The projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. Alabama Power does not expect any changes to the funding obligations to the nuclear decommissioning trust at this time.

Net cash provided from operating activities totaled $540.1 million for the first six months of 2009, compared to $543.3 million for the corresponding period in 2008. Changes in operating cash flow were not material. Net cash used for investing activities totaled $623.7 million compared to $725.0 million for the corresponding period in 2008. The $101.3 million decrease was primarily due to a decline in gross property additions related to nuclear refueling outages. Net cash provided from financing activities totaled $252.3 million for the first six months of 2009, compared to $140.7 million for the corresponding period in 2008. The $111.6 million increase was primarily due to no redemptions or maturities offset by fewer issuances of securities in the first six months of 2009 as compared to the first six months of 2008. Fluctuations in cash flow from financing activities vary from year-to-year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2009 include an increase of $168.7 million in cash and cash equivalents and an increase of $262.8 million in gross plant primarily due to increases in transmission and distribution projects. Long-term debt increased $552.1 million.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $250 million will be required through June 30, 2010 for maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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

49

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 June 30, 2009 cash and cash equivalents of approximately $196.9 million, unused committed lines of credit of approximately $1.3 billion, and commercial paper programs. The credit facilities provide liquidity support to Alabama Power’s commercial paper borrowings and $582 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Of the unused credit facilities, $325 million will expire in 2009, $145 million will expire in 2010, $25 million will expire in 2011, and $765 million will expire in 2012. Of the facilities that expire in 2009 and 2010, $361 million allow for one-year term loans. Alabama Power expects to renew its credit facilities, as needed, prior to expiration. See Note 6 to the financial statements of Alabama Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and other Southern Company subsidiaries. At June 30, 2009, Alabama Power had no commercial paper outstanding and no outstanding borrowings under its committed lines of credit. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are primarily for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At June 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $16 million. At June 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $175 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. In addition, certain nuclear fuel agreements could require collateral of up to $64 million in the event of a rating change to below investment grade for Southern Company. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

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

Due to cost-based rate regulation, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

50

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

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

	Second Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(130.2	)	$	(91.9	)
Contracts realized or settled		40.6			63.9
Current period changes(a)		(1.9	)		(63.5	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(91.5	)	$	(91.5	)

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

The increases in the fair value positions of the energy-related derivative contracts for the three months and six months ended June 30, 2009 were $39 million and $0.4 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At June 30, 2009, Alabama Power had a net hedge volume of 49 million mmBtu with a weighted average contract cost approximately $1.89 per mmBtu above market prices, compared to 49 million mmBtu at March 31, 2009 with a weighted average contract cost approximately $2.70 per mmBtu above market prices and compared to 45 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $2.12 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the fuel cost recovery clause.

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

	June 30,			December 31,
	2009			2008
	(in millions)
Regulatory hedges		$(91.5	)		$(91.9	)
Cash flow hedges		—			—
Not designated		—			—
Total fair value		$(91.5	)		$(91.9	)

Energy-related derivative contracts which are designated as regulatory hedges relate to Alabama Power’s fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clauses. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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

51

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

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

	June 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(91.5	)		(77.0	)		(14.6	)		0.1
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(91.5	)	$	(77.0	)	$	(14.6	)	$	0.1

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

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

Financing Activities

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

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

Subsequent to June 30, 2009, Alabama Power issued 3,375,000 shares of common stock to Southern Company at $40 a share ($135 million aggregate purchase price). The proceeds were used for general corporate purposes.

In 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.

52

GEORGIA POWER COMPANY

53

GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	1,682,225		$	1,830,753		$	3,274,620		$	3,405,760
Wholesale revenues, non-affiliates		96,570			142,276			192,556			294,968
Wholesale revenues, affiliates		29,623			72,164			44,833			146,074
Other revenues		65,896			65,969			128,146			129,207
Total operating revenues		1,874,314			2,111,162			3,640,155			3,976,009
Operating Expenses:
Fuel		652,889			683,299			1,253,379			1,321,222
Purchased power, non-affiliates		70,817			107,723			132,770			165,754
Purchased power, affiliates		172,418			247,842			369,641			500,777
Other operations and maintenance		353,562			391,781			744,055			760,596
Depreciation and amortization		175,080			159,204			342,191			309,812
Taxes other than income taxes		81,008			79,485			157,256			150,771
Total operating expenses		1,505,774			1,669,334			2,999,292			3,208,932
Operating Income		368,540			441,828			640,863			767,077
Other Income and (Expense):
Allowance for equity funds used during construction		22,313			23,981			43,067			51,738
Interest income		(197	)		1,050			1,033			1,837
Interest expense, net of amounts capitalized		(99,425	)		(83,727	)		(197,815	)		(170,065	)
Other income (expense), net		2,531			1,371			(4,189	)		(1,922	)
Total other income and (expense)		(74,778	)		(57,325	)		(157,904	)		(118,412	)
Earnings Before Income Taxes		293,762			384,503			482,959			648,665
Income taxes		99,682			132,279			162,310			216,080
Net Income		194,080			252,224			320,649			432,585
Dividends on Preferred and Preference Stock		4,346			4,346			8,691			8,691
Net Income After Dividends on Preferred and Preference Stock	$	189,734		$	247,878		$	311,958		$	423,894

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2009			2008		2009		2008
	(in thousands)					(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	189,734		$	247,878	$	311,958	$	423,894
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(905), $6,027, $275, and $(16), respectively		(1,435	)		9,556		435		(24	)
Reclassification adjustment for amounts included in net income, net of tax of $2,427, $489, $4,170, and $695, respectively		3,848			774		6,611		1,101
Total other comprehensive income (loss)		2,413			10,330		7,046		1,077
Comprehensive Income	$	192,147		$	258,208	$	319,004	$	424,971

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

54

GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months
	Ended June 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	320,649		$	432,585
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		402,086			367,910
Deferred income taxes and investment tax credits		54,721			29,175
Deferred revenues		(20,929	)		60,875
Deferred expenses		20,523			27,059
Allowance for equity funds used during construction		(43,067	)		(51,738	)
Pension, postretirement, and other employee benefits		(11,543	)		6,304
Hedge settlements		(16,167	)		(20,486	)
Other, net		42,135			(25,801	)
Changes in certain current assets and liabilities —
-Receivables		(126,080	)		(193,372	)
-Fossil fuel stock		(222,837	)		(40,214	)
-Prepaid income taxes		(20,298	)		4,302
-Other current assets		(14,914	)		(14,874	)
-Accounts payable		120,228			102,384
-Accrued taxes		(74,291	)		(12,300	)
-Accrued compensation		(103,764	)		(49,119	)
-Other current liabilities		31,345			54,941
Net cash provided from operating activities		337,797			677,631
Investing Activities:
Property additions		(1,208,114	)		(992,317	)
Distribution of restricted cash from pollution control revenue bonds		15,566			13,221
Nuclear decommissioning trust fund purchases		(699,359	)		(225,477	)
Nuclear decommissioning trust fund sales		664,633			218,597
Cost of removal, net of salvage		(33,041	)		(15,957	)
Change in construction payables, net of joint owner portion		103,558			7,200
Other investing activities		43,910			(16,754	)
Net cash used for investing activities		(1,112,847	)		(1,011,487	)
Financing Activities:
Increase (decrease) in notes payable, net		114,439			(347,612	)
Proceeds —
Capital contributions from parent company		602,968			251,262
Pollution control revenue bonds issuances		—			94,935
Senior notes issuances		500,000			500,000
Other long-term debt issuances		750			300,000
Redemptions —
Pollution control revenue bonds		—			(41,935	)
Senior notes		(151,928	)		(45,812	)
Payment of preferred and preference stock dividends		(8,758	)		(8,309	)
Payment of common stock dividends		(369,450	)		(360,600	)
Other financing activities		(7,963	)		(8,430	)
Net cash provided from financing activities		680,058			333,499
Net Change in Cash and Cash Equivalents		(94,992	)		(357	)
Cash and Cash Equivalents at Beginning of Period		132,739			15,392
Cash and Cash Equivalents at End of Period	$	37,747		$	15,035
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $18,986 and $21,619 capitalized for 2009 and 2008, respectively)	$	167,890		$	154,225
Income taxes (net of refunds)	$	79,141		$	130,091

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

55

GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At June 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	37,747		$	132,739
Restricted cash and cash equivalents		11,081			22,381
Receivables —
Customer accounts receivable		575,753			554,219
Unbilled revenues		212,550			147,978
Under recovered regulatory clause revenues		346,608			338,780
Joint owner accounts receivable		146,544			43,858
Other accounts and notes receivable		44,913			54,041
Affiliated companies		15,784			13,091
Accumulated provision for uncollectible accounts		(11,679	)		(10,732	)
Fossil fuel stock, at average cost		707,594			484,757
Materials and supplies, at average cost		362,530			356,537
Vacation pay		65,644			71,217
Prepaid income taxes		86,285			65,987
Other regulatory assets, current		151,044			118,961
Other current assets		52,240			63,464
Total current assets		2,804,638			2,457,278
Property, Plant, and Equipment:
In service		24,779,503			23,975,262
Less accumulated provision for depreciation		9,301,959			9,101,474
Plant in service, net of depreciation		15,477,544			14,873,788
Nuclear fuel, at amortized cost		302,160			278,412
Construction work in progress		1,759,917			1,434,989
Total property, plant, and equipment		17,539,621			16,587,189
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		63,450			57,163
Nuclear decommissioning trusts, at fair value		520,445			460,430
Miscellaneous property and investments		37,058			40,945
Total other property and investments		620,953			558,538
Deferred Charges and Other Assets:
Deferred charges related to income taxes		586,370			572,528
Deferred under recovered regulatory clause revenues		364,728			425,609
Other regulatory assets, deferred		1,361,027			1,449,352
Other deferred charges and assets		204,552			265,174
Total deferred charges and other assets		2,516,677			2,712,663
Total Assets	$	23,481,889		$	22,315,668

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

56

GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)

	At June 30,			At December 31,
Liabilities and Stockholder's Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	435,372		$	280,443
Notes payable		471,533			357,095
Accounts payable —
Affiliated		240,279			260,545
Other		678,495			422,485
Customer deposits		193,851			186,919
Accrued taxes —
Accrued income taxes		78,877			70,916
Unrecognized tax benefits		148,686			128,712
Other accrued taxes		155,370			278,172
Accrued interest		91,215			79,432
Accrued vacation pay		49,248			57,643
Accrued compensation		38,556			135,191
Liabilities from risk management activities		109,522			113,432
Other current liabilities		207,789			136,176
Total current liabilities		2,898,793			2,507,161
Long-term Debt		7,196,675			7,006,275
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,161,017			3,064,580
Deferred credits related to income taxes		134,470			140,933
Accumulated deferred investment tax credits		249,357			256,218
Employee benefit obligations		870,699			882,965
Asset retirement obligations		706,933			688,019
Other cost of removal obligations		378,462			396,947
Other regulatory liabilities, deferred		75,293			115,865
Other deferred credits and liabilities		108,498			111,505
Total deferred credits and other liabilities		5,684,729			5,657,032
Total Liabilities		15,780,197			15,170,468
Preferred Stock		44,991			44,991
Preference Stock		220,966			220,966
Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - 9,261,500 shares		398,473			398,473
Paid-in capital		4,262,668			3,655,731
Retained earnings		2,800,298			2,857,789
Accumulated other comprehensive loss		(25,704	)		(32,750	)
Total common stockholder’s equity		7,435,735			6,879,243
Total Liabilities and Stockholder’s Equity	$	23,481,889		$	22,315,668

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

57

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

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

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales in the midst of the current economic downturn, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, capital expenditures, and fuel prices. Appropriately balancing the need to recover these increasing costs with customer prices will continue to challenge Georgia Power for the foreseeable future. Georgia Power is required to file a general rate case by July 1, 2010, which will determine whether the 2007 Retail Rate Plan should be continued, modified, or discontinued. On June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations in lieu of filing a request for a base rate increase. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Retail Rate Matters” herein for additional information.

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

RESULTS OF OPERATIONS

Net Income

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(58.2)	(23.5)	$(111.9)	(26.4)

Georgia Power’s second quarter 2009 net income after dividends on preferred and preference stock was $189.7 million compared to $247.9 million for the corresponding period in 2008. Georgia Power’s year-to-date 2009 net income after dividends on preferred and preference stock was $312.0 million compared to $423.9 million for the corresponding period in 2008. These decreases were primarily due to lower industrial base revenues resulting from the recessionary economy. Also contributing to the year-to-date decrease was a charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees resigned from their positions effective March 31, 2009.

Retail Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(148.5)	(8.1)	$(131.1)	(3.9)

In the second quarter 2009, retail revenues were $1.68 billion compared to $1.83 billion for the corresponding period in 2008. For year-to-date 2009, retail revenues were $3.27 billion compared to $3.41 billion for the corresponding period in 2008.

58

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:

	Second Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	1,830.8					$	3,405.8
Estimated change in —
Rates and pricing		(42.1	)		(2.3	)		(22.5	)		(0.7	)
Sales growth (decline)		(42.4	)		(2.3	)		(60.4	)		(1.8	)
Weather		5.1			0.3			4.5			0.1
Fuel cost recovery		(69.2	)		(3.8	)		(52.8	)		(1.5	)
Retail – current year	$	1,682.2			(8.1	)%	$	3,274.6			(3.9	)%

Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2009 when compared to the corresponding periods in 2008 due to decreased revenues from market-response rates to large commercial and industrial customers of $78.6 million and $105.2 million for the second quarter and year-to-date 2009, respectively, partially offset by increased recognition of environmental compliance cost recovery revenues of $36.7 million and $83.0 million for the second quarter and year-to-date 2009, respectively, in accordance with the 2007 Retail Rate Plan.

Revenues attributable to changes in sales declined in the second quarter and year-to-date 2009 when compared to the corresponding periods in 2008. These decreases were primarily due to the recessionary economy, partially offset by a 0.3% increase in retail customers. Weather-adjusted residential KWH sales decreased 1.1%, weather-adjusted commercial KWH sales decreased 0.8%, and weather-adjusted industrial KWH sales decreased 14.6% for the second quarter 2009 when compared to the corresponding period in 2008. Weather-adjusted residential KWH sales increased 0.1%, weather-adjusted commercial KWH sales decreased 0.7%, and weather-adjusted industrial KWH sales decreased 14.3% year-to-date 2009 when compared to the corresponding period in 2008. Weather-adjusted industrial KWH sales decreased due to a broad decline in demand across all industrial segments for the second quarter and year-to-date 2009.

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

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased by $69.2 million in the second quarter 2009 and by $52.8 million year-to-date 2009 when compared to the corresponding periods in 2008 due to decreased KWH sales and fuel and purchased power expenses. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not impact net income.

Wholesale Revenues – Non-Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(45.7)	(32.1)	$(102.4)	(34.7)

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

59

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

In the second quarter 2009, wholesale revenues from non-affiliates were $96.6 million compared to $142.3 million for the corresponding period in 2008. For year-to-date 2009, wholesale revenues from non-affiliates were $192.6 million compared to $295.0 million for the corresponding period in 2008. These decreases were due to a 44.7% decrease and a 49.2% decease in KWH sales for the second quarter and year-to-date 2009, respectively, due to lower demand primarily caused by the recessionary economy.

Wholesale Revenues – Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(42.6)	(59.0)	$(101.3)	(69.3)

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 second quarter 2009, wholesale revenues from affiliates were $29.6 million compared to $72.2 million for the corresponding period in 2008. For year-to-date 2009, wholesale revenues from affiliates were $44.8 million compared to $146.1 million for the corresponding period in 2008. These decreases were due to a 19.6% decrease and a 58.7% decrease in KWH sales in the second quarter and year-to-date 2009, respectively, due to lower demand primarily caused by the recessionary economy.

Fuel and Purchased Power Expenses

	Second Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Second Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(30.4	)		(4.5	)	$	(67.8	)		(5.1	)
Purchased power – non-affiliates		(36.9	)		(34.3	)		(33.0	)		(19.9	)
Purchased power – affiliates		(75.4	)		(30.4	)		(131.2	)		(26.2	)
Total fuel and purchased power expenses	$	(142.7	)				$	(232.0	)

In the second quarter 2009, total fuel and purchased power expenses were $896.1 million compared to $1.04 billion for the corresponding period in 2008. The decrease was due to an $82.6 million decrease related to fewer KHWs generated and purchased and a $60.1 million decrease in the average cost of purchased power, partially offset by an increase in the average cost of fuel.

For year-to-date 2009, total fuel and purchased power expenses were $1.76 billion compared to $1.99 billion for the corresponding period in 2008. The decrease was due to a $190.3 million decrease related to fewer KWHs generated and purchased and a $41.7 million decrease in the average cost of purchased power, partially offset by an increase in the average cost of fuel.

60

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:

	Second Quarter		Second Quarter		Percent							Percent
Average Cost	2009		2008		Change			Year-to-Date 2009		Year-to-Date 2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		3.40		3.03		12.2			3.32		2.94		12.9
Purchased power		6.41		8.90		(28.0	)		6.41		8.07		(20.6	)

In the second quarter 2009, fuel expense was $652.9 million compared to $683.3 million for the corresponding period in 2008. For year-to-date 2009, fuel expense was $1.25 billion compared to $1.32 billion for the corresponding period in 2008. These decreases were due to lower natural gas prices and decreases of 14.3% and 16.2% in KWHs generated in the second quarter and year-to-date 2009, respectively, as a result of lower KWH demand. These decreases were partially offset by increases of 22.6% and 25.5% in the average cost of coal per KWH generated in the second quarter and year-to-date 2009, respectively.

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

Non-Affiliates

In the second quarter 2009, purchased power from non-affiliates was $70.8 million compared to $107.7 million for the corresponding period in 2008. For year-to-date 2009, purchased power from non-affiliates was $132.8 million compared to $165.8 million for the corresponding period in 2008. These decreases were due to 44.9% and 38.4% decreases in the average cost per KWH purchased in the second quarter and year-to-date 2009, respectively, over the corresponding periods in 2008. These decreases were partially offset by a 24.6% increase and a 33.1% increase in the volume of KWHs purchased from available lower-priced market energy alternatives in the second quarter and year-to-date 2009, respectively, over the corresponding periods in 2008.

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

Affiliates

In the second quarter 2009, purchased power from affiliates was $172.4 million compared to $247.8 million for the corresponding period in 2008. For year-to-date 2009, purchased power from affiliates was $369.6 million compared to $500.8 million for the corresponding period in 2008. These decreases were primarily due to 21.6% and 15.4% decreases in the average cost per KWH purchased for the second quarter and year-to-date 2009, respectively. These decreases were partially offset by a 20.5% increase and a 5.0% increase in the volume of KWHs purchased in the second quarter and year-to-date 2009, respectively.

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.

61

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

Other Operations and Maintenance Expenses

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(38.2)	(9.8)	$(16.5)	(2.2)

In the second quarter 2009, other operations and maintenance expenses were $353.6 million compared to $391.8 million for the corresponding period in 2008. The decrease was due to a $19.1 million decrease in power generation, a $13.9 million decrease in transmission and distribution, and a decrease of $7.1 million in customer accounting, service, and sales costs all of which are related to cost containment activities in an effort to offset the effects of the recessionary economy.

For year-to-date 2009, other operations and maintenance expenses were $744.1 million compared to $760.6 million for the corresponding period in 2008. The decrease was due to a $20.1 million decrease in power generation, an $18.3 million decrease in transmission and distribution, and a $13.3 million decrease in customer accounting, service, and sales costs primarily due to the cost containment activities described above, partially offset by a $4.5 million increase in uncollectible accounts and a $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition plan under which 579 employees elected to resign their positions effective March 31, 2009. In the second quarter 2009, approximately one-third of the $29.4 million charge was offset by lower salary and employee benefits costs, and the other two-thirds will be offset during the remainder of the year. This charge is not expected to have a material impact on Georgia Power’s financial statements for the year ending December 31, 2009.

Depreciation and Amortization

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$15.9	10.0	$32.4	10.5

In the second quarter 2009, depreciation and amortization was $175.1 million compared to $159.2 million for the corresponding period in 2008. For year-to-date 2009, depreciation and amortization was $342.2 million compared to $309.8 million for the corresponding period in 2008. These increases were primarily due to additional plant in service related to transmission, distribution, and environmental projects.

Allowance for Equity Funds Used During Construction

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(1.7)	(7.0)	$(8.6)	(16.8)

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

For year-to-date 2009, AFUDC was $43.1 million compared to $51.7 million for the corresponding period in 2008. The decrease was due to a decrease in the average construction work in progress balances for year-to-date 2009 compared to the corresponding period in 2008 as a result of projects completed in 2008.

62

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

Interest Expense, Net of Amount Capitalized

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$15.7	18.7	$27.7	16.3

In the second quarter 2009, interest expense, net of amounts capitalized was $99.4 million compared with $83.7 million for the corresponding period in 2008. For year-to-date 2009, interest expense, net of amounts capitalized was $197.8 million compared to $170.1 million for the corresponding period in 2008. These increases were primarily due to an increase in long-term debt levels resulting from the issuance of additional senior notes in the last 12 months, partially offset by lower average interest rates on existing variable rate debt.

Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(32.6)	(24.6)	$(53.8)	(24.9)

In the second quarter 2009, income taxes were $99.7 million compared with $132.3 million for the corresponding period in 2008. For year-to-date 2009, income taxes were $162.3 million compared with $216.1 million for the corresponding period in 2008. The decreases were primarily due to lower pre-tax net income.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

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

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA’s regulation of cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed the U.S. Court of Appeals for the Second Circuit’s decision

63

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

with respect to the rule’s use of cost-benefit analysis and held that the EPA could consider costs in arriving at its standards and in providing variances from those standards for existing power plant cooling water intake structures. Other aspects of the court’s decision were not appealed and remain unaffected by the U.S. Supreme Court’s ruling. While the U.S. Supreme Court’s decision may ultimately result in greater flexibility for demonstrating compliance with the standards, the full scope of the regulations will depend on subsequent legal proceedings, further rulemaking by the EPA, the results of studies and analyses performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies and, therefore, cannot be determined at this time.

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Georgia Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives and is expected to now be considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Georgia Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Georgia PSC Matters

Market-Based Rate Authority

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information. In May 2008, the Georgia PSC approved an additional increase of approximately $222 million effective June 2008. On March 10, 2009, the Georgia PSC granted Georgia Power’s request to delay its fuel case filing until September 4, 2009. The extension was requested as a result of difficulty in establishing a forward-looking fuel rate due to volatile coal and gas prices, uncertain sales forecasts, and a continuing decline in the State of Georgia’s economy. As of June 30, 2009, Georgia Power had a total under recovered fuel cost balance of approximately $711 million compared to $764 million at December 31, 2008. The ultimate outcome of this matter cannot be determined at this time.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.

Retail Rate Matters

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

The economic recession has significantly reduced Georgia Power’s revenues upon which retail rates were set under the 2007 Retail Rate Plan. Despite stringent efforts to reduce expenses, current projections indicate Georgia Power’s retail ROE will be less than 10.25% in both 2009 and 2010. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations. Under Georgia Power’s proposal, the regulatory liability would be amortized ratably over the 18-month period from July 1, 2009 through December 31, 2010 as a reduction to operating expenses. Even if the Georgia PSC approves the accounting order request as filed, Georgia Power currently expects its retail ROE will remain below the 10.25% low end of its allowed retail ROE range in 2009 and 2010. The accounting order request is subject to the review and approval of the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Georgia Power. Georgia Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $120 million and $150 million. Southern Company and its subsidiaries have also filed an application under the ARRA for a grant, of which approximately $140 million relates to Georgia Power, to be used primarily for the advanced metering

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

infrastructure program and other transmission and distribution automation and modernization projects. Georgia Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Construction

Nuclear

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

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

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

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

Other

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

Nuclear Relicensing

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

Other Matters

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. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials 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.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

New Accounting Standards

Variable Interest Entities

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Georgia Power’s financial condition remained stable at June 30, 2009. Throughout the turmoil in the financial markets, Georgia Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper borrowings and variable rate pollution control revenue bonds. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Georgia Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees at Georgia Power currently average less than³/₈ of 1% per year. Georgia Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Georgia Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

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

Georgia Power’s investments in pension and nuclear decommissioning trust funds stabilized during the second quarter 2009. Georgia Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time. Georgia Power does not expect any changes to funding obligations to the nuclear decommissioning trusts prior to 2011.

Net cash provided from operating activities totaled $337.8 million for the first six months of 2009, compared to $677.6 million for the corresponding period in 2008. The $339.8 million decrease in cash provided from operating activities in the first six months of 2009 was primarily due to the $112 million decrease in net income and an increase of $182 million in fuel and materials inventory additions. Net cash used for investing activities totaled $1.1 billion for the first six months of 2009, compared to $1.0 billion for the corresponding period in 2008, primarily due to gross property additions to utility plant. Net cash provided from financing activities totaled $680.1 million for the first six months of 2009, compared to $333.5 million for the corresponding period in 2008. The $346.6 million increase was primarily due to higher capital contributions from Southern Company.

Significant balance sheet changes for the first six months of 2009 include an increase of $1.0 billion in total property, plant, and equipment.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $435 million will be required through June 30, 2010 to fund maturities and announced redemptions of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in nuclear plants to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

Georgia Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at June 30, 2009 approximately $37.7 million of cash and cash equivalents and approximately $1.7 billion of unused credit arrangements with banks. See Note 6 to the financial statements of

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

Georgia Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Of the unused credit arrangements in place at June 30, 2009, $555 million expire in 2010 and $1.1 billion expire in 2012. Subsequent to June 30, 2009, Georgia Power entered into a new $40 million credit arrangement. The agreement expires in 2010 and contains a two-year term loan executable at expiration. Georgia Power expects to renew its credit facilities, as needed, prior to expiration.

Credit arrangements provide liquidity support to Georgia Power’s purchase obligations related to variable rate pollution control revenue bonds and commercial paper borrowings. At June 30, 2009, Georgia Power had $636.3 million of variable rate pollution control revenue bonds. Subsequent to June 30, 2009, Georgia Power incurred an additional $154.3 million of obligations related to variable rate pollution control revenue bonds and converted another $20.8 million from a fixed rate mode to a variable rate mode, increasing the total outstanding variable rate pollution control bonds to $811.4 million. Georgia Power may meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At June 30, 2009, Georgia Power had approximately $471 million of commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At June 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $39 million. At June 30, 2009, 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. In addition, certain nuclear fuel agreements could require collateral of up to $187 million in the event of a rating change to below investment grade for Southern Company. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

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

Due to cost-based rate regulation, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

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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 for the three and six months ended June 30, 2009 were as follows:

	Second Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(176.6	)	$	(113.2	)
Contracts realized or settled		54.3			74.1
Current period changes(a)		(3.1	)		(86.3	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(125.4	)	$	(125.4	)

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

The changes in the fair value positions of the energy-related derivative contracts for the three months and six months ended June 30, 2009 were an increase of $51 million and a decrease of $12 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At June 30, 2009, Georgia Power had a net hedge volume of 75 million mmBtu with a weighted average contract cost approximately $1.69 per mmBtu above market prices, compared to 72 million mmBtu at March 31, 2009 with a weighted average contract cost approximately $2.53 per mmBtu above market prices and compared to 59 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $1.96 per mmBtu above market prices. The natural gas hedge settlements are recovered through the fuel cost recovery mechanism.

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

	June 30,			December 31,
	2009			2008
	(in millions)
Regulatory hedges	$	(125.4	)	$	(113.2	)
Not designated		—			—
Total fair value	$	(125.4	)	$	(113.2	)

Energy-related derivative contracts which are designated as regulatory hedges relate to Georgia Power’s fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery mechanism. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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

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

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

	June 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
				(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(125.4	)		(100.6	)		(25.1	)		0.3
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(125.4	)	$	(100.6	)	$	(25.1	)	$	0.3

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

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

Financing Activities

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

Subsequent to June 30, 2009, Georgia Power incurred obligations in connection with the issuance of $154.3 million of variable rate pollution control revenue bonds. The proceeds of the bonds were used to retire $154.3 million of fixed rate pollution control revenue bonds.

Subsequent to June 30, 2009, Georgia Power issued a notice to redeem on August 21, 2009 its $55 million of Series D 5.50% Senior Insured Quarterly Notes due November 15, 2017.

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.

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GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	290,050		$	284,218		$	528,441		$	512,182
Wholesale revenues, non-affiliates		22,700			25,052			44,666			50,708
Wholesale revenues, affiliates		10,727			26,524			16,087			69,464
Other revenues		17,618			14,073			36,185			29,048
Total operating revenues		341,095			349,867			625,379			661,402
Operating Expenses:
Fuel		156,195			165,999			271,748			316,126
Purchased power, non-affiliates		6,051			6,086			10,489			9,212
Purchased power, affiliates		13,240			16,685			28,621			25,428
Other operations and maintenance		64,983			65,774			137,474			132,205
Depreciation and amortization		23,317			22,206			46,376			43,910
Taxes other than income taxes		22,989			20,803			45,437			41,499
Total operating expenses		286,775			297,553			540,145			568,380
Operating Income		54,320			52,314			85,234			93,022
Other Income and (Expense):
Allowance for equity funds used during construction		5,707			2,040			10,525			3,523
Interest income		85			709			294			1,418
Interest expense, net of amounts capitalized		(9,907	)		(10,678	)		(19,739	)		(21,674	)
Other income (expense), net		(487	)		(344	)		(1,103	)		(1,010	)
Total other income and (expense)		(4,602	)		(8,273	)		(10,023	)		(17,743	)
Earnings Before Income Taxes		49,718			44,041			75,211			75,279
Income taxes		15,899			15,499			23,299			25,656
Net Income		33,819			28,542			51,912			49,623
Dividends on Preference Stock		1,550			1,550			3,101			3,101
Net Income After Dividends on Preference Stock	$	32,269		$	26,992		$	48,811		$	46,522

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
	(in thousands)				(in thousands)
Net Income After Dividends on Preference Stock	$	32,269	$	26,992	$	48,811	$	46,522
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $403, $-, and $(1,077), respectively		—		643		—		(1,715	)
Reclassification adjustment for amounts included in net income, net of tax of $104, $103, $209, and $157, respectively		167		162		334		249
Total other comprehensive income (loss)		167		805		334		(1,466	)
Comprehensive Income	$	32,436	$	27,797	$	49,145	$	45,056

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 Six Months
	Ended June 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	51,912		$	49,623
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		48,831			46,438
Deferred income taxes		(10,224	)		9,215
Allowance for equity funds used during construction		(10,525	)		(3,523	)
Pension, postretirement, and other employee benefits		(597	)		554
Stock option expense		637			537
Tax benefit of stock options		3			109
Hedge settlements		—			(5,220	)
Other, net		(1,762	)		(60	)
Changes in certain current assets and liabilities —
-Receivables		(3,606	)		(27,073	)
-Fossil fuel stock		(50,999	)		(26,432	)
-Materials and supplies		(459	)		6,669
-Prepaid income taxes		416			—
-Property damage cost recovery		10,816			12,463
-Other current assets		1,319			1,339
-Accounts payable		(1,002	)		6,419
-Accrued taxes		13,591			4,433
-Accrued compensation		(9,347	)		(6,952	)
-Other current liabilities		10,640			2,838
Net cash provided from operating activities		49,644			71,377
Investing Activities:
Property additions		(240,336	)		(149,760	)
Investment in restricted cash from pollution control revenue bonds		(49,188	)		—
Distribution of restricted cash from pollution control revenue bonds		11,417			—
Cost of removal, net of salvage		(5,439	)		(4,519	)
Construction payables		9,661			5,754
Other investing activities		(3,375	)		(2,885	)
Net cash used for investing activities		(277,260	)		(151,410	)
Financing Activities:
Decrease in notes payable, net		(73,944	)		(40,801	)
Proceeds —
Common stock issued to parent		135,000			—
Capital contributions from parent company		1,897			73,060
Gross excess tax benefit of stock options		9			212
Pollution control revenue bonds		130,400			—
Senior notes		140,000			—
Other long-term debt issuances		—			110,000
Redemptions —
Senior notes		(722	)		(651	)
Payment of preference stock dividends		(3,101	)		(2,956	)
Payment of common stock dividends		(44,650	)		(40,850	)
Other financing activities		(1,556	)		(2,141	)
Net cash provided from financing activities		283,333			95,873
Net Change in Cash and Cash Equivalents		55,717			15,840
Cash and Cash Equivalents at Beginning of Period		3,443			5,348
Cash and Cash Equivalents at End of Period	$	59,160		$	21,188
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $4,195 and $1,404 capitalized for 2009 and 2008, respectively)	$	19,502		$	19,831
Income taxes (net of refunds)	$	25,642		$	17,744

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 June 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	59,160		$	3,443
Restricted cash and cash equivalents		37,771			—
Receivables —
Customer accounts receivable		91,578			69,531
Unbilled revenues		71,132			48,742
Under recovered regulatory clause revenues		54,573			98,644
Other accounts and notes receivable		5,943			7,201
Affiliated companies		4,205			8,516
Accumulated provision for uncollectible accounts		(2,120	)		(2,188	)
Fossil fuel stock, at average cost		159,084			108,129
Materials and supplies, at average cost		37,295			36,836
Other regulatory assets, current		37,791			38,908
Other current assets		25,320			25,655
Total current assets		581,732			443,417
Property, Plant, and Equipment:
In service		2,872,680			2,785,561
Less accumulated provision for depreciation		993,670			971,464
Plant in service, net of depreciation		1,879,010			1,814,097
Construction work in progress		540,019			391,987
Total property, plant, and equipment		2,419,029			2,206,084
Other Property and Investments		15,779			15,918
Deferred Charges and Other Assets:
Deferred charges related to income taxes		31,556			24,220
Other regulatory assets, deferred		172,345			170,836
Other deferred charges and assets		24,569			18,550
Total deferred charges and other assets		228,470			213,606
Total Assets	$	3,245,010		$	2,879,025

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

	At June 30,			At December 31,
Liabilities and Stockholder's Equity	2009			2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	140,000		$	—
Notes payable		65,986			148,239
Accounts payable —
Affiliated		58,777			50,304
Other		93,742			90,381
Customer deposits		30,571			28,017
Accrued taxes —
Accrued income taxes		23,610			39,983
Other accrued taxes		18,064			11,855
Accrued interest		9,363			8,959
Accrued compensation		6,319			15,667
Other regulatory liabilities, current		17,799			4,602
Liabilities from risk management activities		23,734			26,928
Other current liabilities		21,254			29,047
Total current liabilities		509,219			453,982
Long-term Debt		979,177			849,265
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		275,861			254,354
Accumulated deferred investment tax credits		10,454			11,255
Employee benefit obligations		95,660			97,389
Other cost of removal obligations		185,098			180,325
Other regulatory liabilities, deferred		41,668			28,597
Other deferred credits and liabilities		85,743			83,768
Total deferred credits and other liabilities		694,484			655,688
Total Liabilities		2,182,880			1,958,935
Preference Stock		97,998			97,998
Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - June 30, 2009: 3,142,717 shares
- December 31, 2008: 1,792,717 shares		253,060			118,060
Paid-in capital		514,091			511,547
Retained earnings		201,579			197,417
Accumulated other comprehensive loss		(4,598	)		(4,932	)
Total common stockholder’s equity		964,132			822,092
Total Liabilities and Stockholder’s Equity	$	3,245,010		$	2,879,025

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

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

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$5.3	19.6	$2.3	4.9

Gulf Power’s net income after dividends on preference stock for the second quarter 2009 was $32.3 million compared to $27.0 million for the corresponding period in 2008. The increase was primarily due to increased allowance for equity funds used during construction (AFUDC), which is non-taxable, and a decrease in other operations and maintenance expenses.

Gulf Power’s net income after dividends on preference stock for year-to-date 2009 was $48.8 million compared to $46.5 million for the corresponding period in 2008. The increase was primarily due to increased AFUDC, partially offset by a decline in sales, less favorable weather, and increased other operations and maintenance expenses.

Retail Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$5.9	2.1	$16.2	3.1

In the second quarter 2009, retail revenues were $290.1 million compared to $284.2 million for the corresponding period in 2008. For year-to-date 2009, retail revenues were $528.4 million compared to $512.2 million for the corresponding period in 2008.

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

Details of the change to retail revenues are as follows:

	Second Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	284.2					$	512.2
Estimated change in –
Rates and pricing		8.0			2.9			15.3			3.0
Sales growth (decline)		0.6			0.2			(3.5	)		(0.7	)
Weather		(1.4	)		(0.5	)		(3.0	)		(0.6	)
Fuel and other cost recovery		(1.3	)		(0.5	)		7.4			1.4
Retail – current year	$	290.1			2.1	%	$	528.4			3.1	%

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

Revenues attributable to changes in sales increased in the second quarter 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential and commercial customers increased 3.6% and 1.9%, respectively, primarily due to increased customer usage. KWH energy sales to industrial customers decreased 22.1% as a result of recessionary economic conditions and increased customer co-generation due to the lower cost of natural gas.

Revenues attributable to changes in sales declined year-to-date 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential customers increased 0.4% primarily due to increased customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 0.9% primarily due to decreased customer usage driven by the recession. KWH energy sales to industrial customers decreased 21.2% as a result of recessionary economic conditions and increased customer co-generation due to the lower cost of natural gas.

Revenues attributable to changes in weather decreased in the second quarter and year-to-date 2009 when compared to the corresponding periods in 2008. These decreases were due to less favorable weather in 2009.

Fuel and other cost recovery revenues decreased in the second quarter 2009 when compared to the corresponding period in 2008 due to overall decreased customer usage primarily resulting from decreased industrial usage. Fuel and other cost recovery revenues increased year-to-date 2009 when compared to the corresponding period in 2008 primarily due to higher projected fuel and purchased power costs. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and revenues related to the recovery of storm damage restoration costs. Annually, Gulf Power petitions the Florida PSC for recovery of projected fuel and purchased power costs including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material impact on net income. See FUTURE EARNINGS POTENTIAL – “FERC and Florida PSC Matters – Retail Fuel Cost Recovery” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under “Revenues” and

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

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

Wholesale Revenues – Non-Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(2.3)	(9.4)	$(6.0)	(11.9)

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

In the second quarter 2009, wholesale revenues from non-affiliates were $22.7 million compared to $25.0 million for the corresponding period in 2008. The decrease was primarily a result of lower energy revenues related to 17.5% decrease in KWH sales.

For year-to-date 2009, wholesale revenues from non-affiliates were $44.7 million compared to $50.7 million for the corresponding period in 2008. The decrease was primarily a result of lower energy revenues related to 21.5% decrease in KWH sales.

Wholesale Revenues – Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(15.8)	(59.6)	$(53.4)	(76.8)

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.

In the second quarter 2009, wholesale revenues from affiliates were $10.7 million compared to $26.5 million for the corresponding period in 2008. The decrease was due to reduced customer demand resulting in a 30.4% decrease in KWH sales and a 41.9% decrease in price related to lower Power Pool interchange energy rates.

For year-to-date 2009, wholesale revenues from affiliates were $16.1 million compared to $69.5 million for the corresponding period in 2008. The decrease was due to reduced customer demand resulting in a 66.9% decrease in KWH sales and a 30.0% decrease in price related to lower Power Pool interchange energy rates.

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

Other Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$3.5	25.2	$7.2	24.6

In the second quarter 2009, other revenues were $17.6 million compared to $14.1 million for the corresponding period in 2008. For year-to-date 2009, other revenues were $36.2 million compared to $29.0 million for the corresponding period in 2008. These increases were primarily due to other energy services and higher franchise fees. The increased revenues from other energy services did not have a material impact on net income since they were generally offset by associated expenses. Franchise fees have no impact on net income.

Fuel and Purchased Power Expenses

	Second Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Second Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(9.8	)		(5.9	)	$	(44.4	)		(14.0	)
Purchased power – non-affiliates		(0.1	)		(0.6	)		1.3			13.9
Purchased power – affiliates		(3.4	)		(20.6	)		3.2			12.6
Total fuel and purchased power expenses	$	(13.3	)				$	(39.9	)

In the second quarter 2009, total fuel and purchased power expenses were $175.5 million compared to $188.8 million for the corresponding period in 2008. The net decrease in fuel and purchased power expenses was due to an $18.1 million decrease related to fewer KWHs generated and a $5.6 million decrease in the average cost of fuel and purchased power, partially offset by a $10.4 million increase related to KWHs purchased.

For year-to-date 2009, total fuel and purchased power expenses were $310.8 million compared to $350.7 million for the corresponding period in 2008. The net decrease in fuel and purchased power expenses was due to a $68.2 million decrease related to fewer KWHs generated, partially offset by a $26.9 million increase related to KWHs purchased as well as a $1.4 million 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 expenses are generally offset by energy revenues through Gulf Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “FERC and Florida PSC Matters – Retail Fuel Cost Recovery” herein for additional information.

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

	Second Quarter		Second Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2009		2008		Change			2009		2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		4.45		4.26		4.5			4.39		4.03		8.9
Purchased power		6.71		10.73		(37.5	)		5.87		8.90		(34.0	)

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

In the second quarter 2009, fuel expense was $156.2 million compared to $166.0 million for the corresponding period in 2008. The decrease was due to a decrease of 10.9% in KWHs generated as a result of lower KWH demand, and lower natural gas prices of 47.7%. The decrease was partially offset by an increase of 27.5% in the average cost of coal per KWH generated.

For year-to-date 2009, fuel expense was $271.7 million compared to $316.1 million for the corresponding period in 2008. The decrease was due to a decrease of 21.6% in KWHs generated as a result of lower KWH demand, and lower natural gas prices of 38.3%. The decrease was partially offset by an increase of 25.1% in the average cost of coal per KWH generated.

Non-Affiliates

In the second quarter 2009, purchased power from non-affiliates was $6.0 million compared to $6.1 million for the corresponding period in 2008. The decrease was not material.

For year-to-date 2009, purchased power from non-affiliates was $10.5 million compared to $9.2 million for the corresponding period in 2008. The increase was due to a 30.4% increase in the volume of KWHs purchased from available lower-priced market energy alternatives. The increase was partially offset by a 1.6% decrease in the average cost per KWH purchased.

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

Affiliates

In the second quarter 2009, purchased power from affiliates was $13.3 million compared to $16.7 million for the corresponding period in 2008. The decrease was due to a 51.7% decrease in average cost per KWH purchased, partially offset by a 66.3% increase in the volume of KWHs purchased from available lower-priced market energy alternatives.

For year-to-date 2009, purchased power from affiliates was $28.6 million compared to $25.4 million for the corresponding period in 2008. The increase was due to a 106.9% increase in the volume of KWHs purchased from available lower-priced market energy alternatives, partially offset by a 45.3% decrease in the average cost per KWH purchased.

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

Other Operations and Maintenance Expenses

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(0.8)	(1.2)	$5.3	4.0

In the second quarter 2009, other operations and maintenance expenses when compared to the corresponding period in 2008 were not material.

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

For year-to-date 2009, other operations and maintenance expenses were $137.5 million compared to $132.2 million for the corresponding period in 2008. The increase was primarily due to a $5.5 million increase in other energy services and a $1.5 million increase in scheduled maintenance at generation facilities, partially offset by a $1.7 million decrease in storm recovery costs. The increased expense from other energy services and the decreased storm recovery costs did not have a material impact on earnings since they were offset by increased associated revenues.

Depreciation and Amortization

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$1.1	5.0	$2.5	5.6

In the second quarter 2009, depreciation and amortization was $23.3 million compared to $22.2 million for the corresponding period in 2008. For year-to-date 2009, depreciation and amortization was $46.4 million compared to $43.9 million for the corresponding period in 2008. The increases were primarily due to net additions to generation and distribution facilities.

Taxes Other Than Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$2.2	10.5	$3.9	9.5

In the second quarter 2009, taxes other than income taxes were $23.0 million compared to $20.8 million for the corresponding period in 2008. For year-to-date 2009, taxes other than income taxes were $45.4 million compared to $41.5 million for the corresponding period in 2008. The increases were primarily due to increases in franchise fees and gross receipt taxes, which were directly related to increased retail revenues.

Allowance for Equity Funds Used During Construction

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$3.7	N/M	$7.0	N/M

N/M-Not Meaningful

In the second quarter 2009, AFUDC was $5.7 million compared to $2.0 million for the corresponding period in 2008. For year-to-date 2009, AFUDC was $10.5 million compared to $3.5 million for the corresponding period in 2008. These increases were primarily due to the construction of environmental control projects.

Interest Income

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(0.6)	(88.0)	$(1.1)	(79.3)

In the second quarter 2009, interest income was $0.1 million compared to $0.7 million for the corresponding period in 2008. For year-to-date 2009, interest income was $0.3 million compared to $1.4 million for the corresponding period in 2008. These decreases were primarily due to decreases in interest received related to the recovery of financing costs associated with the fuel clause and interest on investments.

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

Interest Expense, Net of Amounts Capitalized

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(0.8)	(7.2)	$(1.9)	(8.9)

In the second quarter 2009, interest expense, net of amounts capitalized was $9.9 million compared to $10.7 million for the corresponding period in 2008. For year-to-date 2009, interest expense, net of amounts capitalized was $19.8 million compared to $21.7 million for the corresponding period in 2008. These decreases were primarily the result of an increase in capitalization of AFUDC related to the construction of environmental control projects.

Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$0.4	2.6	$(2.4)	(9.2)

In the second quarter 2009, income taxes were $15.9 million compared to $15.5 million for the corresponding period in 2008. The increase was primarily due to higher earnings before income taxes, partially offset by an increase in the tax benefit associated with an increase in AFUDC, which is non-taxable, and state tax credits.

For year-to-date 2009, income taxes were $23.3 million compared to $25.7 million for the corresponding period in 2008. The decrease was primarily due to an increase in the tax benefit associated with an increase in AFUDC, which is non-taxable, and state tax credits, partially offset by a decrease in the federal production activities deduction.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

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

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

Water Quality

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

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Gulf Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives and is expected to now be considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Gulf Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

FERC and Florida PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern

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

Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Fuel Cost Recovery

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

Under recovered fuel costs at June 30, 2009 totaled $52.7 million, compared to $96.7 million at December 31, 2008. This amount is included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor would have no significant effect on Gulf Power’s revenues or net income, but would affect cash flow. 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.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Gulf Power. Gulf Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $13 million and $16 million. Southern Company and its subsidiaries have also filed an application under the ARRA for a grant, of which approximately $38 million relates to Gulf Power, to be used primarily for the advanced metering infrastructure program and other transmission and distribution automation and modernization projects. Gulf Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Other Matters

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

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under the Agreement will be material; however these costs have been approved by the Florida PSC for recovery through Gulf Power’s fuel clause and purchased power capacity clause; therefore, no material impact is expected on Gulf Power’s net income. The ultimate outcome of this matter cannot now be determined.

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. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials 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.

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, and Unbilled Revenues.

New Accounting Standards

Variable Interest Entities

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

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FINANCIAL CONDITION AND LIQUIDITY

Overview

Gulf Power’s financial condition remained stable at June 30, 2009. Throughout the turmoil in the financial markets, Gulf Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper borrowings and variable rate pollution control revenue bonds. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Gulf Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. In the second quarter 2009, Gulf Power renewed $20 million of expiring credit facilities and entered into an additional $80 million of credit facilities. Total committed credit fees at Gulf Power currently average less than¹/2 of 1% per year. Gulf Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Gulf Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Gulf Power’s investments in pension trust funds stabilized during the second quarter 2009. Gulf Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time.

Net cash provided from operating activities totaled $49.6 million for the first six months of 2009 compared to $71.4 million for the corresponding period in 2008. The $21.8 million decrease in cash provided from operating activities was primarily due to a $22.4 million increase in customer receivables. Net cash used for investing activities in the first six months of 2009 totaled $277.3 million primarily due to gross property additions to utility plant. These additions were primarily related to installation of equipment to comply with environmental requirements. Net cash provided from financing activities totaled $283.3 million for the first six months of 2009, compared to $95.9 million for the corresponding period in 2008. The $187.4 million increase in cash provided from financing activities was primarily due to the issuances of $140.0 million of senior notes, $135.0 million of common stock to Southern Company, and $130.4 million of pollution control revenue bonds in 2009, partially offset by an issuance of $110 million of long-term debt in 2008, a $71.2 million decrease of capital contributions from Southern Company, and a $33.1 million increase in cash payments related to notes payable.

Significant balance sheet changes for the first six months of 2009 include a net increase of $212.9 million in property, plant, and equipment, primarily related to environmental control projects; the issuance of $140.0 million in senior notes; the issuance of common stock to Southern Company for $135.0 million; the issuance of $130.4 million of pollution control revenue bonds, with a related restricted cash balance of $37.8 million; an increase in customer accounts receivable and unbilled revenues of $44.4 million; and a $44.0 million decrease in under recovered regulatory clause revenues related to fuel.

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

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power’s capital requirements for its construction program, maturities of long-term debt, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $140 million will be required through June 30, 2010 to fund maturities of debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power had at June 30, 2009 approximately $59.2 million of cash and cash equivalents and $220 million of unused committed lines of credit with banks. Of these credit agreements, $90 million expire in 2009, $130 million expire in 2010, and $70 million of these facilities contain provisions allowing one-year term loans executable at expiration. Gulf Power expects to renew its credit facilities, as needed, prior to expiration. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. These credit arrangements provide liquidity support to Gulf Power’s commercial paper borrowings and $69 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Gulf Power may meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At June 30, 2009, Gulf Power had $66 million of commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At June 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $62 million. At June 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $246 million. Included in these amounts are certain agreements that could require collateral

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

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

Market Price Risk

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

Due to cost-based rate regulation, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Gulf Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Gulf Power continues to manage a fuel-hedging program implemented per the guidelines of the Florida PSC. As such, Gulf Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

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

	Second Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(43.2	)	$	(31.2	)
Contracts realized or settled		15.2			23.2
Current period changes(a)		(0.2	)		(20.2	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(28.2	)	$	(28.2	)

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

The increases in the fair value positions of the energy-related derivative contracts for the three months and six months ended June 30, 2009 were $15 million and $3 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to both the volume and prices of natural gas. At June 30, 2009, Gulf Power had a net hedge volume of 15 million mmBtu with a weighted average contract cost approximately $1.95 per mmBtu above market prices, compared to 16 million mmBtu at March 31, 2009 with a weighted average contract cost approximately $2.76 per mmBtu above market prices and compared to 14 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $2.24 per mmBtu above market prices. Natural gas hedge settlements are recovered through the fuel cost recovery clause.

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

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

	June 30,			December 31,
	2009			2008
	(in millions)
Regulatory hedges	$	(28.2	)	$	(31.2	)
Not designated		—			—
Total fair value	$	(28.2	)	$	(31.2	)

Energy-related derivative contracts which are designated as regulatory hedges relate to Gulf Power’s fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clause. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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

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

	June 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(28.2	)		(23.4	)		(4.8	)		—
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(28.2	)	$	(23.4	)	$	(4.8	)	$	—

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

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

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

Financing Activities

On January 22, 2009, Gulf Power issued to Southern Company 1,350,000 shares of Gulf Power common stock, without par value, and realized proceeds of $135 million. The proceeds were used to repay a portion of Gulf Power’s short-term debt and for other general corporate purposes, including Gulf Power’s continuous construction program.

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

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

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

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

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MISSISSIPPI POWER COMPANY

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MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	201,132		$	187,121		$	376,867		$	355,510
Wholesale revenues, non-affiliates		73,693			83,595			153,847			168,401
Wholesale revenues, affiliates		7,963			22,546			17,381			50,925
Other revenues		3,893			4,670			7,309			8,512
	��
Total operating revenues		286,681			297,932			555,404			583,348
Operating Expenses:
Fuel		125,832			138,857			245,797			268,973
Purchased power, non-affiliates		2,873			5,426			5,708			7,681
Purchased power, affiliates		21,595			17,484			43,400			43,482
Other operations and maintenance		61,601			63,368			121,362			128,141
Depreciation and amortization		17,660			17,101			35,675			35,098
Taxes other than income taxes		16,221			16,286			31,145			31,851
Total operating expenses		245,782			258,522			483,087			515,226
Operating Income		40,899			39,410			72,317			68,122
Other Income and (Expense):
Interest income		163			184			795			593
Interest expense, net of amounts capitalized		(6,254	)		(4,391	)		(11,016	)		(8,832	)
Other income (expense), net		1,136			2,899			2,765			4,518
Total other income and (expense)		(4,955	)		(1,308	)		(7,456	)		(3,721	)
Earnings Before Income Taxes		35,944			38,102			64,861			64,401
Income taxes		13,578			13,664			24,091			23,358
Net Income		22,366			24,438			40,770			41,043
Dividends on Preferred Stock		433			433			866			866
Net Income After Dividends on Preferred Stock	$	21,933		$	24,005		$	39,904		$	40,177

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009		2008
	(in thousands)						(in thousands)
Net Income After Dividends on Preferred Stock	$	21,933		$	24,005		$	39,904	$	40,177
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(139), $(144), $27, and $(1,454), respectively		(224	)		(233	)		44		(2,347	)
Comprehensive Income	$	21,709		$	23,772		$	39,948	$	37,830

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

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MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months
	Ended June 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	40,770		$	41,043
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		39,202			37,232
Deferred income taxes and investment tax credits, net		(11,019	)		(8,732	)
Pension, postretirement, and other employee benefits		2,852			3,765
Stock option expense		747			555
Tax benefit of stock options		14			95
Generation construction screening expense		(14,049	)		(8,780	)
Other, net		2,078			(1,861	)
Changes in certain current assets and liabilities —
-Receivables		13,274			(22,108	)
-Fossil fuel stock		(44,024	)		(30,521	)
-Materials and supplies		(1,464	)		(13,569	)
-Prepaid income taxes		(446	)		1,607
-Other current assets		(12,644	)		273
-Other accounts payable		(14,103	)		14,948
-Accrued taxes		(14,243	)		(20,369	)
-Accrued compensation		(12,990	)		(12,379	)
-Other current liabilities		2,260			19,801
Net cash provided from (used for) operating activities		(23,785	)		1,000
Investing Activities:
Property additions		(50,943	)		(57,404	)
Cost of removal, net of salvage		(7,287	)		(424	)
Construction payables		(4,709	)		(7,275	)
Hurricane Katrina capital grant proceeds		—			7,314
Other investing activities		(1,412	)		(998	)
Net cash used for investing activities		(64,351	)		(58,787	)
Financing Activities:
Increase in notes payable, net		20,501			10,669
Proceeds —
Capital contributions from parent company		2,101			2,714
Gross excess tax benefit of stock options		60			253
Senior notes issuances		125,000			—
Other long-term debt issuances		—			80,000
Redemptions —
Senior notes		(40,000	)		—
Payment of preferred stock dividends		(866	)		(866	)
Payment of common stock dividends		(34,250	)		(34,200	)
Other financing activities		(1,780	)		(1,471	)
Net cash provided from financing activities		70,766			57,099
Net Change in Cash and Cash Equivalents		(17,370	)		(688	)
Cash and Cash Equivalents at Beginning of Period		22,413			4,827
Cash and Cash Equivalents at End of Period	$	5,043		$	4,139
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $117 and $58 capitalized for 2009 and 2008, respectively)	$	8,873		$	7,844
Income taxes (net of refunds)	$	27,149		$	32,628

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 June 30,			At December 31,
Assets	2009			2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	5,043		$	22,413
Receivables —
Customer accounts receivable		52,477			40,262
Unbilled revenues		31,445			24,798
Under recovered regulatory clause revenues		21,163			54,994
Other accounts and notes receivable		11,355			8,995
Affiliated companies		23,443			24,108
Accumulated provision for uncollectible accounts		(919	)		(1,039	)
Fossil fuel stock, at average cost		129,562			85,538
Materials and supplies, at average cost		28,607			27,143
Other regulatory assets, current		72,074			59,220
Other current assets		22,497			10,898
Total current assets		396,747			357,330
Property, Plant, and Equipment:
In service		2,296,298			2,234,573
Less accumulated provision for depreciation		932,020			923,269
Plant in service, net of depreciation		1,364,278			1,311,304
Construction work in progress		40,180			70,665
Total property, plant, and equipment		1,404,458			1,381,969
Other Property and Investments		7,606			8,280
Deferred Charges and Other Assets:
Deferred charges related to income taxes		8,807			9,566
Other regulatory assets, deferred		182,882			171,680
Other deferred charges and assets		24,355			23,870
Total deferred charges and other assets		216,044			205,116
Total Assets	$	2,024,855		$	1,952,695

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 June 30,		At December 31,
Liabilities and Stockholder's Equity	2009		2008
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,279	$	41,230
Notes payable		46,794		26,293
Accounts payable —
Affiliated		38,537		36,847
Other		43,203		63,704
Customer deposits		10,539		10,354
Accrued taxes —
Accrued income taxes		8,128		8,842
Other accrued taxes		28,965		50,700
Accrued interest		5,524		3,930
Accrued compensation		7,614		20,604
Other regulatory liabilities, current		9,695		9,718
Liabilities from risk management activities		37,851		29,291
Other current liabilities		20,290		19,144
Total current liabilities		258,419		320,657
Long-term Debt		494,073		370,460
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		222,470		222,324
Deferred credits related to income taxes		12,592		14,074
Accumulated deferred investment tax credits		13,419		14,014
Employee benefit obligations		143,513		142,188
Other cost of removal obligations		96,497		96,191
Other regulatory liabilities, deferred		54,359		51,340
Other deferred credits and liabilities		51,662		52,216
Total deferred credits and other liabilities		594,512		592,347
Total Liabilities		1,347,004		1,283,464
Redeemable Preferred Stock		32,780		32,780
Common Stockholder’s Equity:
Common stock, without par value —
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares		37,691		37,691
Paid-in capital		322,880		319,958
Retained earnings		284,456		278,802
Accumulated other comprehensive income (loss)		44		—
Total common stockholder’s equity		645,071		636,451
Total Liabilities and Stockholder’s Equity	$	2,024,855	$	1,952,695

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

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

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

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(2.1)	(8.6)	$(0.3)	(0.7)

Mississippi Power’s net income after dividends on preferred stock for the second quarter 2009 was $21.9 million compared to $24.0 million for the corresponding period in 2008. Mississippi Power’s net income after dividends on preferred stock for year-to-date 2009 was $39.9 million compared to $40.2 million for the corresponding period in 2008. The decreases in net income after dividends for the second quarter 2009 and year-to-date 2009 were primarily due to decreases in wholesale energy revenues, total other income and (expense), and other revenues. These decreases were partially offset by an increase in territorial base revenues primarily resulting from an increase in territorial wholesale demand and a wholesale base rate increase as well as a decrease in other operations and maintenance expenses.

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Retail Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$14.0	7.5	$21.4	6.0

In the second quarter 2009, retail revenues were $201.1 million compared to $187.1 million for the corresponding period in 2008. For year-to-date 2009, retail revenues were $376.9 million compared to $355.5 million for the corresponding period in 2008.

Details of the change to retail revenues are as follows:

	Second Quarter						Year-to-Date
	2009						2009
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	187.1					$	355.5
Estimated change in —
Rates and pricing		0.9			0.5			2.5			0.7
Sales growth (decline)		(0.3	)		(0.2	)		(2.5	)		(0.7	)
Weather		1.3			0.7			0.2			0.0
Fuel and other cost recovery		12.1			6.5			21.2			6.0
Retail – current year	$	201.1			7.5	%	$	376.9			6.0	%

Revenues associated with changes in rates and pricing increased in the second quarter 2009 when compared to the corresponding period in 2008 due to a $1.1 million increase related to the reclassification of 2008 System Restoration Rider (SRR) revenue reductions to expense pursuant to an order from the Mississippi PSC dated January 9, 2009, partially offset by decreases in retail revenues of approximately $0.2 million related to the ECO Plan rate.

Revenues associated with changes in rates and pricing increased year-to-date 2009 when compared to the corresponding period in 2008 due to a $2.1 million increase related to the reclassification of 2008 SRR revenue reductions to expense pursuant to an order from the Mississippi PSC dated January 9, 2009 and an increase in base rates of $0.9 million related to a rate change effective in mid-January 2008. These increases were partially offset by a decrease of $0.5 million related to the ECO Plan rate.

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 declined in the second quarter 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential and commercial customers decreased 5.2% and 0.2%, respectively. KWH energy sales to industrial customers increased 3.2%. The decrease in weather-adjusted KWH sales to residential and commercial customers is primarily due to a recessionary economy. The increase in industrial sales is primarily due to maintenance outages experienced by some industrial customers in 2008.

Revenues attributable to changes in sales declined for year-to-date 2009 when compared to the corresponding period in 2008. Weather-adjusted KWH energy sales to residential and commercial customers decreased 4.1% and 0.5%, respectively. KWH energy sales to industrial customers decreased 1.6%. The decrease in weather-adjusted KWH sales to residential and commercial customers is primarily due to a recessionary economy. The decrease in industrial sales is primarily due to lower production levels experienced by industrial customers resulting from a recessionary economy.

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Revenues attributable to changes in weather increased slightly in the second quarter and year-to-date 2009 when compared to the corresponding periods in 2008. Revenues resulting from changes in weather were minimal as overall weather conditions were similar in 2009 when compared to the corresponding periods in 2008.

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

Wholesale Revenues – Non-Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(9.9)	(11.8)	$(14.6)	(8.6)

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

In the second quarter 2009, wholesale revenues from non-affiliates were $73.7 million compared to $83.6 million for the corresponding period in 2008. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $15.5 million, partially offset by $5.6 million increased revenues from customers inside Mississippi Power’s service territory. The $15.5 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $17.5 million decrease associated with lower prices resulting from lower marginal cost of fuel, partially offset by a $2.0 million increase in sales. The $5.6 million increase in revenues from customers inside Mississippi Power’s service territory was due to a $3.0 million increase in recoverable fuel costs and a $2.6 million increase due to higher demands by customers and a base rate increase that was effective January 2009.

For year-to-date 2009, wholesale revenues to non-affiliates were $153.8 million compared to $168.4 million for the corresponding period in 2008. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $27.4 million, partially offset by $12.8 million increased revenues from customers inside Mississippi Power’s service territory. The $27.4 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $24.1 million decrease associated with lower prices resulting from lower marginal cost of fuel, a $3.0 million decrease in sales, and a $0.3 million decrease in capacity revenues. The $12.8 million increase in revenues from customers inside Mississippi Power’s service territory was due to a $6.9 million increase in recoverable fuel costs and a $5.9 million increase due to higher demands by customers and a base rate increase that was effective January 2009.

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Wholesale Revenues – Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(14.5)	(64.7)	$(33.5)	(65.9)

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

In the second quarter 2009, wholesale revenues from affiliates were $8.0 million compared to $22.5 million for the corresponding period in 2008. The decrease was primarily due to a $14.9 million decrease in energy revenues, of which $11.6 million was associated with decreased sales and $3.3 million was associated with lower prices. Capacity revenues increased $0.4 million.

For year-to-date 2009, wholesale revenues from affiliates were $17.4 million compared to $50.9 million for the corresponding period in 2008. The decrease was primarily due to a $34.1 million decrease in energy revenues, of which $29.9 million was associated with decreased sales and $4.2 million was associated with lower prices. Capacity revenues increased $0.6 million.

Other Revenues

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(0.8)	(16.6)	$(1.2)	(14.1)

In the second quarter 2009, other revenues were $3.9 million compared to $4.7 million for the corresponding period in 2008. The decrease was primarily due to a $0.6 million transmission contract buyout that occurred in 2008.

For year-to-date 2009, other revenues were $7.3 million compared to $8.5 million for the corresponding period in 2008. The decrease was primarily due to a $0.6 million decrease in transmission revenues and a $0.6 million transmission contract buyout that occurred in 2008.

Fuel and Purchased Power Expenses

	Second Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Second Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(13.1	)		(9.4	)	$	(23.2	)		(8.6	)
Purchased power – non-affiliates		(2.5	)		(47.1	)		(2.0	)		(25.7	)
Purchased power – affiliates		4.1			23.5			(0.1	)		(0.2	)
Total fuel and purchased power expenses	$	(11.5	)				$	(25.3	)

In the second quarter 2009, total fuel and purchased power expenses were $150.3 million compared to $161.8 million for the corresponding period in 2008. This decrease was primarily due to a $19.4 million decrease in the cost of fuel and purchased power, partially offset by a $7.9 million increase in total KWHs generated and purchased.

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For year-to-date 2009, total fuel and purchased power expenses were $294.9 million compared to $320.1 million for the corresponding period in 2008. This decrease was primarily due to a $13.5 million decrease in total KWHs generated and purchased and an $11.7 million decrease in the cost of fuel and purchased power.

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

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

	Second Quarter		Second Quarter		Percent			Year-to-Date		Year-to-Date		Percent
Average Cost	2009		2008		Change			2009		2008		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		4.21		4.03		4.5			4.32		3.97		8.8
Purchased power		3.36		6.77		(50.4	)		3.62		5.94		(39.1	)

In the second quarter 2009, fuel expense was $125.8 million compared to $138.9 million for the corresponding period for 2008. The decrease was primarily due to a 13.2% decrease in generation from Mississippi Power facilities resulting from purchased power available at lower cost and lower energy sales, partially offset by a 4.5% increase in the price of fuel primarily due to an increase in coal prices.

For year-to-date 2009, fuel expense was $245.8 million compared to $269.0 million for the corresponding period for 2008. The decrease was primarily due to a 16.0% decrease in generation from Mississippi Power facilities resulting from purchased power available at lower cost and lower energy sales, partially offset by an 8.8% increase in the price of fuel primarily due to an increase in coal prices.

Non-Affiliates

In the second quarter 2009, purchased power expense from non-affiliates was $2.9 million compared to $5.4 million for the corresponding period in 2008. The decrease was primarily the result of a 74.4% decrease in the average cost of purchased power per KWH, partially offset by a 107.0% increase in KWH volume purchased. The decrease in prices was due to a lower marginal cost of fuel while the increase in volume was a result of lower cost opportunity purchases.

For year-to-date 2009, purchased power expense from non-affiliates was $5.7 million compared to $7.7 million for the corresponding period in 2008. The decrease was primarily the result of a 61.1% decrease in the average cost of purchased power per KWH, partially offset by a 91.2% increase in KWH volume purchased. The decrease in prices was due to a lower marginal cost of fuel while the increase in volume was a result of lower cost opportunity purchases.

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

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Affiliates

In the second quarter 2009, purchased power from affiliates was $21.6 million compared to $17.5 million for the corresponding period in 2008. The increase was primarily due to a 118.1% increase in KWH volume purchased, partially offset by a 43.4% decrease in the average cost of purchased power per KWH.

For year-to-date 2009, purchased power from affiliates was $43.4 million compared to $43.5 million for the corresponding period in 2008. The decrease was primarily due to a 32.2% decrease in the average cost of purchased power per KWH, partially offset by a 47.2% increase in KWH volume 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.

Other Operations and Maintenance Expenses

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(1.8)	(2.8)	$(6.7)	(5.3)

In the second quarter 2009, other operations and maintenance expenses were $61.6 million compared to $63.4 million for the corresponding period in 2008. The decrease in other operations and maintenance expenses was primarily due to generation construction screening expenses of $2.5 million incurred in the second quarter 2008 which were originally expensed and subsequently reclassified in the fourth quarter 2008 to a regulatory asset upon the FERC’s acceptance of the wholesale rate filing in October 2008. Also contributing to the change was a $2.2 million decrease in transmission and distribution expenses as a result of the timing of projects and overall reductions in spending and a $0.3 million decrease in customer accounting, service, and sales expenses. These decreases were partially offset by a $2.6 million increase in production expenses primarily due to outage work in 2009 and a $0.6 million increase in administrative and general expenses primarily due to an increase in property insurance expense.

For year-to-date 2009, other operations and maintenance expenses were $121.4 million compared to $128.1 million for the corresponding period in 2008. The decrease in other operations and maintenance expenses was primarily due to generation construction screening expenses of $4.2 million incurred in the first six months of 2008 which were originally expensed and subsequently reclassified in the fourth quarter 2008 to a regulatory asset upon the FERC’s acceptance of the wholesale rate filing in October 2008. Also contributing to the change was a $4.0 million decrease in transmission and distribution expenses as a result of timing of projects and overall reductions in spending and a $1.5 million decrease in generation-related environmental expenses. These decreases were partially offset by a $3.0 million increase in production expenses primarily due to outage work in 2009.

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

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Interest Expense, Net of Amounts Capitalized

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$1.9	42.4	$2.2	24.7

In the second quarter 2009, interest expense, net of amounts capitalized was $6.3 million compared to $4.4 million for the corresponding period in 2008. The increase was primarily due to a $1.6 million increase in interest expense associated with the issuance of long-term debt in November 2008 and March 2009.

For year-to-date 2009, interest expense, net of amounts capitalized was $11.0 million compared to $8.8 million for the corresponding period in 2008. The increase was primarily due to a $2.3 million increase in interest expense associated with the issuance of long-term debt in November 2008 and March 2009.

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

Other Income (Expense), Net

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(1.8)	(60.8)	$(1.7)	(38.8)

In the second quarter 2009, other income (expense), net was $1.1 million compared to $2.9 million for the corresponding period in 2008. The decrease was primarily due to a $1.8 million decrease due to mark-to-market losses on energy-related derivative positions.

For year-to-date 2009, other income (expense), net was $2.8 million compared to $4.5 million for the corresponding period in 2008. The decrease was primarily due to a $1.9 million decrease in income due to mark-to-market losses on energy-related derivative positions and amounts collected from customers for construction of substation projects which had a tax effect of $0.8 million, partially offset by a $0.7 million increase in customer projects.

Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(0.1)	(0.6)	$0.7	3.1

In the second quarter 2009, income taxes were $13.6 million compared to $13.7 million for the corresponding period in 2008. The change was primarily due to a $0.6 million decrease resulting from the decrease in pre-tax income, partially offset by an increase in income taxes resulting from fully amortizing a regulatory liability through income taxes in 2008 of $0.4 million pursuant to a December 2007 regulatory accounting order from the Mississippi PSC.

For year-to-date 2009, income taxes were $24.1 million compared to $23.4 million for the corresponding period in 2008. The change was primarily due to a $0.4 million increase resulting from the increase in pre-tax income and a $0.7 million increase resulting from fully amortizing a regulatory liability through income taxes in 2008 pursuant to a December 2007 regulatory accounting order from the Mississippi PSC.

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

FUTURE EARNINGS POTENTIAL

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

Water Quality

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

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Global Climate Issues” of Mississippi Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have

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

FERC and Mississippi PSC Matters

Market-Based Rate Authority

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

Retail Regulatory Matters

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Environmental Compliance Overview Plan” in Item 8 of the Form 10-K for information on Mississippi Power’s annual environmental filing with the Mississippi PSC. On February 3, 2009, Mississippi Power submitted its 2009 ECO Plan notice which proposed an increase in annual revenue for Mississippi Power of approximately $1.5 million. On June 19, 2009, the Mississippi PSC approved the ECO Plan with the new rates effective in June 2009.

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MISSISSIPPI POWER COMPANY
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Performance Evaluation Plan

The Mississippi Public Utilities Staff, pursuant to the Mississippi PSC’s 2004 order approving the current PEP, is reviewing the PEP to determine if any modifications should be made. On March 2, 2009, concurrent with this review, the annual PEP evaluation filing for 2009 was suspended. Mississippi Power anticipates that, as a result of this required review, changes to the PEP will be made. Annual evaluations will resume for 2010 under the current PEP or a revised PEP. Mississippi Power does not anticipate that the suspension of the PEP filing for 2009 will have a material impact on 2009 earnings. On August 3, 2009, the Mississippi Public Utilities Staff and Mississippi Power filed a joint report with the Mississippi PSC proposing several changes to the PEP and asking the Mississippi PSC to rule on the recommendations by the end of September 2009. While the final outcome is not known, it is likely that any modifications made to the PEP will result in a lower performance incentive under the PEP and therefore smaller and/or less frequent rate changes in the future. See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Performance Evaluation Plan” in Item 8 of the Form 10-K for additional information regarding Mississippi Power’s base rates.

On March 16, 2009, Mississippi Power submitted its annual PEP lookback filing for 2008, which recommended no surcharge or refund. The ultimate 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 Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. The Mississippi PSC approved the retail fuel cost recovery factor on March 3, 2009, with the new rates effective in March 2009. The retail fuel cost recovery factor will result in an annual increase in an amount equal to 10.3% of total 2008 retail revenues based on ten months of recovery under the new rate. At June 30, 2009, the amount of under recovered retail fuel costs included in the balance sheet was $16.3 million compared to $36.0 million at December 31, 2008. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and Market Base (MB) fuel cost recovery factor. Effective January 1, 2009, the wholesale MRA fuel rate increased resulting in an annual increase in an amount equal to 13.9% of total 2008 MRA revenues. Effective February 1, 2009, the wholesale MB fuel rate increased resulting in an annual increase in an amount equal to 16.7% of total 2008 MB revenues. At June 30, 2009, the amount of under recovered wholesale MRA and MB fuel costs included in the balance sheet was $3.5 million and $1.4 million compared to $15.4 million and $3.7 million, respectively, at December 31, 2008. Mississippi Power’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this increase to the billing factor will have no significant effect on Mississippi Power’s revenues or net income, but will increase annual cash flow.

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

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Integrated Coal Gasification Combined Cycle

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

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

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

On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures. The Mississippi PSC’s determination of prudence for Mississippi Power’s pre-construction costs is scheduled to occur by May 2010. As of June 30, 2009, Mississippi Power had spent a total of $56.4 million associated with Mississippi Power’s generation resource planning, evaluation, and screening activities, including regulatory filing costs. Costs incurred for the six months ended June 30, 2009 totaled $14.1 million as compared to $13.0 million for the six months ended June 30, 2008. Of the total $56.4 million, $51.9 million was deferred in other regulatory assets, $3.7 million was related to land purchases capitalized, and $0.8 million was previously expensed.

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

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

The ultimate outcome of these matters cannot now be determined.

107

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

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives, which could have a significant impact on the future cash flow and net income of Mississippi Power. Mississippi Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be between approximately $11 million and $14 million. Southern Company and its subsidiaries have also filed an application under the ARRA for a grant, of which approximately $40 million relates to Mississippi Power, to be used primarily for the advanced metering infrastructure program and other transmission and distribution automation and modernization projects. Mississippi Power continues to assess the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Other Matters

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

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

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, and Plant Daniel Operating Lease.

108

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

New Accounting Standards

Variable Interest Entities

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Mississippi Power’s financial condition remained stable at June 30, 2009. Throughout the turmoil in the financial markets, Mississippi Power has maintained adequate access to capital without drawing on any of its committed bank credit arrangements used to support its commercial paper borrowings and variable rate pollution control revenue bonds. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. Market rates for committed credit have increased, and Mississippi Power has been and expects to continue to be subject to higher costs as its existing facilities are replaced or renewed. Total committed credit fees at Mississippi Power currently average less than¹/4 of 1% per year. Mississippi Power’s interest cost for short-term debt has decreased as market short-term interest rates have declined from 2008 levels. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. Mississippi Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. See “Sources of Capital” and “Financing Activities” herein for additional information.

Mississippi Power’s investments in pension trust funds stabilized during the second quarter 2009. Mississippi Power expects that the earliest that cash may have to be contributed to the pension trust fund is 2012 and such contribution could be significant; however, projections of the amount vary significantly depending on interpretations of and decisions related to federal legislation passed during 2008 as well as other key variables including future trust fund performance and cannot be determined at this time.

Net cash used for operating activities totaled $23.8 million for the first six months of 2009, compared to $1.0 million provided from operating activities for the corresponding period in 2008. The $24.8 million increase in cash used for operating activities was primarily due to a decrease in Energy Cost Management clause (ECM) revenues resulting from a decrease in the ECM rate effective in March 2009 and cash payments related to losses on settled hedges in 2009. Also contributing to the increase in cash used for operating activities were increases in both coal prices and inventory. These increases in cash used for operating activities were partially offset by an increase in cash resulting from higher fuel rates effective in March 2009. The $5.6 million increase in net cash used for investing activities was primarily due to grant proceeds of $7.3 million received in the second quarter 2008. The $13.7 million increase in net cash provided from financing activities was primarily due to a $9.8 million increase in borrowings from commercial paper in 2009 and an increase in the issuance of long-term debt in the first quarter 2009 of $45 million compared to the corresponding period in 2008, partially offset by cash outflows resulting from $40 million of long-term senior notes that matured on March 9, 2009.

109

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

Significant balance sheet changes for the first six months of 2009 include a decrease in under recovered regulatory clause revenues of $33.8 million primarily due to lower fuel costs and the implementation of a higher fuel cost recovery factor in 2009. Fossil fuel inventory increased $44.0 million primarily due to increases in coal inventory and emissions allowances of $26.3 million and $19.9 million, respectively. Other regulatory assets increased $12.9 million primarily due to mark-to-market losses on forward gas contracts and total property, plant, and equipment increased by $22.5 million. Securities due within one year decreased by $40.0 million due to senior notes maturing during the first quarter 2009. Notes payable increased by $20.5 million primarily due to an increase in commercial paper borrowings. Accrued taxes, other decreased by $21.8 million primarily due to 2008 property tax payments of $39.8 million in the first quarter 2009 offset by an $18.4 million accrual for 2009. Long-term debt increased by $124 million primarily due to the issuance of senior notes in the first quarter 2009.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $1.3 million will be required through June 30, 2010 for maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

Mississippi Power’s current liabilities sometimes exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Mississippi Power had at June 30, 2009 approximately $5.0 million of cash and cash equivalents and $148.5 million of unused committed credit arrangements with banks. These credit arrangements provide liquidity support to Mississippi Power’s commercial paper borrowings and $40 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Of the unused credit facilities, $58.5 million expire in 2009 and $90 million expire in 2010 while $43.5 million of these credit arrangements contain provisions allowing two-year term loans executable at expiration and $15 million contain provisions allowing one-year term loans executable at expiration. Mississippi Power expects to renew its credit facilities, as needed, prior to expiration.

110

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

See Note 6 to the financial statements of Mississippi Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Mississippi Power may meet short-term cash needs 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 June 30, 2009, Mississippi Power had $45.4 million of commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

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

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At June 30, 2009, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $12 million. At June 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $211 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

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

Due to cost-based rate regulation, Mississippi Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power has no material change in market risk exposure when compared with the December 31, 2008 reporting period.

111

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

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

	Second Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(76.0	)	$	(52.0	)
Contracts realized or settled		16.8			25.8
Current period changes(a)		(0.6	)		(33.6	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(59.8	)	$	(59.8	)

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

The changes in the fair value positions of the energy-related derivative contracts for the three months and six months ended June 30, 2009 were an increase of $16 million and a decrease of $8 million, respectively, substantially all of which is due to natural gas positions. These changes are attributable to the prices of natural gas positions. At June 30, 2009, Mississippi Power had a net hedge volume of 30 million mmBtu with a weighted average contract cost approximately $2.02 per mmBtu above market prices, compared to 30 million mmBtu at March 31, 2009 with a weighted average contract cost approximately $2.60 per mmBtu above market prices and compared to 29 million mmBtu at December 31, 2008 with a weighted average contract cost approximately $1.89 per mmBtu above market prices. The majority of the natural gas hedge settlements are recovered through the energy cost management clause.

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

	June 30, 2009			December 31, 2008
	(in millions)
Regulatory hedges	$	(59.6	)	$	(52.0	)
Cash flow hedges		—			—
Not designated		(0.2	)		—
Total fair value	$	(59.8	)	$	(52.0	)

Energy-related derivative contracts which are designated as regulatory hedges relate to Mississippi Power’s fuel hedging program where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost management clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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

112

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

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

	June 30, 2009
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(59.8	)		(36.4	)		(21.1	)		(2.3	)
Level 3		—			—			—			—
Fair value of contracts outstanding at end of period	$	(59.8	)	$	(36.4	)	$	(21.1	)	$	(2.3	)

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

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

Financing Activities

During the first quarter 2009, Mississippi Power issued $125 million of Series 2009A 5.55% Senior Notes due March 1, 2019. The proceeds were used to repay at maturity Mississippi Power’s $40 million aggregate principal amount of Series F Floating Rate Senior Notes due March 9, 2009, to repay a portion of short-term indebtedness, and for general corporate purposes, including Mississippi Power’s continuous construction program.

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

113

SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES

114

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	90,877		$	170,907		$	185,489		$	251,376
Wholesale revenues, affiliates		137,718			143,893			273,002			277,386
Other revenues		2,003			1,784			3,624			3,354
Total operating revenues		230,598			316,584			462,115			532,116
Operating Expenses:
Fuel		51,731			76,341			117,512			112,388
Purchased power, non-affiliates		24,778			34,312			46,260			50,868
Purchased power, affiliates		13,860			64,963			29,062			115,671
Other operations and maintenance		34,966			35,654			67,939			70,685
Depreciation and amortization		27,198			20,943			51,537			40,930
Taxes other than income taxes		4,789			4,639			9,548			9,181
Total operating expenses		157,322			236,852			321,858			399,723
Operating Income		73,276			79,732			140,257			132,393
Other Income and (Expense):
Interest expense, net of amounts capitalized		(21,592	)		(19,894	)		(43,151	)		(39,251	)
Other income (expense), net		(23	)		34			(234	)		12,614
Total other income and (expense)		(21,615	)		(19,860	)		(43,385	)		(26,637	)
Earnings Before Income Taxes		51,661			59,872			96,872			105,756
Income taxes		20,607			24,452			37,902			41,361
Net Income	$	31,054		$	35,420		$	58,970		$	64,395

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2009		2008			2009		2008
	(in thousands)					(in thousands)
Net Income	$	31,054	$	35,420		$	58,970	$	64,395
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(4,886), $302, and $(7,831), respectively		—		(7,554	)		466		(12,116	)
Reclassification adjustment for amounts included in net income, net of tax of $931, $1,348, $1,866, and $2,690, respectively		1,435		2,084			2,875		4,158
Total other comprehensive income (loss)		1,435		(5,470	)		3,341		(7,958	)
Comprehensive Income	$	32,489	$	29,950		$	62,311	$	56,437

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

115

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months
	Ended June 30,
	2009			2008
	(in thousands)
Operating Activities:
Net income	$	58,970		$	64,395
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		57,610			48,844
Deferred income taxes		24,442			23,614
Deferred revenues		(21,070	)		(27,234	)
Mark-to-market adjustments		991			8,534
Accumulated billings on construction contract		24,565			39,437
Accumulated costs on construction contract		(31,113	)		(46,014	)
Gain on sale of property		(24	)		(6,015	)
Other, net		3,858			1,553
Changes in certain current assets and liabilities —
-Receivables		(50,026	)		(114,097	)
-Fossil fuel stock		1,389			(2,776	)
-Materials and supplies		(1,826	)		(1,049	)
-Prepaid income taxes		5,510			(12,034	)
-Other current assets		1,493			(494	)
-Accounts payable		(15,940	)		59,180
-Accrued taxes		8,642			7,829
-Accrued interest		27			(25	)
-Other current liabilities		(158	)		2,326
Net cash provided from operating activities		67,340			45,974
Investing Activities:
Property additions		(7,835	)		(40,444	)
Sale of property		52			5,001
Change in construction payables		(1,624	)		(7,222	)
Payments pursuant to long-term service agreements		(15,450	)		(14,094	)
Other investing activities		(184	)		(726	)
Net cash used for investing activities		(25,041	)		(57,485	)
Financing Activities:
Increase in notes payable, net		—			56,625
Proceeds — Capital contributions		1,680			2,135
Payment of common stock dividends		(53,050	)		(47,250	)
Net cash provided from (used for) financing activities		(51,370	)		11,510
Net Change in Cash and Cash Equivalents		(9,071	)		(1	)
Cash and Cash Equivalents at Beginning of Period		37,894			5
Cash and Cash Equivalents at End of Period	$	28,823		$	4
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $163 and $7,000 capitalized for 2009 and 2008, respectively)	$	37,508		$	31,941
Income taxes (net of refunds)	$	7,725		$	29,866

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

116

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

	At June 30,		At December 31,
Assets	2009		2008
	(in thousands)
Current Assets:
Cash and cash equivalents	$	28,823	$	37,894
Receivables —
Customer accounts receivable		39,530		23,640
Other accounts receivable		1,514		2,162
Affiliated companies		70,605		33,401
Fossil fuel stock, at average cost		15,521		17,801
Materials and supplies, at average cost		28,353		26,527
Prepaid service agreements — current		38,992		26,304
Prepaid income taxes		15,962		18,066
Other prepaid expenses		1,259		2,756
Assets from risk management activities		12,884		10,799
Other current assets		4,507		4,532
Total current assets		257,950		203,882
Property, Plant, and Equipment:
In service		2,880,403		2,847,757
Less accumulated provision for depreciation		401,164		351,193
Plant in service, net of depreciation		2,479,239		2,496,564
Construction work in progress		10,449		8,775
Total property, plant, and equipment		2,489,688		2,505,339
Deferred Charges and Other Assets:
Prepaid long-term service agreements		50,600		81,542
Other deferred charges and assets — affiliated		3,684		3,827
Other deferred charges and assets — non-affiliated		18,690		18,550
Total deferred charges and other assets		72,974		103,919
Total Assets	$	2,820,612	$	2,813,140

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

117

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

	At June 30,			At December 31,
Liabilities and Stockholder’s Equity	2009			2008
	(in thousands)
Current Liabilities:
Accounts payable —
Affiliated	$	49,256		$	61,527
Other		6,502			11,278
Accrued taxes —
Accrued income taxes		5,471			88
Other accrued taxes		10,303			2,343
Accrued interest		29,943			29,916
Liabilities from risk management activities		8,982			7,452
Billings in excess of cost on construction contract		5,359			11,907
Deferred capacity revenues — current affiliated		6,099			1,206
Other current liabilities		67			223
Total current liabilities		121,982			125,940
Long-term Debt		1,297,480			1,297,353
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		234,652			209,960
Deferred capacity revenues — affiliated		8,515			32,211
Other deferred credits and liabilities — affiliated		6,150			6,667
Other deferred credits and liabilities — non-affiliated		2,532			2,648
Total deferred credits and other liabilities		251,849			251,486
Total Liabilities		1,671,311			1,674,779
Common Stockholder’s Equity:
Common stock, par value $.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		863,788			862,109
Retained earnings		308,229			302,309
Accumulated other comprehensive loss		(22,716	)		(26,057	)
Total common stockholder’s equity		1,149,301			1,138,361
Total Liabilities and Stockholder’s Equity	$	2,820,612		$	2,813,140

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

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

OVERVIEW

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

To evaluate operating results and to ensure Southern Power’s ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators. These indicators include peak season equivalent forced outage rate (EFOR), return on invested capital (ROIC), and net income. EFOR defines the hours during peak demand times when Southern Power’s generating units are not available due to forced outages (the lower the better). ROIC is focused on earning a return on all invested capital that meets or exceeds Southern Power’s weighted average cost of capital. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Southern Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(4.3)	(12.3)	$(5.4)	(8.4)

Southern Power’s net income for the second quarter 2009 was $31.1 million compared to $35.4 million for the corresponding period in 2008. The decrease was primarily due to increased depreciation associated with an increase in depreciation rates and Plant Franklin Unit 3 being placed into commercial operation in June 2008 and a reduction of capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008. These unfavorable impacts were partially offset by increased revenues associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased generation from Southern Power’s combined cycle units due to lower natural gas prices.

Southern Power’s net income for year-to-date 2009 was $59.0 million compared to $64.4 million for the corresponding period in 2008. The decrease was primarily due to a gain on the sale of an undeveloped tract of land in Orange County, Florida to the Orlando Utilities Commission (OUC) and the receipt of a fee for participating in an asset auction that were both recognized in income in the first quarter 2008. Additionally, the decrease was due to increased depreciation associated with an increase in depreciation rates, increased depreciation associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008, and a reduction of capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008. These unfavorable impacts were partially offset by increased revenues associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased generation from Southern Power’s combined cycle units due to lower natural gas prices.

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Wholesale Revenues–Non-Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(80.0)	(46.8)	$(65.9)	(26.2)

Wholesale energy sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market cost of available energy compared to the cost of Southern Power’s energy. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

Wholesale revenues from non-affiliates for the second quarter 2009 were $90.9 million compared to $170.9 million for the corresponding period in 2008. The decrease was due to lower natural gas prices reducing energy revenues by $88.2 million. The decrease was partially offset by increased capacity revenues primarily from the operation of Plant Franklin Unit 3 of $2.0 million and mark-to-market gains of $0.5 million recognized in 2009. Southern Power recognized mark-to-market losses of $5.7 million in 2008.

Wholesale revenues from non-affiliates for year-to-date 2009 were $185.5 million compared to $251.4 million for the corresponding period in 2008. The decrease was due to lower natural gas prices reducing energy revenues by $112.8 million. The decrease was partially offset by increased capacity revenues primarily from the operation of Plant Franklin Unit 3 of $8.0 million and mark-to-market gains of $4.9 million recognized in 2009. Southern Power recognized mark-to-market losses of $34.0 million in 2008.

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

Wholesale Revenues–Affiliates

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(6.2)	(4.3)	$(4.4)	(1.6)

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 second quarter 2009 were $137.7 million compared to $143.9 million for the corresponding period in 2008. The decrease was due to a decrease of $104.9 million due to lower natural gas prices. The decrease was substantially offset by increased energy revenues of $98.7 million due to increased power sales under the IIC. The increase in sales under the IIC was primarily due to lower natural gas prices.

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Wholesale revenues from affiliates for year-to-date 2009 were $273.0 million compared to $277.4 million for the corresponding period in 2008. The decrease was due to a decrease of $125.8 million due to lower natural gas prices. The decrease was substantially offset by increased energy revenues of $121.4 million due to increased power sales under the IIC. The increase in sales under the IIC was primarily due to lower natural gas prices.

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

Fuel and Purchased Power Expenses

	Second Quarter 2009						Year-to-Date 2009
	vs.						vs.
	Second Quarter 2008						Year-to-Date 2008
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(24.6	)		(32.2	)	$	5.1			4.6
Purchased power – non-affiliates		(9.5	)		(27.8	)		(4.6	)		(9.1	)
Purchased power – affiliates		(51.1	)		(78.7	)		(86.6	)		(74.9	)
Total fuel and purchased power expenses	$	(85.2	)				$	(86.1	)

Southern Power PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel costs is accompanied by an increase or decrease in related fuel revenues and does not have a significant impact on net income.

In the second quarter 2009, total fuel and purchased power expenses were $90.4 million compared to $175.6 million for the corresponding period in 2008. Fuel expense decreased $117.3 million due to a 33.7% decrease in the average cost of natural gas. This decrease was substantially offset by increases of $77.2 million due to a 101% increase in generation associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased generation at Southern Power’s other combined cycle units due to lower natural gas prices. Additionally, $16.5 million in mark-to-market gains were recognized in the second quarter 2008 compared to $1.0 million in mark-to-market gains recognized in the second quarter 2009. Purchased power expense decreased $30.6 million due to increased generation at Southern Power’s combined cycle units during the second quarter 2009 due to lower natural gas prices. Additionally, purchased power expense decreased $26.8 million due to a decrease in the average cost of purchased power and a decrease of $3.2 million in mark-to-market losses recognized.

For year-to-date 2009, total fuel and purchased power expenses were $192.8 million compared to $278.9 million for the corresponding period in 2008. Fuel expense increased $152.4 million due to a 135.6% increase in generation associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased generation at Southern Power’s other combined cycle units due to lower natural gas prices. Additionally, $28.4 million in mark-to-market gains were recognized in 2008 compared to $2.9 million in mark-to-market losses recognized in 2009. These increases were substantially offset by decreases of $178.6 million due to a 44.4% decrease in the average cost of natural gas. Purchased power expense decreased $60.9 million due to increased generation at Southern Power’s combined cycle units due to lower natural gas prices. Additionally, purchased power expense decreased $30.3 million due to a decrease in the average cost of purchased power.

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In the second quarter 2009, fuel expense was $51.7 million compared to $76.3 million for the corresponding period in 2008. Fuel expense decreased $117.3 million due to a 33.7% decrease in the average cost of natural gas. This decrease was substantially offset by increases of $77.2 million due to a 101% increase in generation associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased generation at Southern Power’s other combined cycle units due to lower natural gas prices. Additionally, $16.5 million in mark-to-market gains were recognized in the second quarter 2008 compared to $1.0 million in mark-to- market gains recognized in the second quarter 2009.

For year-to-date 2009, fuel expense was $117.5 million compared to $112.4 million for the corresponding period in 2008. Fuel expense increased $152.4 million due to a 135.6% increase in generation associated with Plant Franklin Unit 3 being placed into commercial operation in June 2008 and increased generation at Southern Power’s other combined cycle units due to lower natural gas prices. Additionally, $28.4 million in mark-to-market gains were recognized in 2008 compared to $2.9 million in mark-to-market losses recognized in 2009. These increases were substantially offset by decreases of $178.6 million due to a 44.4% decrease in the average cost of natural gas.

In the second quarter 2009, purchased power expense was $38.6 million compared to $99.3 million for the corresponding period in 2008. Purchased power expense decreased $30.6 million due to increased generation at Southern Power’s combined cycle units during the second quarter 2009 due to lower natural gas prices. Additionally, purchased power expense decreased $26.8 million due to a decrease in the average cost of purchased power and a decrease of $3.2 million in mark-to-market losses recognized.

For year-to-date 2009, purchased power expense was $75.3 million compared to $166.5 million for the corresponding period in 2008. Purchased power expense decreased $60.9 million due to increased generation at Southern Power’s combined cycle units due to lower natural gas prices. Additionally, purchased power expense decreased $30.3 million due to a decrease in the average cost of purchased power.

Other Operations and Maintenance Expenses

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(0.7)	(1.9)	$(2.8)	(3.9)

In the second quarter 2009, the change in other operations and maintenance expenses from the second quarter 2008 was not material.

For year-to-date 2009, other operations and maintenance expenses were $67.9 million compared to $70.7 million for the corresponding period in 2008. The decrease was primarily due to transmission tariff penalties of $3.6 million recognized in 2008, partially offset by an increase in plant maintenance activities of $0.8 million.

Depreciation and Amortization

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$6.3	29.9	$10.6	25.9

In the second quarter 2009, depreciation and amortization was $27.2 million compared to $20.9 million for the corresponding period in 2008. For year-to-date 2009, depreciation and amortization was $51.5 million compared to $40.9 million for the corresponding period in 2008. These increases were due to the completion of Plant Franklin Unit 3 in June 2008 and higher depreciation rates implemented in January 2009. See Note 1

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to the financial statements of Southern Power under “Depreciation” in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under “Southern Power Depreciation Policy” herein for additional information.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$1.7	8.5	$3.9	9.9

In the second quarter 2009, interest expense, net of amounts capitalized was $21.6 million compared to $19.9 million for the corresponding period in 2008. For year-to-date 2009, interest expense, net of amounts capitalized was $43.2 million compared to $39.3 million for the corresponding period in 2008. These increases were primarily due to a decrease in capitalized interest as a result of the completion of Plant Franklin Unit 3 in June 2008, partially offset by a decrease in short-term borrowing levels.

Other Income (Expense), Net

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(0.1)	N/M	$(12.8)	(101.9)

N/M — Not meaningful

In the second quarter 2009, the change in other income (expense), net from the second quarter 2008 was not material.

For year-to-date 2009, other income (expense), net was $(0.2) million as compared to $12.6 million for the corresponding period in 2008. The change was primarily due to a $6.0 million gain on the sale of an undeveloped tract of land in Orange County, Florida to the OUC and a $6.4 million fee received for participating in an asset auction that were both recognized in the first quarter 2008. Southern Power was not the successful bidder in the auction.

Income Taxes

Second Quarter 2009 vs. Second Quarter 2008		Year-to-Date 2009 vs. Year-to-Date 2008
(change in millions)	(% change)	(change in millions)	(% change)
$(3.9)	(15.7)	$(3.5)	(8.4)

In the second quarter 2009, income taxes were $20.6 million compared to $24.5 million for the corresponding period in 2008. For year-to-date 2009, income taxes were $37.9 million compared to $41.4 million for the corresponding period in 2008. These decreases were primarily due to lower pre-tax earnings.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power’s future earnings potential. The level of Southern Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power’s competitive wholesale business. These factors include Southern Power’s ability to achieve sales growth while containing costs. Another major factor is federal regulatory policy, which may impact Southern Power’s level of participation in the market. The level of future earnings also depends on numerous factors including regulatory matters (such as those related to affiliate contracts), creditworthiness of customers, total generating capacity available in the Southeast, the successful remarketing of capacity as current contracts expire, and Southern Power’s ability to execute its

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acquisition strategy. Recent recessionary conditions have negatively impacted capacity revenues. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Environmental Matters

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

Global Climate Issues

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters - Global Climate Issues” of Southern Power in Item 7 of the Form 10-K for information regarding the potential for legislation and regulation addressing greenhouse gas emissions. On April 17, 2009, the EPA released a proposed finding that certain greenhouse gas emissions from new motor vehicles endanger public health and welfare due to climate change. The ultimate outcome of the proposed endangerment finding cannot be determined at this time and will depend on additional regulatory action and potential legal challenges. However, regulatory decisions that may follow from such a finding could have implications for both new and existing stationary sources, such as power plants. In addition, federal legislative proposals that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards, and energy efficiency standards continue to be actively considered in Congress, and the reduction of greenhouse gas emissions has been identified as a high priority by the current Administration. On June 26, 2009, the American Clean Energy and Security Act of 2009, which would impose mandatory greenhouse gas restrictions through implementation of a cap and trade program, a renewable energy standard, and other measures, was passed by the House of Representatives and is expected to now be considered by the Senate. The ultimate outcome of these matters cannot be determined at this time; however, mandatory restrictions on Southern Power’s greenhouse gas emissions, or requirements relating to renewable energy or energy efficiency, could result in significant additional compliance costs that could affect future results of operations, cash flows, and financial condition.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC Matters – Market-Based Rate Authority” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “FERC Matters – Market-Based Rate Authority” in Item 8 of the Form 10-K for information regarding market-based rate authority. In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff.

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The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction in 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas. The original generation dominance proceeding initiated by the FERC in December 2004 remains pending before the FERC. The ultimate outcome of this matter cannot be determined at this time.

Legislation

On February 17, 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA include an extension of bonus depreciation and multiple renewable energy incentives. Southern Power estimates the cash flow reduction to 2009 tax payments as a result of the bonus depreciation provisions of the ARRA to be immaterial. Southern Power is currently assessing the other financial implications of the ARRA. The ultimate impact cannot be determined at this time.

Construction Projects

Cleveland County Units 1-4

In December 2008, Southern Power announced that it will build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to go into commercial operation in 2012. Costs incurred through June 30, 2009 were $7.5 million. The total estimated construction cost is expected to be between $350 million and $400 million.

Power Sales Agreements

Southern Power has entered into PPAs with North Carolina Electric Membership Corporation (NCEMC) and North Carolina Municipal Power Agency No. 1 (NCMPA1) for a portion of the generating capacity from the Cleveland County plant that will begin in 2012 and expire in 2036 and 2031, respectively. NCEMC will purchase 180 MWs of capacity that will be supported by one unit at the plant and will purchase capacity from a second unit at the plant that will increase to 180 MWs over a seven-year phase-in period. NCMPA1 will purchase 180 MWs from a third unit at the plant. The NCEMC PPAs were approved by the Rural Utilities Service on March 6, 2009.

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Potential Acquisition

On April 2, 2009, Southern Power signed an agreement to acquire all of the outstanding general and limited partnership interests of Hartwell Energy Limited Partnership (Hartwell). Hartwell owns a dual-fueled generating plant near Hartwell, Georgia with installed capacity of 318 MWs. The plant consists of two combustion turbine natural gas generating units with oil back-up. The entire output of the plant is sold under a PPA with Oglethorpe Power Corporation (Oglethorpe) through May 31, 2019.

The acquisition was subject to a right of first refusal held by Oglethorpe, certain regulatory approvals, and other conditions. On July 31, 2009, Oglethorpe exercised its right of first refusal and will purchase the ownership interests of Hartwell.

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS- ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power’s critical accounting policies and estimates related to Revenue Recognition, Normal Sale and Non-Derivative Transactions, Cash Flow Hedge Transactions, Mark-to-Market Transactions, Percentage of Completion, Asset Impairments, Acquisition Accounting, Contingent Obligations, and Depreciation.

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New Accounting Standards

Variable Interest Entities

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power’s financial condition remained stable at June 30, 2009. Throughout the turmoil in the financial markets, Southern Power has maintained cash balances to cover the majority of its capital needs and has had limited need to issue commercial paper or draw on committed credit arrangements. Southern Power has successfully accessed the commercial paper market as needed during 2009. There was no commercial paper outstanding at June 30, 2009. 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. Market rates for committed credit have increased, and Southern Power may be subject to higher costs as its existing facilities are replaced or renewed. The current facility expires in 2012 and the commitment fee is less than¹/₈ of 1%. Southern Power experienced no material counterparty credit losses as a result of the turmoil in the financial markets. The ultimate impact on future financing costs as a result of financial turmoil cannot be determined at this time. See “Sources of Capital” herein for additional information.

Net cash provided from operating activities totaled $67.3 million for the first six months of 2009, compared to $46.0 million for the corresponding period in 2008. The $21.3 million increase in cash provided from operating activities was due primarily to the timing of income tax payments. Net cash used for investing activities totaled $25.0 million for the first six months of 2009, compared to $57.5 million for the corresponding period in 2008. The $32.5 million decrease was primarily due to reduced property additions as Plant Franklin Unit 3 was completed in June 2008. Net cash used in financing activities totaled $51.4 million for the first six months of 2009 compared to net cash provided of $11.5 million for the corresponding period in 2008. The change was primarily due to a reduction in short-term borrowings in 2009 and an increase in dividends paid to Southern Company.

Significant asset changes in the balance sheet for the first six months of 2009 include increases in accounts receivable balances due to seasonality and a reduction in prepaid service agreements due to completion of scheduled outages.

Significant liability and stockholder’s equity changes in the balance sheet for the first six months of 2009 include a reduction in affiliate accounts payable due to timing of payments to SCS, a reduction in billings in excess of cost due to the timing of scheduled payments, and costs incurred with regard to the OUC construction contract whereby Southern Power is providing engineering, procurement, and construction services to build a combined cycle unit for OUC. The OUC contract is not expected to have any positive or negative impacts to Southern Power over the term of the contract as Southern Power is not anticipating any profit or loss from this transaction at this time. Additionally, deferred capacity revenues decreased due to levelization.

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

Sources of Capital

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

Southern Power’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source, as well as cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at June 30, 2009 $400 million in committed credit arrangements with banks that will expire in 2012. Proceeds from these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for Southern Power’s commercial paper program. See Note 6 to the financial statements of Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information.

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

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

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At June 30, 2009, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $356 million. At June 30, 2009, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $850 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

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

be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Power’s ability to access capital markets, particularly the short-term debt market.

In addition, through the acquisition of Plant Rowan, Southern Power assumed a PPA with Duke Energy that could require collateral, but not accelerated payment, in the event of a downgrade to Southern Power’s credit rating to below BBB- or Baa3. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.

Market Price Risk

Southern Power is exposed to market risks, including changes in interest rates and certain energy-related commodity prices. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power’s policies in areas such as counterparty exposure and hedging practices. It is Southern Power’s policy that derivatives be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis.

Southern Power’s market risk exposure relative to interest rate changes has not changed materially compared with the December 31, 2008 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

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

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

	Second Quarter			Year-to-Date
	2009			2009
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	3.3		$	3.4
Contracts realized or settled		0.1			0.2
Current period changes(a)		(0.2	)		(0.4	)
Contracts outstanding at the end of the period, assets (liabilities), net	$	3.2		$	3.2

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

The decreases in the fair value positions of the energy-related derivative contracts for the three months and six months ended June 30, 2009 were $0.1 million and $0.2 million, respectively, which is due to both volume and price changes in power and natural gas positions. The net hedge position at June 30, 2009 and respective period end dates that support these changes are as follows:

	June 30,			March 31,			December 31,
	2009			2009			2008
Power (net sold)
MWHs (in millions)		1.1			0.7			0.3
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	2.29		$	3.71		$	(2.29	)
Natural gas (net purchase)
Commodity – million mmBtu		2.9			3.5			1.9
Location basis – million mmBtu		2.0			2.0			—
Commodity – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	0.24		$	(0.27	)	$	(2.16	)
Location basis – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	(0.05	)	$	0.06		$	—

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

	June 30, 2009		December 31, 2008
	(in millions)
Cash flow hedges	$	–	$	(0.8	)
Not designated		3.2		4.2
Total fair value	$	3.2	$	3.4

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

Total net unrealized pre-tax losses recognized in the statements of income for the six months ended June 30, 2009 for energy-related derivative contracts that are not hedges was $1 million and will continue to be marked to market until the settlement date. For the three months ended June 30, 2009, the net unrealized loss was immaterial. For the three and six months ended June 30, 2008, the total net unrealized gains (losses) recognized in the statements of income were $5 million and $(9) million, respectively. See Note (E) to the Condensed Financial Statements herein for further details of these gains (losses).

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

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

	June 30, 2009
	Fair Value Measurements
	Total		Maturity
	Fair Value		Year 1		Years 2&3			Years 4&5
	(in millions)
Level 1	$	—	$	—	$	—		$	—
Level 2		3.2		3.9		(0.7	)		—
Level 3		—		—		—			—
Fair value of contracts outstanding at end of period	$	3.2	$	3.9	$	(0.7	)	$	—

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

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

Financing Activities

Southern Power did not issue or redeem any long-term securities during the six months ended June 30, 2009.

131

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
Alabama Power	A, B, C, E, F, G
Georgia Power	A, B, C, E, F, G
Gulf Power	A, B, C, E, F, G
Mississippi Power	A, B, C, E, F, G
Southern Power	A, B, C, E, G

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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, 2008 have been derived from the audited financial statements of each registrant. In the opinion of each registrant’s management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2009 and 2008. In addition, all subsequent events have been evaluated for disclosure through the issuance of the financial statements on August 6, 2009. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the audited financial statements included in the Form 10-K and, with respect to Southern Company, the subsequently revised audited financial statements included in the Current Report on Form 8-K filed May 8, 2009 (the Form 8-K), and details which have not changed significantly in amount or composition since the filing of the Form 10-K and, for Southern Company, the Form 8-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K and, for Southern Company, the Form 8-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented do not necessarily indicate operating results for the entire year.
	Reclassifications
	Certain prior period data presented in the financial statements have been reclassified to conform to the current year presentation. For comparative purposes, each registrant’s statement of income for the three and six months ended June 30, 2008 were modified within the operating expenses section to combine the line items “Other operations” and “Maintenance” into a single line item entitled “Other operations and maintenance.” The balance sheets at December 31, 2008 of Southern Company, Alabama Power, and Georgia Power were modified to present a separate line item for “Other regulatory assets, current” previously included in “Other current assets.” In addition, Georgia Power’s balance sheet was modified to present a separate line item for “Joint owner accounts receivable” previously included in “Other accounts and notes receivable” and to reflect a new line item “Liabilities from risk management activities” previously included in “Other current liabilities.” To conform to the current year presentation, Southern Power’s balance sheet at December 31, 2008 reflects a separate line item for the amount of “Deferred capacity revenues—current affiliated” previously included in “Accounts payable—affiliated.” Southern Company modified its statements of cash flows within the operating activities section for the prior period by collapsing the line item “Derivative fair value adjustments” into “Other, net.” Also, within the investing activities section, the line items “Investment in unconsolidated subsidiaries” and “Hurricane Katrina capital grant proceeds” previously shown as separate line items are now included in “Other investing activities” while “Change in construction payables” previously included in “Other investing activities” is shown separately in the current presentation. Within the operating activities of Georgia Power’s statements of cash flows, “Deferred revenues” and “Deferred expenses” previously included in “Other, net” in

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

the prior period are now shown as separate line items. Also, within the financing activities of the same statement, the line item “Capital leases” was collapsed into “Other financing activities.” Mississippi Power’s balance sheet was modified to combine the line item “Prepaid income taxes” with “Other current assets.” Mississippi Power’s statement of cash flows for the six months ended June 30, 2008 was modified within the operating activities to present separately from “Other, net” the amount of “Generation construction screening expense.”

These reclassifications had no effect on total assets, net income, cash flows, or earnings per share.

Effective January 1, 2009, Southern Company and its subsidiaries adopted retrospectively a new accounting standard for noncontrolling interests. In connection with the adoption, Southern Company evaluated the requirements with respect to the presentation of preferred and preference stock of subsidiaries. Based on the accounting guidance, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are considered to be “noncontrolling interests” and are separately presented as a component of “Stockholders’ Equity” on Southern Company’s consolidated balance sheets. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary’s board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as “Redeemable Preferred Stock of Subsidiaries” in a manner consistent with temporary equity. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision that would allow the holders to elect a majority of such subsidiary’s board.

In addition, the new accounting standard for noncontrolling interests requires that preferred and preference dividends of subsidiaries previously presented within Southern Company’s consolidated statements of income as a component of “Other Income and (Expense)” be presented as a deduction from “Consolidated Net Income” to arrive at “Consolidated Net Income After Dividends on Preferred and Preference Stock.” In Southern Company’s consolidated statements of cash flows, the preferred and preference dividends previously classified in operating activities are now classified in financing activities.

Southern Power Depreciation Policy

See Note 1 to the financial statements of Southern Power under “Depreciation” in Item 8 of the Form 10-K for information regarding Southern Power’s depreciation policy. Southern Power revised its depreciation rates in 2009. The change in estimate is due to revised useful life assumptions for certain components of plant in service. The expected 2009 impact to Southern Power is an increase in depreciation expense of $8.2 million and a reduction in net income of $5.0 million.

Nuclear Relicensing

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

Leveraged Leases

On June 29, 2009, Southern Company terminated two international leveraged lease investments for a net gain, after termination of related debt, of $25.5 million. The termination is reflected on the statements of cash flows and the statements of income on line items “Proceeds from property sales,” “Gain on disposition of lease termination,” and “Loss on extinguishment of debt.”

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(B)	CONTINGENCIES AND REGULATORY MATTERS
	See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
	General Litigation Matters
	Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, each registrant’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 claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such pending or potential litigation against the registrants and any of their subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on such registrant’s financial statements.
	Mirant Matters
	Mirant was an energy company with businesses that included independent power projects and energy trading and risk management companies in the United States and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership, and Mirant became an independent corporate entity.
	Mirant Bankruptcy
	In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization in December 2005, and Mirant announced that this plan became effective in January 2006. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).
	Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed under “Guarantees” in Note 7 to the financial statements of Southern Company in Item 8 of the Form 10-K and with various lawsuits related to Mirant discussed below. Also, Southern Company has joint and several liability with Mirant regarding the joint consolidated federal income tax returns through 2001, as discussed in Note 5 to the financial statements of Southern Company in Item 8 of the Form 10-K. In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid approximately $39 million in additional tax and interest related to Mirant tax items and filed a claim in Mirant’s bankruptcy case for that amount. To date, Southern Company has received from the IRS approximately $38 million in refunds related to Mirant. Southern Company believes it has a right to recoup the $39 million tax payment owed by Mirant from such tax refunds. As a result, Southern Company intends to retain the tax refunds and reduce its claim against Mirant for the payment of Mirant taxes by the amount of such refunds. MC Asset Recovery, LLC, a special purpose subsidiary of Reorganized Mirant (MC Asset Recovery), has objected to and sought to equitably subordinate the Southern Company tax claim in its fraudulent transfer litigation against Southern Company. Southern Company’s proofs of claim filed in the Mirant bankruptcy survive the settlement of the MC Asset Recovery litigation. Southern Company has reserved the remaining amount with respect to its Mirant tax claim.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these guarantees, lawsuits, and additional IRS assessments. As a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. As part of a complaint filed against Southern Company in June 2005 and amended thereafter, Mirant and The Official Committee of Unsecured Creditors of Mirant Corporation (Unsecured Creditors’ Committee) objected to and sought equitable subordination of Southern Company’s claims, and Mirant moved to reject the separation agreements entered into in connection with the spin-off. MC Asset Recovery has been substituted as plaintiff in the complaint. If Southern Company’s claims for indemnification with respect to these, or any additional future payments, are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. The final outcome of this matter cannot now be determined.

MC Asset Recovery Litigation

In June 2005, Mirant, as a debtor in possession, and the Unsecured Creditors’ Committee filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005, February 2006, May 2006, and March 2007.

In December 2005, the Bankruptcy Court entered an order authorizing the transfer of this proceeding, along with certain other actions, to MC Asset Recovery. Under that order, Reorganized Mirant was obligated to fund up to $20 million in professional fees in connection with the lawsuits, as well as certain additional amounts. Any net recoveries from these lawsuits would be distributed to, and shared equally by, certain unsecured creditors and the original equity holders. In January 2006, the U.S. District Court for the Northern District of Texas substituted MC Asset Recovery as plaintiff.

The complaint, as amended in March 2007, alleged that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The alleged fraudulent transfers and illegal dividends included without limitation: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80% interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer plaintiff asserted was valued at over $200 million. The complaint also sought to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleged that Southern Company was liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of recovery and that Southern Company breached its fiduciary duties to Mirant and its creditors, caused Mirant to breach its fiduciary duties to creditors, and aided and abetted breaches of fiduciary duties by Mirant’s directors and officers. The complaint also sought recoveries under the theories of restitution and unjust enrichment. In addition, the complaint alleged a claim under the Federal Debt Collection Procedure Act (FDCPA) to avoid certain transfers from Mirant to Southern Company; however, in July 2008, the court ruled that the FDCPA does not apply and that Georgia law should apply instead. The complaint sought monetary damages in excess of $2 billion plus interest, punitive damages, attorneys’ fees, and costs. Finally, the complaint included an objection to Southern Company’s pending claims against Mirant in the Bankruptcy Court (which relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements of Southern Company in Item 8 of the Form 10-K) and sought equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the complaint in April 2007.

In January 2006, the U.S. District Court for the Northern District of Texas granted Southern Company’s motion to withdraw this action from the Bankruptcy Court and, in February 2006, granted

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Southern Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia. In May 2006, Southern Company filed a motion for summary judgment seeking entry of judgment against the plaintiff as to all counts of the complaint. In December 2006, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the motion. As a result, certain breach of fiduciary duty claims alleged in earlier versions of the complaint were barred; all other claims in the complaint were allowed to proceed. In August 2008, Southern Company filed a second motion for summary judgment. MC Asset Recovery filed its response to Southern Company’s motion for summary judgment in October 2008. On February 5, 2009, the court denied the summary judgment motion in connection with the fraudulent conveyance and illegal dividend claims concerning certain advance return/loan repayments in 1999, dividends in 1999 and 2000, and transfers in connection with Mirant’s separation from Southern Company. The court granted Southern Company’s motion for summary judgment with respect to certain claims, including claims for unjust enrichment, claims that Southern Company aided and abetted Mirant’s directors’ breach of fiduciary duties to Mirant, and claims that Southern Company used Mirant as an alter ego. In addition, the court granted Southern Company’s motion in connection with the fraudulent transfer and illegal dividend claims concerning certain turbine termination payments.

On March 31, 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve the action. The settlement includes an agreement by Southern Company to pay MC Asset Recovery $202 million and requires MC Asset Recovery to release Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in connection with Mirant’s plan of reorganization, as well as to release all actions against current or former officers and directors of Mirant and Southern Company that have or could have been filed. Pursuant to the settlement, Southern Company recorded a charge in the first quarter 2009 of $202 million, which was paid in the second quarter 2009. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. On June 29, 2009, the case was dismissed with prejudice. Southern Company’s claims in the Mirant bankruptcy remain pending. Southern Company is currently evaluating potential recovery of the settlement payment through various means. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. The ultimate outcome of any such recovery and/or income tax treatment cannot be determined at this time.

Environmental Matters

New Source Review Actions

In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama after Alabama Power was dismissed from the original action. In these lawsuits, the EPA alleged that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including one facility co-owned by Mississippi Power. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the Court denied the motion based on lack of jurisdiction, and the EPA has not refiled. The action against Georgia Power has been administratively closed since the spring of 2001, and the case has not been reopened.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. The consent decree required Alabama Power to pay $100,000 to resolve the government’s claim for a civil penalty and to donate $4.9 million of sulfur dioxide emission allowances to a nonprofit charitable organization. It also formalized specific emissions reductions to be accomplished by Alabama Power, consistent with other Clean Air Act programs that require emissions reductions. In August 2006, the district court in Alabama granted Alabama Power’s motion for summary judgment and entered final judgment in favor of Alabama Power on the EPA’s claims related to all of the remaining plants: Plants Barry, Gaston, Gorgas, and Greene County.

The plaintiffs appealed the district court’s decision to the U.S. Court of Appeals for the Eleventh Circuit, where the appeal was stayed, pending the U.S. Supreme Court’s decision in a similar case against Duke Energy. The Supreme Court issued its decision in the Duke Energy case in April 2007, and in December 2007, the Eleventh Circuit vacated the district court’s decision in the Alabama Power case and remanded the case back to the district court for consideration of the legal issues in light of the Supreme Court’s decision in the Duke Energy case. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, and the ultimate outcome of these matters cannot be determined at this time.

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

Carbon Dioxide Litigation

New York Case

In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005, but no decision has been issued. The ultimate outcome of these matters cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Kivalina Case

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. In June 2008, all defendants filed motions to dismiss this case. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. 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 at June 30, 2009 was $11.1 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a large site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites on the Georgia Hazardous Sites Inventory and CERCLA NPL are anticipated.

By letter dated September 30, 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices from the EPA. Georgia Power, along with other named PRPs, is negotiating with the EPA to address cleanup of the site and reimbursement for past expenditures related to work performed at the site. In addition, on April 30, 2009, two PRPs filed separate actions in the U.S. District Court for the Eastern District of North Carolina against numerous other PRPs, including Georgia Power, seeking contribution from the defendants for expenses incurred by the plaintiffs related to work performed at a portion of the site. The ultimate outcome of these matters will depend upon further environmental assessment and the ultimate number of PRPs and cannot be determined at this time; however, it is not expected to have a material impact on Georgia Power’s financial statements.

Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $67.2 million at June 30, 2009. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates.

In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a potentially responsible party at a site in Texas. The site was owned by an electric transformer

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is now in bankruptcy and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. Amounts expensed related to this work have not been material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan. See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters — Environmental Compliance Overview Plan.”

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 dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could be subject to refund to a cost-based rate level.

In November 2007, the presiding administrative law judge issued an initial decision regarding the methodology to be used in the generation dominance tests. The proceedings are ongoing. The ultimate outcome of this generation dominance proceeding cannot now be determined, but an adverse decision by the FERC in a final order could require the traditional operating companies and Southern Power to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates and could also result in total refunds of up to $19.7 million, plus interest. The potential refunds include $3.9 million for Alabama Power, $5.8 million for Georgia Power, $0.8 million for Gulf Power, $8.4 million for Mississippi Power, and $0.7 million for Southern Power, in each case plus interest. Southern Company and its subsidiaries believe that there is no meritorious basis for an adverse decision in this proceeding and are vigorously defending themselves in this matter.

In June 2007, the FERC issued its final rule in Order No. 697 regarding market-based rate authority. The FERC generally retained its current market-based rate standards. Responding to a number of requests for rehearing, the FERC issued Order No. 697-A on April 21, 2008 and Order No. 697-B on December 12, 2008 and Order No. 697-C on June 16, 2009. These orders largely affirmed and clarified the FERC’s prior revision and codification of the regulations governing market-based rates for public utilities. In accordance with the orders, Southern Company submitted to the FERC an updated market power analysis in September 2008 related to its continued market-based rate authority.

In October 2008, Southern Company filed with the FERC a revised market-based rate (MBR) tariff and a new cost-based rate (CBR) tariff. The revised MBR tariff provides for a “must offer” energy auction whereby Southern Company offers all of its available energy for sale in a day-ahead auction and an hour-ahead auction with reserve prices not to exceed the CBR tariff price, after considering

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Southern Company’s native load requirements, reliability obligations, and sales commitments to third parties. All sales under the energy auction would be at market clearing prices established under the auction rules. The new CBR tariff provides for a cost-based price for wholesale sales of less than a year. On March 5, 2009, the FERC accepted Southern Company’s CBR tariff for filing. On March 25, 2009, the FERC accepted Southern Company’s compliance filing related to the MBR tariff and directed Southern Company to commence the energy auction within 30 days. Southern Company commenced the energy auction on April 23, 2009. The FERC has determined that implementation of the energy auction in accordance with the MBR tariff order adequately mitigates going forward any presumption of market power that Southern Company may have in the Southern Company retail service territory and adjacent market areas.

Intercompany Interchange Contract

Southern Company’s generation fleet in its retail service territory is operated under the IIC as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among the traditional operating companies, Southern Power, and SCS, as agent, under the terms of which the Power Pool is operated, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.

In October 2006, the FERC issued an order accepting a settlement resolving the proceeding subject to Southern Company’s agreement to accept certain modifications to the settlement’s terms and Southern Company notified the FERC that it accepted the modifications. The modifications largely involve functional separation and information restrictions related to marketing activities conducted on behalf of Southern Power. In November 2006, Southern Company filed with the FERC a compliance plan in connection with the order. In April 2007, the FERC approved, with certain modifications, the plan submitted by Southern Company. Implementation of the plan did not have a material impact on Southern Company’s or the traditional operating companies’ financial statements. Southern Power’s annual cost of implementing the compliance plan is approximately $7.0 million. In November 2007, Southern Company notified the FERC that the plan had been implemented. In December 2008, the FERC division of audits issued for public comment its final audit report pertaining to compliance implementation and related matters. No comments challenging the audit report’s findings were submitted. A decision is now pending from the FERC.

Generation Interconnection Agreements

In November 2004, generator company subsidiaries of Tenaska, Inc. (Tenaska), as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, filed complaints at the FERC requesting that the FERC modify the agreements and that those Southern Company subsidiaries refund a total of $19 million previously paid for interconnection facilities, of which $11 million would be refunded by Alabama Power and $8 million by Georgia Power. No other similar complaints are pending with the FERC.

In January 2007, the FERC issued an order granting Tenaska’s requested relief. Although the FERC’s order required the modification of Tenaska’s interconnection agreements, under the provisions of the order, Southern Company determined that no refund was payable to Tenaska. Southern Company requested rehearing asserting that the FERC retroactively applied a new principle to existing interconnection agreements. Tenaska requested rehearing of FERC’s methodology for determining the amount of refunds. The requested rehearings were denied, and Southern Company and Tenaska appealed the orders to the U.S.

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Circuit Court for the District of Columbia. On July 7, 2009, the U.S. Circuit Court affirmed the FERC’s January 2007 order. The ultimate outcome of these matters cannot now be determined.

Right of Way Litigation

Southern Company and certain of its subsidiaries, including Mississippi Power, have been named as defendants in numerous lawsuits brought by landowners since 2001. The plaintiffs’ lawsuits claim that defendants may not use, or sublease to third parties, some or all of the fiber optic communications lines on the rights of way that cross the plaintiffs’ properties and that such actions exceed the easements or other property rights held by defendants. The plaintiffs assert claims for, among other things, trespass and unjust enrichment and seek compensatory and punitive damages and injunctive relief. Management of Southern Company and Mississippi Power believe that they have complied with applicable laws and that the plaintiffs’ claims are without merit.

To date, Mississippi Power has entered into agreements with plaintiffs in approximately 95% of the actions pending against Mississippi Power to clarify its easement rights in the State of Mississippi. These agreements have been approved by the Circuit Courts of Harrison County and Jasper County, Mississippi (First Judicial Circuit), and dismissals of the related cases are in progress. These agreements have not resulted in any material effects on Southern Company’s or Mississippi Power’s financial statements.

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. An adverse outcome in this matter, combined with an adverse outcome against the telecommunications company in one or more of the right of way lawsuits, could result in substantial judgments; however, the final outcome of these matters cannot now be determined.

Nuclear Fuel Disposal Cost Litigation

See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under “Nuclear Fuel Disposal Costs” in Item 8 of the Form 10-K for information regarding the litigation brought by Alabama Power and Georgia Power against the government for breach of contracts related to the disposal of spent nuclear fuel. In July 2007, the U.S. Court of Federal Claims awarded Georgia Power a total of $30 million, based on its ownership interests, and awarded Alabama Power $17.3 million, representing all of the direct costs of the expansion of spent nuclear fuel storage facilities from 1998 through 2004. In August 2007, the government filed a motion for reconsideration, which was denied in November 2007. In January 2008, the government filed a notice of appeal. In February 2008, the government filed a motion to stay the appeal pending the court’s decisions in three other cases already on appeal. In April 2008, the court granted the government’s motion to stay the appeal pending the court’s decisions in three other similar cases already on appeal. Those cases were decided in August 2008. Based on the rulings in those cases, an appeal is expected.

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

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continuing breach of contract. In October 2008, the court denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of June 30, 2009 for either claim. The final outcome of these matters cannot be determined at this time; however, no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.

Income Tax Matters

Leveraged Leases

In 2002, the IRS began the examination of three sale-in-lease-out (SILO) transactions entered into by Southern Company. As a result of this examination, the IRS challenged the deductions related to these transactions. Southern Company disagreed with the IRS’s conclusion, went through all administrative appeals, paid approximately $168 million of the additional tax, and sued the IRS for the refund of such taxes.

During the second quarter 2008, decisions in favor of the IRS were reached in several court cases involving other taxpayers with similar leveraged lease investments. Pursuant to the application of certain accounting standards related to leveraged leases, management is required to assess on a periodic basis the likely outcome of the uncertain tax positions related to the SILO transactions. Based on these accounting standards and management’s review of the recent court decisions, Southern Company recorded an after-tax charge of approximately $67 million in the second quarter 2008.

In December 2008, Southern Company received from the Commissioner of the IRS an invitation to participate in a global settlement initiative related to the SILO transactions. Southern Company accepted the settlement offer on January 8, 2009. Pursuant to the settlement offer, Southern Company recorded an additional after-tax charge in the fourth quarter 2008 of $16 million. Including the charge recorded in the second quarter 2008, total after-tax charges related to settling the SILO litigation amounted to $83 million in 2008. Of the total, approximately $7 million represented interest and $76 million represented non-cash charges related to the reallocation of lease income and will be recognized in income over the remaining term of the affected leases. All additional taxes due as a result of the settlement have now been paid. A final closing agreement with the IRS was signed on June 19, 2009. This agreement ends the dispute with the IRS. Subsequent to the settlement and before the end of the second quarter 2009, Southern Company terminated one of the SILOs and one other international leveraged lease. Of the $76 million non-cash charges related to the IRS settlement, approximately $30 million related to the SILO which was terminated on June 29, 2009.

Georgia State Income Tax Credits

Georgia Power’s 2005 through 2008 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power has also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, these claims could have a significant, and possibly material, positive effect on Southern Company’s and Georgia Power’s net income. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s and Georgia Power’s cash flow. The ultimate outcome of this matter cannot now be determined.

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Retail Rate Matters

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

The economic recession has significantly reduced Georgia Power’s revenues upon which retail rates were set under the Retail Rate Plan. Despite stringent efforts to reduce expenses, current projections indicate Georgia Power’s retail ROE will be less than 10.25% in both 2009 and 2010. However, in lieu of filing to increase customer rates as allowed under the 2007 Retail Rate Plan, on June 29, 2009, Georgia Power filed a request with the Georgia PSC for an accounting order that would allow Georgia Power to amortize approximately $324 million of its regulatory liability related to other cost of removal obligations. Under Georgia Power’s proposal, the regulatory liability would be amortized ratably over the 18-month period from July 1, 2009 through December 31, 2010 as a reduction to operating expenses. Even if the Georgia PSC approves the accounting order request as filed, Georgia Power currently expects its retail ROE will remain below the 10.25% low end of its allowed retail ROE range in 2009 and 2010. The accounting order request is subject to the review and approval of the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects

Integrated Coal Gasification Combined Cycle

On January 16, 2009, Mississippi Power filed for a Certificate of Public Convenience and Necessity with the Mississippi PSC to allow construction of a new electric generating plant located in Kemper County, Mississippi. The plant would utilize an advanced integrated coal gasification combined cycle technology with an output capacity of 582 MWs. The Kemper IGCC will use locally mined lignite (an abundant, lower heating value coal) from a proposed mine adjacent to the plant as fuel. This certificate, if approved by the Mississippi PSC, would authorize Mississippi Power to acquire, construct and operate the Kemper IGCC and related facilities. The Kemper IGCC, subject to federal and state reviews and certain regulatory approvals, is expected to begin commercial operation in May 2014. As part of its filing, Mississippi Power has requested certain rate recovery treatment in accordance with the base load construction legislation.

Mississippi Power filed an application in June 2006 with the DOE for certain tax credits available to projects using clean coal technologies under the Energy Policy Act of 2005. The DOE subsequently certified the Kemper IGCC, and in November 2006 the IRS allocated Internal Revenue Code Section 48A tax credits of $133 million to Mississippi Power. On May 11, 2009, Mississippi Power received notification from the IRS formally certifying these tax credits. The utilization of these credits is dependent upon meeting the certification requirements for the Kemper IGCC, including an in-service date no later than May 2014. Mississippi Power has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for the Section 48A credits.

On February 14, 2008, Mississippi Power also requested that the DOE transfer the remaining funds previously granted to a cancelled Southern Company project that would have been located in Orlando, Florida. On December 12, 2008, an agreement was reached to assign the remaining funds to the Kemper IGCC. The estimated construction cost of the Kemper IGCC is approximately $2.2 billion, which is net of $220 million related to funding to be received from the DOE related to project construction. The remaining DOE funding of $50 million is projected to be used for demonstration over the first few years of operation.

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

Beginning in December 2006, the Mississippi PSC has approved Mississippi Power’s requested accounting treatment to defer the costs associated with Mississippi Power’s generation resource planning, evaluation, and screening activities as a regulatory asset. On December 22, 2008, Mississippi Power requested an amendment to its original order that would allow these costs to continue to be charged to and remain in a regulatory asset until January 1, 2010. On April 6, 2009, Mississippi Power received an accounting order from the Mississippi PSC directing Mississippi Power to continue to charge all generation resource planning, evaluation, and screening costs to regulatory assets including those costs associated with activities to obtain a certificate of public convenience and necessity and costs necessary and prudent to preserve the availability, economic viability, and/or required schedule of the Kemper IGCC generation resource planning, evaluation, and screening activities until the Mississippi PSC makes findings and determination as to the recovery of Mississippi Power’s prudent expenditures. The Mississippi PSC’s determination of prudence for Mississippi Power’s pre-construction costs is scheduled to occur by May 2010. As of June 30, 2009, Mississippi Power had spent a total of $56.4 million associated with Mississippi Power’s generation resource planning, evaluation, and screening activities, including regulatory filing costs. Costs incurred for the six months ended June 30, 2009 totaled $14.1 million as compared to $13.0 million for the six months ended June 30, 2008. Of the total $56.4 million, $51.9 million was deferred in other regulatory assets, $3.7 million was related to land purchases capitalized, and $0.8 million was previously expensed.

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

On June 5, 2009, the Mississippi PSC issued an order initiating an evaluation of the Kemper IGCC and establishing a two-phase procedural schedule. During Phase I, the Mississippi PSC will determine if a need exists for new generating resources. Hearings for Phase I are scheduled for October 2009 with a decision in November 2009. If it is determined a need exists in Phase I, the appropriate resource to fill the need as well as the cost recovery of that resource through application of the State of Mississippi’s Baseload Act of 2008 will be determined during Phase II. Hearings regarding Phase II issues are scheduled for February 2010 with a decision by May 2010.

The ultimate outcome of these matters cannot now be determined.

Nuclear

In August 2006, Southern Nuclear, on behalf of Georgia Power, Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light and Sinking Fund Commissioners (collectively, Owners), filed an application with the NRC for an early site permit relating to two additional nuclear units on the site of Plant Vogtle. See Note 4 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information on these co-owners. On March 31, 2008, Southern Nuclear filed an

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

application with the NRC for a combined construction and operating license (COL) for the new units. If licensed by the NRC, Vogtle Units 3 and 4 are scheduled to be placed in service in 2016 and 2017, respectively.

On April 8, 2008, Georgia Power, acting for itself and as agent for the Owners, and a consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, Consortium) entered into an engineering, procurement, and construction agreement to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 MWs each and related facilities, structures, and improvements at Plant Vogtle (Vogtle 3 and 4 Agreement).

The Vogtle 3 and 4 Agreement is an arrangement whereby the Consortium supplies and constructs the entire facility with the exception of certain items provided by the Owners. Under the terms of the Vogtle 3 and 4 Agreement, the Owners will pay a purchase price that will be subject to certain price escalation and adjustments, adjustments for change orders, and performance bonuses. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Consortium under the Vogtle 3 and 4 Agreement. Georgia Power’s proportionate share, based on its current ownership interest, is 45.7%.

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

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

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

The Owners and the Consortium have agreed to certain liquidated damages upon the Consortium’s failure to comply with the schedule and performance guarantees. The Owners and the Consortium also have agreed to certain bonuses payable to the Consortium for early completion and unit performance. The Consortium’s liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.

The obligations of Westinghouse Electric Company LLC and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement.

In addition, the Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including delays in receipt of the COL or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Owners, Owner insolvency, and certain other events.

Southern Company is also exploring other possibilities relating to additional nuclear power projects, both on its own or in partnership with other utilities. The final outcome of these matters cannot now be determined.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(C)	FAIR VALUE MEASUREMENTS
	As of June 30, 2009, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, are as follows:

	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of June 30, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	23	$	—	$	23
Nuclear decommissioning trusts(a)(b)		594		343		—		937
Cash equivalents and restricted cash		688		—		—		688
Other		7		44		34		85
Total	$	1,289	$	410	$	34	$	1,733
Liabilities:
Energy-related derivatives	$	—	$	325	$	—	$	325
Interest rate derivatives		—		16		—		16
Total	$	—	$	341	$	—	$	341
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Nuclear decommissioning trusts(a)
Domestic equity		244		35		—		279
U.S. Treasury and government agency securities		—		12		—		12
Corporate bonds		7		56		—		63
Mortgage and asset backed securities		—		50		—		50
Other		—		14		—		14
Cash equivalents and restricted cash		191		—		—		191
Total	$	442	$	170	$	—	$	612
Liabilities:
Energy-related derivatives	$	—	$	95	$	—	$	95
Interest rate derivatives		—		9		—		9
Total	$	—	$	104	$	—	$	104
Georgia Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	4
Nuclear decommissioning trusts(a)
Domestic equity		343		1		—		344
U.S. Treasury and government agency securities		—		24		—		24
Municipal bonds		—		15		—		15
Corporate bonds		—		86		—		86
Mortgage and asset backed securities		—		25		—		25
Other		—		25		—		25
Cash equivalents and restricted cash		34		—		—		34
Total	$	377	$	180	$	—	$	557
Liabilities:
Energy-related derivatives	$	—	$	129	$	—	$	129
Interest rate derivatives		—		7		—		7
Total	$	—	$	136	$	—	$	136

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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 June 30, 2009:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Gulf Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents and restricted cash		41		—		—		41
Total	$	41	$	1	$	—	$	42
Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	29
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents		2		—		—		2
Total	$	2	$	2	$	—	$	4
Liabilities:
Energy-related derivatives	$	—	$	62	$	—	$	62
Southern Power
Assets:
Energy-related derivatives	$	—	$	13	$	—	$	13
Cash equivalents		29		—		—		29
Total	$	29	$	13	$	—	$	42
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	10

(a)	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
(b)	For additional detail, see the nuclear decommissioning trusts for Alabama Power and Georgia Power.

Energy-related derivatives and interest rate derivatives primarily consist of over-the-counter contracts. See Note (E) under “Financial Instruments” herein for additional information. The nuclear decommissioning trust funds are invested in a diversified mix of equity and fixed income securities. The cash equivalents and restricted cash consist of securities with original maturities of 90 days or less. “Other” represents marketable securities and certain deferred compensation funds also invested in various marketable securities. All of these financial instruments and investments are valued primarily using the market approach.

Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at June 30, 2009 are as follows:

	Level 3
	Other
	Three Months Ended		Six Months Ended
	June 30, 2009		June 30, 2009
	(in millions)
Beginning balance	$	32	$	35
Total gains (losses) — realized/unrealized:
Included in earnings		—		(3	)
Included in OCI		2		2
Ending balance at June 30, 2009	$	34	$	34

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Unrealized losses of $3 million were included in earnings during the six-month period relating to assets still held at June 30, 2009 and are recorded in “depreciation and amortization.”

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months and six months ended June 30, 2009, the increase in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $45 million and $22 million, respectively, for Alabama Power, $52 million and $27 million, respectively, for Georgia Power, and $97 million and $49 million, respectively, for Southern Company.

As of June 30, 2009, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
Southern Company		$18,916		$19,231
Alabama Power		$6,407		$6,547
Georgia Power		$7,566		$7,626
Gulf Power		$1,119		$1,129
Mississippi Power		$491		$500
Southern Power		$1,297		$1,357

The fair values were based on either closing market prices (Level 1) or closing prices of comparable instruments (Level 2).

(D)	STOCKHOLDERS’ EQUITY
	Earnings per Share
	For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to exercised options and outstanding options under the stock option plan. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for further information on the stock option plan. The effect of the stock options was determined using the treasury stock method. Shares used to compute diluted earnings per share are as follows (in thousands):

	Three Months		Three Months		Six Months		Six Months
	Ended		Ended		Ended		Ended
	June 30, 2009		June 30, 2008		June 30, 2009		June 30, 2008
As reported shares		790,748		769,122		785,303		767,636
Effect of options		1,320		4,018		1,562		4,091
Diluted shares		792,068		773,140		786,865		771,727

The reduction in the effect of options for the three and six months ended June 30, 2009 compared to the corresponding periods in 2008 is primarily due to the anti-dilutive nature of certain stock options outstanding that have exercise prices that exceed the average stock price of Southern Company shares in the three and six months ended June 30, 2009. At June 30, 2009, there were 37.8 million stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options for the three and six months ended June 30, 2009 would have increased by 3.5 million and 3.1 million shares, respectively.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Changes in Stockholders’ Equity

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

				Preferred and
	Common			Preference		Total
	Stockholders’			Stock of		Stockholders’
	Equity			Subsidiaries		Equity
				(in millions)
Balance at December 31, 2008	$	13,276		$	707	$	13,983
Net income after dividends on preferred and preference stock		604			—		604
Other comprehensive income (loss)		16			—		16
Stock issued		559			—		559
Cash dividends on common stock		(670	)		—		(670	)
Other		(1	)		—		(1	)
Balance at June 30, 2009	$	13,784		$	707	$	14,491

				Preferred and
	Common			Preference		Total
	Stockholders’			Stock of		Stockholders’
	Equity			Subsidiaries		Equity
	(in millions)
Balance at December 31, 2007	$	12,385		$	707	$	13,092
Net income after dividends on preferred and preference stock		776			—		776
Other comprehensive income (loss)		(14	)		—		(14	)
Stock issued		260			—		260
Cash dividends on common stock		(630	)		—		(630	)
Other		(7	)		—		(7	)
Balance at June 30, 2008	$	12,770		$	707	$	13,477

(E)	FINANCING
	Bank Credit Arrangements
	At June 30, 2009, unused credit arrangements with banks totaled $4.7 billion, of which $484 million expires during 2009, $965 million expires in 2010, $25 million expires in 2011, and $3.2 billion expires in 2012. These credit arrangements provide liquidity support to the registrants’ commercial paper borrowings and the traditional operating companies’ variable rate pollution control revenue bonds.

150

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

The following table outlines the credit arrangements by company:

					Executable
					Term-Loans				Expires
					One		Two
Company	Total		Unused		Year		Years		2009		2010		2011		2012
	(in millions)
Southern Company	$	950	$	950	$	—	$	—	$	—	$	—	$	—	$	950
Alabama Power		1,260		1,260		361		—		325		145		25		765
Georgia Power		1,675		1,663		—		—		—		555		—		1,120
Gulf Power		220		220		70		—		90		130		—		—
Mississippi Power		149		149		15		44		59		90		—		—
Southern Power		400		400		—		—		—		—		—		400
Other		55		55		55		—		10		45		—		—
Total	$	4,709	$	4,697	$	501	$	44	$	484	$	965	$	25	$	3,235

Subsequent to June 30, 2009, Georgia Power entered into an additional committed credit agreement resulting in an increase of $40 million. The agreement expires in 2010 and contains a two year term-loan option.

See Note 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information.

Changes in Redeemable Preferred Stock of Subsidiaries

The following table presents year-to-date changes in redeemable preferred stock of subsidiaries for Southern Company:

	Redeemable Preferred
	Stock of Subsidiaries
	(in millions)
Balance at December 31, 2008	$	375
Issuance (Redemption) of preferred stock		—
Balance at June 30, 2009	$	375
Balance at December 31, 2007	$	498
Issuance (Redemption) of preferred stock		(125	)
Other		2
Balance at June 30, 2008	$	375

Financial Instruments

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the companies’ policies in areas such as counterparty exposure and risk management practices. The registrants’ policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the statement of financial position as either assets or liabilities.

151

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts. Southern Power also has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

To mitigate residual risks relative to movements in electricity prices, the registrants enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the registrants may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

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

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

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

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

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

At June 30, 2009, the net volume of energy-related derivative contracts for power and natural gas positions for the registrants, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:

	Power						Gas
			Longest		Longest		Net			Longest		Longest
As of June 30,	Net Sold		Hedge		Non-Hedge		Purchased			Hedge		Non-Hedge
2009:	MWH		Date		Date		mmBtu			Date		Date
	(in thousands)						(in millions)
Southern Company		1,442		2009		2010		173	*		2012		2010
Alabama Power		6		—		2009		49			2012		—
Georgia Power		7		—		2009		75			2012		—
Gulf Power		1		—		2009		15			2012		—
Mississippi Power		286		2009		2009		30			2012		2009
Southern Power		1,142		—		2010		5	*		—		2010

* Includes location basis of 2 million mmBtu.

152

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending June 30, 2010 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries also enter into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

For cash flow hedges, the fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time the hedged transactions affect earnings.

At June 30, 2009, Southern Company had a total of $1.2 billion notional amount of interest rate derivatives outstanding with net fair value losses of $16 million as follows:

			Weighted
			Average		Fair Value
	Notional	Variable Rate	Fixed Rate	Hedge Maturity	Gain (Loss)
Registrant	Amount	Received	Paid	Date	June 30, 2009
	(in millions)				(in millions)
Cash flow hedges of existing debt
Alabama Power	$576	SIFMA* Index	2.69%	February 2010	$(9)
Georgia Power	301	SIFMA* Index	2.22%	December 2009	(3)
Georgia Power	300	1-month LIBOR	2.43%	April 2010	(4)
Total	$1,177				$(16)

* Securities Industry and Financial Markets Association Municipal Swap Index (SIFMA)

For the six months ended June 30, 2009, Georgia Power incurred net losses of $16 million (all of which were incurred in the first quarter 2009) upon termination of certain interest rate derivatives at the same time it issued debt. The effective portion of these losses has been deferred in OCI and will be amortized to interest expense over the life of the original interest rate derivative, reflecting the period in which the forecasted hedged transaction affects earnings.

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

The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending June 30, 2010, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.

	Estimated Gain (Loss) to
	be Reclassified for the			Total Deferred
	12 Months Ending			Gains (Losses)
Registrant	June 30, 2010			Amortized Through
	(in millions)
Southern Company	$	(35	)		2037
Alabama Power		(9	)		2035
Georgia Power		(15	)		2037
Gulf Power		(1	)		2018
Southern Power		(10	)		2016

153

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Derivative Financial Statement Presentation and Amounts

At June 30, 2009, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 2009
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives
Other current assets	$	4	$	1	$	2	$	1	$	—
Other deferred charges and assets		5		2		2		—		1
Total derivatives designated as hedging instruments for regulatory purposes	$	9	$	3	$	4	$	1	$	1		N/A
Derivatives not designated as hedging instruments
Energy-related derivatives
Other current assets*	$	14	$	—	$	—	$	—	$	1	$	—
Assets from risk management activities		—		—		—		—		—		13
Total derivatives not designated as hedging instruments	$	14	$	—	$	—	$	—	$	1	$	13
Total asset derivatives	$	23	$	3	$	4	$	1	$	2	$	13

* Southern Company includes Assets from risk management activities in Other current assets.

Liability Derivatives at June 30, 2009
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives
Liabilities from risk management activities	$	241	$	78	$	102	$	24	$	37
Other deferred credits and liabilities		73		17		27		5		24
Total derivatives designated as hedging instruments for regulatory purposes	$	314	$	95	$	129	$	29	$	61		N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives
Liabilities from risk management activities	$	16	$	9	$	7	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives
Liabilities from risk management activities	$	10	$	—	$	—	$	—	$	1	$	9
Other deferred credits and liabilities		1		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	11	$	—	$	—	$	—	$	1	$	10
Total liability derivatives	$	341	$	104	$	136	$	29	$	62	$	10

154

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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

At June 30, 2009, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet	Southern			Alabama			Georgia			Gulf			Mississippi
Location	Company			Power			Power			Power			Power
	(in millions)
Energy-related derivatives
Other regulatory assets, current	$	(241	)	$	(78	)	$	(102	)	$	(24	)	$	(37	)
Other regulatory assets, deferred		(73	)		(17	)		(27	)		(5	)		(24	)
Other current liabilities		4			1			2			—			—
Other regulatory liabilities, current		—			—			—			1			—
Other regulatory liabilities, deferred		5			2			2			—			1
Total energy-related derivative gains (losses)	$	(305	)	$	(92	)	$	(125	)	$	(28	)	$	(60	)

For the three months ended June 30, 2009 and June 30, 2008, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI
Derivatives in Cash Flow	on Derivative						into Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2009			2008				2009			2008
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	—		$	7		Fuel	$	—		$	—
Interest rate derivatives		(4	)		—		Interest expense		(12	)		(6	)
Total	$	(4	)	$	7			$	(12	)	$	(6	)
Alabama Power
Energy-related derivatives	$	—		$	—		Fuel	$	—		$	—
Interest rate derivatives		(2	)		3		Interest expense		(3	)		(2	)
Total	$	(2	)	$	3			$	(3	)	$	(2	)
Georgia Power
Interest rate derivatives total	$	(2	)	$	16		Interest expense	$	(6	)	$	(1	)
Gulf Power
Interest rate derivatives total	$	—		$	1		Interest expense	$	—		$	—
Mississippi Power
Energy-related derivatives total	$	—		$	(1	)	Fuel	$	—		$	—
Southern Power
Energy-related derivatives	$	—		$	(12	)	Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(3	)		(3	)
Total	$	—		$	(12	)		$	(3	)	$	(3	)

155

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the six months ended June 30, 2009 and June 30, 2008, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:

	Gain (Loss)
	Recognized in OCI
Derivatives in Cash Flow	on Derivative						Gain (Loss) Reclassified from Accumulated OCI
Hedging Relationships	(Effective Portion)						into Income (Effective Portion)
							Statements of Income Location	Amount
	2009			2008				2009			2008
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	1		$	(5	)	Fuel	$	—		$	—
Interest rate derivatives		(3	)		(24	)	Interest expense		(22	)		(11	)
Total	$	(2	)	$	(29	)		$	(22	)	$	(11	)
Alabama Power
Energy-related derivatives	$	—		$	(1	)	Fuel	$	—		$	—
Interest rate derivatives		(4	)		(2	)	Interest expense		(6	)		(2	)
Total	$	(4	)	$	(3	)		$	(6	)	$	(2	)
Georgia Power
Interest rate derivatives total	$	1		$	—		Interest expense	$	(11	)	$	(2	)
Gulf Power
Interest rate derivatives total	$	—		$	(3	)	Interest expense	$	(1	)	$	—
Mississippi Power
Energy-related derivatives total	$	—		$	(4	)	Fuel	$	—		$	—
Southern Power
Energy-related derivatives	$	1		$	(20	)	Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(5	)		(7	)
Total	$	1		$	(20	)		$	(5	)	$	(7	)
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
For the three months ended June 30, 2009 and June 30, 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:
Derivatives not Designated							Unrealized Gain (Loss) Recognized in Income
as Hedging Instruments							Statements of Income Location	Amount
								2009			2008
								(in millions)
Southern Company
Energy-related derivatives							Wholesale revenues	$	1		$	(6	)
							Fuel		1			16
							Purchased power		(2	)		(5	)
							Other income (expense), net		—			2
Total								$	—		$	7
Mississippi Power
Energy-related derivatives							Other income (expense), net	$	—		$	2
Southern Power
Energy-related derivatives							Wholesale revenues	$	1		$	(6	)
							Fuel		1			16
							Purchased power		(2	)		(5	)
Total								$	—		$	5

156

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the six months ended June 30, 2009 and June 30, 2008, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

Derivatives not Designated	Unrealized Gain (Loss) Recognized in Income
as Hedging Instruments	Statements of Income Location	Amount
		2009			2008
		(in millions)
Southern Company
Energy-related derivatives	Wholesale revenues	$	5		$	(34	)
	Fuel		(3	)		28
	Purchased power		(3	)		(3	)
	Other income (expense), net		—			2
Total		$	(1	)	$	(7	)
Mississippi Power
Energy-related derivatives	Other income (expense), net	$	—		$	2
Southern Power
Energy-related derivatives	Wholesale revenues	$	5		$	(34	)
	Fuel		(3	)		28
	Purchased power		(3	)		(3	)
Total		$	(1	)	$	(9	)

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2009, the fair value of derivative liabilities with contingent features, by registrant, is as follows:

	Southern		Alabama		Georgia		Gulf		Mississipi		Southern
	Company		Power		Power		Power		Power		Power
	(in millions)
Derivative liabilities	$	68	$	19	$	30	$	5	$	8	$	6

At June 30, 2009, the registrants had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $68 million for each registrant.

Currently, each of the registrants has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade.

157

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(F)	RETIREMENT BENEFITS
	Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2009. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related trusts to the extent required by their respective regulatory commissions.
	See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K. Components of the pension plans’ and postretirement plans’ net periodic costs for the three-month and six-month periods ended June 30, 2009 and 2008 are as follows (in millions):

	Southern			Alabama			Georgia			Gulf			Mississippi
PENSION PLANS	Company			Power			Power			Power			Power
Three Months Ended June 30, 2009
Service cost	$	37		$	9		$	12		$	1		$	1
Interest cost		97			24			36			5			5
Expected return on plan assets		(136	)		(41	)		(54	)		(6	)		(5	)
Net amortization		11			2			4			—			1
Net cost (income)	$	9		$	(6	)	$	(2	)	$	—		$	2
Six Months Ended June 30, 2009
Service cost	$	73		$	17		$	24		$	3		$	3
Interest cost		194			48			73			9			9
Expected return on plan assets		(271	)		(82	)		(108	)		(12	)		(10	)
Net amortization		21			5			8			—			1
Net cost (income)	$	17		$	(12	)	$	(3	)	$	—		$	3
Three Months Ended June 30, 2008
Service cost	$	37		$	8		$	13		$	1		$	1
Interest cost		87			22			34			4			4
Expected return on plan assets		(132	)		(40	)		(53	)		(6	)		(5	)
Net amortization		11			3			3			1			1
Net cost (income)	$	3		$	(7	)	$	(3	)	$	—		$	1
Six Months Ended June 30, 2008
Service cost	$	73		$	17		$	25		$	3		$	3
Interest cost		174			44			67			8			8
Expected return on plan assets		(263	)		(80	)		(106	)		(12	)		(10	)
Net amortization		23			6			8			1			1
Net cost (income)	$	7		$	(13	)	$	(6	)	$	—		$	2

158

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	Southern			Alabama			Georgia			Gulf			Mississippi
POSTRETIREMENT PLANS	Company			Power			Power			Power			Power
Three Months Ended June 30, 2009
Service cost	$	6		$	1		$	3		$	1		$	—
Interest cost		29			8			12			2			2
Expected return on plan assets		(15	)		(6	)		(7	)		(1	)		(1	)
Net amortization		7			2			3			—			—
Net cost (income)	$	27		$	5		$	11		$	2		$	1
Six Months Ended June 30, 2009
Service cost	$	13		$	3		$	5		$	1		$	1
Interest cost		57			15			25			3			3
Expected return on plan assets		(30	)		(12	)		(15	)		(1	)		(1	)
Net amortization		14			4			7			—			—
Net cost (income)	$	54		$	10		$	22		$	3		$	3
Three Months Ended June 30, 2008
Service cost	$	7		$	2		$	3		$	1		$	1
Interest cost		27			8			13			1			2
Expected return on plan assets		(14	)		(6	)		(8	)		(1	)		(1	)
Net amortization		7			2			4			1			—
Net cost (income)	$	27		$	6		$	12		$	2		$	2
Six Months Ended June 30, 2008
Service cost	$	14		$	4		$	5		$	1		$	1
Interest cost		55			15			25			2			3
Expected return on plan assets		(29	)		(11	)		(15	)		(1	)		(1	)
Net amortization		15			4			8			1			—
Net cost (income)	$	55		$	12		$	23		$	3		$	3

(G)	EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS
	Effective Tax Rate
	Southern Company’s effective tax rate was 38.2% for the six months ended June 30, 2009, as compared to 33.3% for the same period in 2008. See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for information on the effective income tax rate. Southern Company’s effective tax rate increased for the six months ended June 30, 2009 primarily due to the $202 million charge recorded for the MC Asset Recovery settlement. Southern Company is currently evaluating potential recovery of the settlement payment through various means. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. See Note (B) herein under “Mirant Matters” for further information regarding this matter. The increase in Southern Company’s effective tax rate was partially offset by the early termination of an international leveraged lease investment, which is not taxable.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Unrecognized Tax Benefits

Changes during 2009 for unrecognized tax benefits are as follows:

	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power
					(in millions)
Unrecognized tax benefits as of December 31, 2008	$	146.4	$	3.0	$	137.1	$	0.3	$	1.8	$	0.5
Tax positions from current periods		29.4		1.0		23.4		0.2		0.7		0.3
Tax positions from prior periods		2.2		1.2		0.2		0.3		0.1		0.4
Reductions due to settlements		—		—		—		—		—		—
Reductions due to expired statute of limitations		—		—		—		—		—		—
Balance as of June 30, 2009	$	178.0	$	5.2	$	160.7	$	0.8	$	2.6	$	1.2

The tax positions increase from the current periods relates primarily to the Georgia state tax credits and other miscellaneous uncertain tax positions. See Note (B) herein under “Income Tax Matters — Georgia State Income Tax Credits” for additional information. The tax positions increase from the prior periods relates to the production activities deduction tax position.

Impact on Southern Company’s effective tax rate, if recognized, is as follows:

					As of		As of
	Georgia		Other		June 30,		December 31,
	Power		Registrants		2009		2008		Change
	(in millions)
Tax positions impacting the effective tax rate	$	158.0	$	17.2	$	175.2	$	143.5	$	31.7
Tax positions not impacting the effective tax rate		2.8		—		2.8		2.9		(0.1	)
Balance of unrecognized tax benefits	$	160.8	$	17.2	$	178.0	$	146.4	$	31.6

The change in the tax position impacting the effective tax rate increase relates primarily to the Georgia state tax credits and the production activities deduction.

Accrued interest for unrecognized tax benefits:

	(in millions)
Interest accrued as of December 31, 2008	$	14.8
Interest accrued year-to-date		4.4
Balance as of June 30, 2009	$	19.2

It is reasonably possible that the amount of the unrecognized benefit with respect to a majority of Southern Company’s and Georgia Power’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The conclusion or settlement of the Georgia state tax credits litigation would substantially reduce the balances. The conclusion or settlement of federal or state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

160

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(H)

SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Southern Power’s revenues from sales to the traditional operating companies were $138 million and $273 million for the three months and six months ended June 30, 2009, respectively, and $144 million and $277 million for the three months and six months ended June 30, 2008, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications, energy-related services, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2009:
Operating revenues	$	3,780	$	230	$	(151	)	$	3,859	$	43		$	(17	)	$	3,885
Segment net income (loss) after dividends on preferred and preference stock of subsidiaries		421		31		—			452		25			1			478
Six Months Ended June 30, 2009:
Operating revenues	$	7,338	$	462	$	(302	)	$	7,498	$	87		$	(34	)	$	7,551
Segment net income (loss) after dividends on preferred and preference stock of subsidiaries		723		59		—			782		(180	)		2			604
Total assets at June 30, 2009	$	46,943	$	2,821	$	(141	)	$	49,623	$	1,359		$	(565	)	$	50,417

	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2008:
Operating revenues	$	4,075	$	316	$	(208	)	$	4,183	$	47		$	(15	)	$	4,215
Segment net income (loss) after dividends on preferred and preference stock of subsidiaries		451		35		—			486		(71	)		2			417
Six Months Ended June 30, 2008:
Operating revenues	$	7,693	$	532	$	(393	)	$	7,832	$	95		$	(29	)	$	7,898
Segment net income (loss) after dividends on preferred and preference stock of subsidiaries		793		64		—			857		(81	)		—			776
Total assets at December 31, 2008	$	44,794	$	2,813	$	(139	)	$	47,468	$	1,407		$	(528	)	$	48,347

Products and Services

	Electric Utilities’ Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2009	$	3,293	$	438	$	128	$	3,859
Three Months Ended June 30, 2008		3,449		591		143		4,183
Six Months Ended June 30, 2009	$	6,358	$	889	$	251	$	7,498
Six Months Ended June 30, 2008		6,455		1,105		272		7,832

161

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.

Item 4. Submission of Matters to a Vote of Security Holders.

Southern Company

Southern Company held its annual meeting of stockholders on May 27, 2009. Each nominee for director of Southern Company received the requisite plurality of votes for election. The vote tabulation was as follows:

Nominees	Shares For		Shares Withheld
Juanita Powell Baranco		557,953,677		16,261,476
Francis S. Blake		541,627,901		32,587,252
Jon A. Boscia		552,156,149		22,059,004
Thomas F. Chapman		559,142,402		15,072,751
H. William Habermeyer, Jr.		555,213,786		19,001,367
Veronica M. Hagen		553,930,534		20,284,619
Warren A. Hood, Jr.		559,164,234		15,050,919
Donald M. James		529,248,958		44,966,195
J. Neal Purcell		555,467,932		18,747,221
David M. Ratcliffe		554,108,638		20,106,515
William G. Smith, Jr.		559,122,012		15,093,141
Gerald J. St. Pé		555,689,823		18,525,330

162

Item 4. Submission of Matters to a Vote of Security Holders. (Continued)

In addition, at the annual meeting, stockholders were asked to vote on a number of proposals which were as follows:

• to ratify the appointment of the independent registered public accounting firm. Vote tabulation for this proposal was 566,494,731 shares for, 4,531,672 shares against, and 3,188,750 shares abstaining. As a result of this vote, the appointment of the independent registered public accounting firm was ratified.

• to amend the Southern Company by-laws. Vote tabulation for this proposal was 428,773,461 shares for, 40,706,371 shares against, and 7,716,817 shares abstaining. Although this proposal received a majority of the votes, its approval was contingent upon the approval of the next proposal to amend the Certificate of Incorporation and, therefore, this proposal to amend the by-laws of Southern Company was not approved.

• to amend Southern Company’s Certificate of Incorporation. Vote tabulation for this proposal was 427,791,284 shares for, 44,157,735 shares against, and 5,247,630 shares abstaining. Since this proposal to amend Southern Company’s Certificate of Incorporation did not receive the requisite votes totaling 66 2/3% of the shares outstanding, it was not approved.

• stockholder proposal on an environmental report. Vote tabulation for this proposal was 43,159,326 shares for, 332,611,437 shares against, and 52,424,690 shares abstaining. As a result of this vote, the stockholder proposal on an environmental report was not approved.

• stockholder proposal on a pension policy. Vote tabulation for this proposal was 162,455,186 shares for, 250,634,517 shares against, and 15,111,301 shares abstaining. As a result of this vote, the stockholder proposal on a pension policy was not approved.

Alabama Power

Alabama Power held its annual meeting of common shareholders and preferred shareholders on April 24, 2009, and the following persons were elected to serve as directors of Alabama Power:

Whit Armstrong	Malcolm Portera
Ralph D. Cook	Robert D. Powers
David J. Cooper, Sr.	David M. Ratcliffe
John D. Johns	C. Dowd Ritter
Patricia M. King	James H. Sanford
James K. Lowder	John C. Webb, IV
Charles D. McCrary	James W. Wright

All 25,475,000 of the shares of Alabama Power’s common stock outstanding on the record date were owned by Southern Company and were voted in favor of the nominees for directors. None of the shares of preferred stock or Class A preferred stock were voted. None of the shares of preference stock were entitled to vote.

163

Item 4. Submission of Matters to a Vote of Security Holders. (Continued)

Georgia Power

Georgia Power held its annual meeting of common stockholders and preferred shareholders on May 14, 2009, and the following persons were elected to serve as directors of Georgia Power:

Robert L. Brown, Jr.	Beverly Daniel Tatum
Anna R. Cablik	D. Gary Thompson
Michael D. Garrett	Richard W. Ussery
Stephen S. Green	W. Jerry Vereen
David M. Ratcliffe	E. Jenner Wood, III
Jimmy C. Tallent

All of the 9,261,500 outstanding shares of Georgia Power’s common stock were owned by Southern Company and were voted in favor of the nominees for directors. None of the shares of Class A preferred stock were voted. None of the shares of preference stock were entitled to vote.

Gulf Power

By written consent, in lieu of the annual meeting of shareholders of Gulf Power, effective June 30, 2009, the following persons were elected to serve as directors of Gulf Power:

C. LeDon Anchors	William A. Pullum
William C. Cramer, Jr.	Winston E. Scott
Fred C. Donovan, Sr.	Susan N. Story

All of the 3,142,717 outstanding shares of Gulf Power’s common stock are owned by Southern Company and were voted in favor of the nominees for directors. None of the shares of preference stock were entitled to vote.

Mississippi Power

Mississippi Power held its annual meeting of common stockholders and preferred shareholders on May 20, 2009, and the following persons were elected to serve as directors of Mississippi Power:

Roy Anderson, III	George A. Schloegel
Aubrey B. Patterson, Jr.	Philip J. Terrell
Christine L. Pickering	Anthony J. Topazi
Martha D. Saunders

All of the 1,121,000 outstanding shares of Mississippi Power’s common stock are owned by Southern Company and were voted in favor of the nominees for directors. None of the shares of preferred stock were voted.

164

Item 4. Submission of Matters to a Vote of Security Holders. (Continued)

Southern Power

By written consent, in lieu of the annual meeting of stockholders of Southern Power, effective May 29, 2009, the following persons were elected to serve as directors of Southern Power:

William P. Bowers	G. Edison Holland, Jr.
Thomas A. Fanning	David M. Ratcliffe

All of the 1,000 outstanding shares of Southern Power’s common stock are owned by Southern Company and were voted in favor of the nominees for directors.

165

Item 6. Exhibits.

(3) Articles of Incorporation and By-Laws
Georgia Power
(c)1	-	By-laws of Georgia Power as amended effective May 20, 2009, and as presently in effect. (Designated in Form 8-K dated May 20, 2009, File No. 1-6468, as Exhibit 3(c)2.)
(4) Instruments Describing Rights of Security Holders, Including Indentures
Southern Company
(a)1	-	Fourth Supplemental Indenture to the Senior Note Indenture dated as of May 19, 2009, providing for the issuance of Southern Company’s Series 2009A 4.15% Senior Notes due May 15, 2014. (Designated in Form 8-K dated May 11, 2009, File No. 1-3526, as Exhibit 4.2.)
Gulf Power
(d)1	-	Fifteenth Supplemental Indenture to Senior Note Indenture dated as of June 26, 2009, providing for the issuance of Gulf Power’s Series 2009A Floating Rate Senior Notes due June 28, 2010. (Designated in Form 8-K dated June 22, 2009, File No. 0-2429, as Exhibit 4.2.)
(24) Power of Attorney and Resolutions
Southern Company
(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 1-3526 as Exhibit 24(a).)
Alabama Power
(b)1	-	Power of Attorney and resolution.
Georgia Power
(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 1-6468 as Exhibit 24(c).)
(c)2	-	Power of Attorney for Ronnie R. Labrato. (Designated in the Form 10-Q for the quarter ended March 31, 2009, File No. 1-6468 as Exhibit 24(c)2.)
Gulf Power
(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 0-2429 as Exhibit 24(d).)
Mississippi Power
(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 001-11229 as Exhibit 24(e).)

166

Southern Power
(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2008, File No. 333-98553 as Exhibit 24(f).)
(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.

167

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.

168

(101) XBRL-Related Documents*

Southern Company
INS	XBRL Instance Document*
SCH	XBRL Taxonomy Extension Schema Document*
PRE	XBRL Taxonomy Presentation Linkbase Document*
LAB	XBRL Taxonomy Label Linkbase Document*
CAL	XBRL Taxonomy Calculation Linkbase Document*
DEF	XBRL Definition Linkbase Document*

* To be filed subsequently by amendment.

169

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, President, and Chief Executive Officer
	(Principal Executive Officer)
By	W. Paul Bowers
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen(Melissa K. Caen, Attorney-in-fact)

Date: August 6, 2009

170

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	Art P. Beattie
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen(Melissa K. Caen, Attorney-in-fact)

Date: August 6, 2009

171

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/ W. Paul Bowers(W. Paul Bowers, Attorney-in-fact)

Date: August 6, 2009

172

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	Philip C. Raymond
	Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ W. Paul Bowers(W. Paul Bowers, Attorney-in-fact)

Date: August 6, 2009

173

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	Anthony J. Topazi
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Frances Turnage
	Vice President, Treasurer, and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ W. Paul Bowers(W. Paul Bowers, Attorney-in-fact)

Date: August 6, 2009

174

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	Ronnie L. Bates
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Michael W. Southern
	Senior Vice President, Treasurer, and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Laura I. Patterson(Laura I. Patterson, Attorney-in-fact)

Date: August 6, 2009

175