e10vq

Second Quarter 2010 vs. Second Quarter 2009

Year-to-Date 2010 vs. Year-to-Date 2009

(change in millions)

(% change)

(change in millions)

(% change)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2010

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 18^th 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 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o

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

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


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

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


	Description of	Shares Outstanding
Registrant	Common Stock	at June 30, 2010
The Southern Company	Par Value $5 Per Share		830,705,693
Alabama Power Company	Par Value $40 Per Share		30,537,500
Georgia Power Company	Without Par Value		9,261,500
Gulf Power Company	Without Par Value		3,642,717
Mississippi Power Company	Without Par Value		1,121,000
Southern Power Company	Par Value $0.01 Per Share		1,000

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

DEFINITIONS


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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

•		current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, 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 and recovery from the recent recession, population and business growth (and declines), and the effects of energy conservation measures;

•		available sources and costs of fuels;

•		effects of inflation;

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

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

•		advances in technology;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	3,571,480		$	3,293,012		$	7,030,400		$	6,357,671
Wholesale revenues		473,229			437,750			1,014,816			889,164
Other electric revenues		142,152			128,403			277,587			251,201
Other revenues		20,558			25,999			41,933			53,435

Total operating revenues		4,207,419			3,885,164			8,364,736			7,551,471

Operating Expenses:
Fuel		1,628,985			1,449,138			3,274,143			2,855,405
Purchased power		128,373			133,188			254,939			240,832
Other operations and maintenance		918,391			831,214			1,826,415			1,702,295
MC Asset Recovery litigation settlement		—			—			—			202,000
Depreciation and amortization		366,553			377,341			709,933			767,099
Taxes other than income taxes		214,066			208,089			426,261			407,969

Total operating expenses		3,256,368			2,998,970			6,491,691			6,175,600

Operating Income		951,051			886,194			1,873,045			1,375,871
Other Income and (Expense):
Allowance for equity funds used during construction		45,300			47,500			94,691			90,112
Interest income		4,807			4,870			9,594			11,778
Leveraged lease income (losses)		669			8,676			6,800			18,117
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		(218,669	)		(232,830	)		(441,151	)		(458,557	)
Other income (expense), net		(9,267	)		(3,001	)		(22,704	)		(16,827	)

Total other income and (expense)		(177,160	)		(165,669	)		(352,770	)		(346,261	)

Earnings Before Income Taxes		773,891			720,525			1,520,275			1,029,610
Income taxes		247,502			225,717			483,183			392,886

Consolidated Net Income		526,389			494,808			1,037,092			636,724
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	$	510,194		$	478,613		$	1,004,702		$	604,334

Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.62		$	0.61		$	1.22		$	0.77
Diluted EPS	$	0.61		$	0.60		$	1.21		$	0.77
Average number of shares of common stock outstanding (in thousands)
Basic		828,363			790,748			825,444			785,303
Diluted		832,622			792,068			828,752			786,865
Cash dividends paid per share of common stock	$	0.4550		$	0.4375		$	0.8925		$	0.8575

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Six Months
	Ended June 30,
	2010			2009
	(in thousands)
Operating Activities:
Consolidated net income	$	1,037,092		$	636,724
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		867,583			895,354
Deferred income taxes		215,318			(13,807	)
Deferred revenues		(47,361	)		(26,295	)
Allowance for equity funds used during construction		(94,691	)		(90,112	)
Leveraged lease income (losses)		(6,800	)		(18,117	)
Gain on disposition of lease termination		—			(26,300	)
Loss on extinguishment of debt		—			17,184
Pension, postretirement, and other employee benefits		(1,252	)		(10,939	)
Stock based compensation expense		23,809			18,956
Hedge settlements		1,530			(16,167	)
Generation construction screening costs		(50,554	)		(14,049	)
Other, net		(57,830	)		42,293
Changes in certain current assets and liabilities —
-Receivables		(255,399	)		74,770
-Fossil fuel stock		72,216			(375,888	)
-Materials and supplies		(6,806	)		(20,079	)
-Other current assets		(88,138	)		(96,394	)
-Accounts payable		(52,091	)		14,711
-Accrued taxes		(79,767	)		(140,308	)
-Accrued compensation		(33,932	)		(298,670	)
-Other current liabilities		(27,965	)		66,748

Net cash provided from operating activities		1,414,962			619,615

Investing Activities:
Property additions		(1,935,716	)		(2,192,959	)
Investment in restricted cash from pollution control revenue bonds		(11	)		(49,478	)
Distribution of restricted cash from pollution control revenue bonds		11,403			59,741
Nuclear decommissioning trust fund purchases		(515,901	)		(823,416	)
Nuclear decommissioning trust fund sales		488,561			788,690
Proceeds from property sales		216			339,903
Cost of removal, net of salvage		(59,989	)		(63,705	)
Change in construction payables		12,934			128,101
Other investing activities		(37,037	)		8,063

Net cash used for investing activities		(2,035,540	)		(1,805,060	)

Financing Activities:
Increase in notes payable, net		244,037			148,090
Proceeds —
Long-term debt issuances		1,146,000			1,785,474
Common stock issuances		341,447			539,088
Redemptions —
Long-term debt		(754,304	)		(199,929	)
Payment of common stock dividends		(735,009	)		(670,226	)
Payment of dividends on preferred and preference stock of subsidiaries		(32,394	)		(32,465	)
Other financing activities		(12,643	)		(19,327	)

Net cash provided from financing activities		197,134			1,550,705

Net Change in Cash and Cash Equivalents		(423,444	)		365,260
Cash and Cash Equivalents at Beginning of Period		689,722			416,581

Cash and Cash Equivalents at End of Period	$	266,278		$	781,841

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $40,130 and $38,594 capitalized for 2010 and 2009, respectively)	$	387,451		$	386,729
Income taxes (net of refunds)	$	285,247		$	468,278

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	266,278		$	689,722
Restricted cash and cash equivalents		31,743			43,135
Receivables —
Customer accounts receivable		1,180,856			953,222
Unbilled revenues		496,265			394,492
Under recovered regulatory clause revenues		193,998			333,459
Other accounts and notes receivable		352,798			374,670
Accumulated provision for uncollectible accounts		(27,152	)		(24,568	)
Fossil fuel stock, at average cost		1,383,220			1,446,984
Materials and supplies, at average cost		805,205			793,847
Vacation pay		145,422			145,049
Prepaid expenses		479,878			508,338
Other regulatory assets, current		175,237			166,549
Other current assets		40,514			48,558

Total current assets		5,524,262			5,873,457

Property, Plant, and Equipment:
In service		55,698,851			53,587,853
Less accumulated depreciation		19,647,708			19,121,271

Plant in service, net of depreciation		36,051,143			34,466,582
Nuclear fuel, at amortized cost		677,178			593,119
Construction work in progress		3,902,173			4,170,596

Total property, plant, and equipment		40,630,494			39,230,297

Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,055,036			1,070,117
Leveraged leases		614,830			610,252
Miscellaneous property and investments		286,142			282,974

Total other property and investments		1,956,008			1,963,343

Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,167,278			1,047,452
Unamortized debt issuance expense		199,558			208,346
Unamortized loss on reacquired debt		255,180			254,936
Deferred under recovered regulatory clause revenues		479,896			373,245
Other regulatory assets, deferred		2,724,931			2,701,910
Other deferred charges and assets		436,883			392,880

Total deferred charges and other assets		5,263,726			4,978,769

Total Assets	$	53,374,490		$	52,045,866

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

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


	At June 30,			At December 31,
Liabilities and Stockholders’ Equity	2010			2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,514,465		$	1,112,705
Notes payable		881,638			639,199
Accounts payable		1,282,523			1,329,448
Customer deposits		335,625			330,582
Accrued taxes —
Accrued income taxes		25,664			13,005
Unrecognized tax benefits		168,400			165,645
Other accrued taxes		319,321			398,384
Accrued interest		220,153			218,188
Accrued vacation pay		181,150			183,911
Accrued compensation		222,301			247,950
Liabilities from risk management activities		124,154			124,648
Other regulatory liabilities, current		297,328			528,147
Other current liabilities		362,728			292,016

Total current liabilities		5,935,450			5,583,828

Long-term Debt		18,134,554			18,131,244

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		6,725,211			6,454,822
Deferred credits related to income taxes		241,669			248,232
Accumulated deferred investment tax credits		457,809			447,650
Employee benefit obligations		2,287,633			2,304,344
Asset retirement obligations		1,233,019			1,201,343
Other cost of removal obligations		1,119,382			1,091,425
Other regulatory liabilities, deferred		233,355			277,932
Other deferred credits and liabilities		391,623			345,888

Total deferred credits and other liabilities		12,689,701			12,371,636

Total Liabilities		36,759,705			36,086,708

Redeemable Preferred Stock of Subsidiaries		374,496			374,496

Stockholders’ Equity:
Common Stockholders’ Equity:
Common stock, par value $5 per share —
Authorized — 1 billion shares
Issued — June 30, 2010: 831,147,821 Shares
— December 31, 2009: 820,151,801 Shares
Treasury — June 30, 2010: 442,128 Shares
— December 31, 2009: 505,116 Shares
Par value		4,155,676			4,100,742
Paid-in capital		3,310,322			2,994,245
Treasury, at cost		(14,923	)		(14,797	)
Retained earnings		8,156,346			7,884,922
Accumulated other comprehensive loss		(74,460	)		(87,778	)

Total Common Stockholders’ Equity		15,532,961			14,877,334
Preferred and Preference Stock of Subsidiaries		707,328			707,328

Total Stockholders’ Equity		16,240,289			15,584,662

Total Liabilities and Stockholders’ Equity	$	53,374,490		$	52,045,866

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Consolidated Net Income	$	526,389		$	494,808		$	1,037,092		$	636,724
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1,267), $(1,744), $(481), and $(982), respectively		(1,982	)		(2,811	)		(781	)		(1,664	)
Reclassification adjustment for amounts included in net income, net of tax of $3,124, $4,630, $6,676, and $8,463, respectively		4,928			7,370			10,574			13,468
Marketable securities:
Change in fair value, net of tax of $472, $1,204, $1,616, and $1,295, respectively		770			2,935			2,796			3,669
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $230, $221, $460, and $443, respectively		364			349			729			699

Total other comprehensive income (loss)		4,080			7,843			13,318			16,172

Dividends on preferred and preference stock of subsidiaries		(16,195	)		(16,195	)		(32,390	)		(32,390	)

Comprehensive Income	$	514,274		$	486,456		$	1,018,020		$	620,506

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income

Southern Company’s second quarter 2010 net income after dividends on preferred and preference stock of subsidiaries was $510.2 million ($0.62 per share) compared to $478.6 million ($0.61 per share) for second quarter 2009. The increase for the second quarter 2010 when compared to the corresponding period in 2009 was primarily the result of increases in revenues as a result of warmer weather, the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC, revenues associated with increases in rates under Alabama Power’s Rate Stabilization and Equalization Plan (Rate RSE) and Rate Certificated New Plant for environmental costs (Rate CNP Environmental) that took effect in January 2010, and increases in sales primarily in the industrial sector. The increase for the second quarter 2010 was partially offset by increases in operations and maintenance expense, a gain in the second quarter 2009 on the early termination of two international leveraged lease investments, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects.

Southern Company’s year-to-date 2010 net income after dividends on preferred and preference stock of subsidiaries was $1.00 billion ($1.22 per share) compared to $604.3 million ($0.77 per share) for year-to-date 2009. The increase for year-to-date 2010 when compared to the corresponding period in 2009 was primarily the result of a litigation settlement agreement with MC Asset Recovery, LLC (MC Asset Recovery) in the first quarter 2009, increases in revenues as a result of warmer weather in the second quarter 2010 and significantly colder weather in the first quarter 2010, the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC, revenues associated with increases in rates under Alabama Power’s Rate RSE and Rate CNP Environmental that took effect in January 2010, and increases in sales primarily in the industrial sector. The increase for year-to-date 2010 was partially offset by increases in operations and maintenance expense, a gain in 2009 on the early termination of two international leveraged lease investments, and an increase in depreciation on additional plant in service related to environmental, distribution, and transmission projects.

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

Retail Revenues

In the second quarter 2010, retail revenues were $3.57 billion compared to $3.29 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $7.03 billion compared to $6.36 billion for the corresponding period in 2009.

Details of the change to retail revenues are as follows:


	Second Quarter					Year-to-Date
	2010					2010
	(in millions)		(% change)			(in millions)		(% change)
Retail – prior year	$	3,293.0				$	6,357.7
Estimated change in —
Rates and pricing		57.9		1.8			134.6		2.1
Sales growth (decline)		30.9		0.9			42.4		0.7
Weather		54.0		1.6			179.8		2.8
Fuel and other cost recovery		135.7		4.1			315.9		5.0

Retail – current year	$	3,571.5		8.4	%	$	7,030.4		10.6	%

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

Revenues attributable to changes in sales increased in the second quarter and for year-to-date 2010 when compared to the corresponding periods in 2009 due to increases in weather-adjusted retail KWH sales of 3.8% and 3.2%, respectively. For the second quarter 2010, weather-adjusted residential KWH sales increased 1.4%, weather-adjusted commercial KWH sales decreased 1.0%, and weather-adjusted industrial KWH sales increased 12.3%. For year-to-date 2010, weather-adjusted residential KWH sales increased 1.5%, weather-adjusted commercial KWH sales decreased 0.7%, and weather-adjusted industrial KWH sales increased 9.7%. Increased demand in the primary metals, chemicals, paper, and transportation sectors were the main contributors to the increases in weather-adjusted industrial KWH sales for the second quarter and year-to-date 2010.

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

Fuel and other cost recovery revenues increased $135.7 million in the second quarter 2010 and $315.9 million for year-to-date 2010 when compared to the corresponding periods in 2009. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

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

Wholesale Revenues

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

In the second quarter 2010, wholesale revenues were $473.2 million compared to $437.8 million for the corresponding period in 2009. The increase was primarily due to energy and capacity revenues under new PPAs that began in January and June 2010 at Southern Power, as well as energy sales not covered by PPAs at Southern Power as a result of more favorable weather in the second quarter 2010 when compared to the corresponding period in 2009. This increase was partially offset by the expiration of long-term unit power sales contracts in May 2010 at Alabama Power and the capacity subject to those contracts being made available for retail service starting in June 2010.

For year-to-date 2010, wholesale revenues were $1.01 billion compared to $889.2 million for the corresponding period in 2009. This increase was primarily due to energy and capacity revenues under new PPAs that began in January and June 2010 at Southern Power, as well as energy sales not covered by PPAs at Southern Power due to more favorable weather year-to-date 2010 when compared to the corresponding period in 2009.

Other Electric Revenues

In the second quarter 2010, other electric revenues were $142.2 million compared to $128.4 million for the corresponding period in 2009. This increase was primarily the result of a $4.6 million increase in transmission revenues, a $4.8 million increase in co-generation revenues due to increased sales volume, a $1.2 million increase in rents from electric property, and a $1.3 million increase in outdoor lighting revenues.

For year-to-date 2010, other electric revenues were $277.6 million compared to $251.2 million for the corresponding period in 2009. This increase was primarily the result of a $10.4 million increase in transmission revenues, a $7.6 million increase in co-generation revenues due to increased sales volume, a $3.6 million increase in rents from electric property, and a $1.4 million increase in outdoor lighting revenues.

Revenues from co-generation and other energy services are generally offset by related expenses and do not affect net income.

Other Revenues

In the second quarter 2010, other revenues were $20.6 million compared to $26.0 million for the corresponding period in 2009. The decrease was primarily the result of a $5.0 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry.

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

For year-to-date 2010, other revenues were $41.9 million compared to $53.4 million for the corresponding period in 2009. The decrease was primarily the result of a $10.7 million decrease in revenues at SouthernLINC Wireless related to lower average revenue per subscriber and fewer subscribers due to increased competition in the industry.

Fuel and Purchased Power Expenses


	Second Quarter 2010				Year-to-Date 2010
	vs.				vs.
	Second Quarter 2009				Year-to-Date 2009
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel*	$	179.8		12.4	$	418.7	14.7
Purchased power		(4.8	)	(3.6)		14.1	5.9

Total fuel and purchased power expenses	$	175.0			$	432.8

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

Fuel and purchased power expenses for the second quarter 2010 were $1.76 billion compared to $1.58 billion for the corresponding period in 2009. The increase was primarily the result of a $92.6 million increase related to total KWHs generated and purchased and an $82.4 million increase in the average cost of fuel and purchased power. The increase in total KWHs generated and purchased resulted primarily from increased generation and higher fossil fuel prices when compared to the corresponding period in 2009.

For year-to-date 2010, fuel and purchased power expenses were $3.53 billion compared to $3.10 billion for the corresponding period in 2009. The increase was primarily the result of a $214.0 million increase related to total KWHs generated and purchased and a $218.8 million increase in the average cost of fuel and purchased power. The increase in total KWHs generated and purchased resulted primarily from increased generation and higher fossil fuel prices when compared to the corresponding period in 2009.

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

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


	Second Quarter		Second Quarter		Percent		Year-to-Date		Year-to-Date		Percent
Average Cost	2010		2009		Change		2010		2009		Change
	(cents per net KWH)						(cents per net KWH)
Fuel		3.50		3.34		4.8		3.55		3.37		5.3
Purchased power		5.91		5.59		5.7		6.50		5.36		21.3

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

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

Other Operations and Maintenance Expenses

In the second quarter 2010, other operations and maintenance expenses were $918.4 million compared to $831.2 million for the corresponding period in 2009. The increase was primarily the result of a $37.7 million increase in fossil, hydro, and nuclear expenses, a $22.0 million increase in commodity and labor costs, a $20.9 million increase in transmission and distribution expenses, a $3.6 million increase in administrative and general expenses, and a $3.0 million increase in customer service and sales expenses.

For year-to-date 2010, other operations and maintenance expenses were $1.83 billion compared to $1.70 billion for the corresponding period in 2009. The increase was primarily the result of a $70.0 million increase in fossil, hydro, and nuclear expenses, a $40.1 million increase in commodity and labor costs, a $28.7 million increase in transmission and distribution expenses, and a $19.1 million increase in affiliated service companies’ expenses. The increase was partially offset by a $29.4 million charge in the first quarter 2009 in connection with a voluntary attrition plan at Georgia Power.

MC Asset Recovery Litigation Settlement

N/M – Not Meaningful

In the first quarter 2009, Southern Company entered into a litigation settlement agreement with MC Asset Recovery which resulted in a charge of $202.0 million and required MC Asset Recovery to release Southern Company and certain other designated avoidance actions assigned to MC Asset Recovery in connection with Mirant’s plan of reorganization, as well as to release all actions against current or former officers and directors of Mirant and Southern Company that have or could have been filed. The settlement has been completed and resolves all claims by MC Asset Recovery against Southern Company. In June 2009, the case was dismissed with prejudice. See Note (B) to the Condensed Financial Statements under “Mirant Matters” herein for additional information.

Depreciation and Amortization

In the second quarter 2010, depreciation and amortization was $366.5 million compared to $377.3 million for the corresponding period in 2009. The decrease was primarily the result of amortization of $54.0 million of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC. The decrease was partially offset by depreciation on additional plant in service related to environmental, transmission, and distribution projects.

For year-to-date 2010, depreciation and amortization was $709.9 million compared to $767.1 million for the corresponding period in 2009. The decrease was primarily the result of amortization of $114.3 million of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC. The decrease was partially offset by depreciation on additional plant in service related to environmental, transmission, and distribution projects.

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

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

Taxes Other Than Income Taxes

In the second quarter 2010, taxes other than income taxes were $214.1 million compared to $208.1 million for the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $426.3 million compared to $408.0 million for the corresponding period in 2009. The second quarter and year-to-date 2010 increases were primarily the result of higher municipal franchise fees resulting from increased retail revenues at Georgia Power and increases in ad valorem taxes at Mississippi Power.

Allowance for Funds Used During Construction

In the second quarter 2010, AFUDC equity was $45.3 million compared to $47.5 million for the corresponding period in 2009. The decrease was primarily due to the completion of environmental projects at Alabama Power and Gulf Power, partially offset by increases in construction work in progress balances related to three new combined cycle units and two new nuclear generating units at Georgia Power.

For year-to-date 2010, AFUDC equity was $94.7 million compared to $90.1 million for the corresponding period in 2009. The increase was primarily due to the increase in construction work in progress balances related to three new combined cycle units and two new nuclear generating units at Georgia Power, partially offset by the completion of environmental projects at Alabama Power and Gulf Power.

Leveraged Lease Income

In the second quarter 2010, leveraged lease income was $0.7 million compared to $8.7 million for the corresponding period in 2009. For year-to-date 2010, leveraged lease income was $6.8 million compared to $18.1 million for the corresponding period in 2009. The second quarter and year-to-date 2010 decreases were primarily related to the early termination of two leveraged lease investments in the second quarter of 2009.

Gain on Disposition of Lease Termination

N/M – Not Meaningful

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

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

Loss on Extinguishment of Debt

N/M – Not Meaningful

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

Interest Expense, Net of Amounts Capitalized

In the second quarter 2010, interest expense, net of amounts capitalized was $218.7 million compared to $232.8 million for the corresponding period in 2009. The decrease was primarily due to an $8.9 million decrease related to lower average interest rates on variable rate debt and a $10.2 million decrease in other interest charges. Partially offsetting this decrease was a $3.9 million increase associated with $420.4 million in additional debt outstanding at June 30, 2010 when compared to June 30, 2009.

For year-to-date 2010, interest expense, net of amounts capitalized was $441.2 million compared to $458.6 million for the corresponding period in 2009. The decrease was primarily related to a $19.2 million decrease related to lower average interest rates on variable rate debt and a $13.8 million decrease in other interest charges. Partially offsetting this decrease was a $17.2 million increase associated with $420.4 million in additional debt outstanding at June 30, 2010 when compared to June 30, 2009.

Income Taxes

In the second quarter 2010, income taxes were $247.5 million compared to $225.7 million for the corresponding period in 2009. This increase was primarily due to higher pre-tax earnings in the second quarter 2010, partially offset by state investment tax credits at Georgia Power and tax benefits associated with the construction of a biomass facility at Southern Power.

For year-to-date 2010, income taxes were $483.2 million compared to $392.9 million for the corresponding period in 2009. This increase was primarily due to higher pre-tax earnings in 2010, partially offset by a decrease in uncertain tax positions at Georgia Power related to state income tax credits that remain subject to litigation, state investment tax credits at Georgia Power, and tax benefits associated with the construction of a biomass facility at Southern Power.

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

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

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company’s future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the traditional operating companies’ ability to maintain a constructive regulatory environment that continues to allow for the recovery of all prudently incurred costs during a time of increasing costs. Other major factors include profitability of the competitive wholesale supply business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service area. In addition, the level of future earnings for the wholesale supply business also depends on numerous factors including creditworthiness of customers, total generating capacity available in the Southeast, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Recessionary conditions have impacted sales for the traditional operating companies and have negatively impacted wholesale capacity revenues at Southern Power. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.

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

Air Quality

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

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Southern Company in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO₂) regulations. On June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO₂, including the establishment of a new short-term standard. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

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

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Southern Company in Item 7 of the Form 10-K for information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, Florida, and Georgia, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including each of the states in Southern Company’s service territory, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

These regulations could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

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

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Southern Company in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, the final regulation could significantly alter the options available for beneficial reuse. The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on the management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Global Climate Issues

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

State PSC Matters

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In recent years, the traditional operating companies have experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and uranium and volatile price swings in natural gas. These higher fuel costs have resulted in total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power of approximately $669 million at June 30, 2010. Alabama Power and Mississippi Power collected all previously under recovered fuel costs and, as of June 30, 2010, had a total over recovered fuel balance of approximately $133 million. At December 31, 2009, total under recovered fuel costs included in the balance sheets of Georgia Power and Gulf Power were approximately $667 million and Alabama Power and Mississippi Power had a total over recovered fuel balance of $229 million. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes to the billing factors will have no significant effect on Southern Company’s revenues or net income but will affect cash flow. The traditional operating companies continuously monitor the under or over recovered fuel cost balances. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE

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

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

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

Retail Rate Matters

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

On August 27, 2009, the Georgia PSC approved an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail return on equity (ROE). In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. Through June 30, 2010, Georgia Power had amortized $155.3 million of the regulatory liability and currently expects to amortize the remaining allowed $108 million by December 31, 2010.

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

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

	§		Continuation of a plus or minus 100 basis point range for ROE.

	§		Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.

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

			The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.

	§		Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.

	§		Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.

	§		Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.

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

Georgia Power expects the Georgia PSC to issue a final order in this matter during December 2010. The final outcome of this matter cannot now be determined.

Legislation

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

Healthcare Reform

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

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

Southern Company. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Southern Company cannot be determined at this time.

Stimulus Funding

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

Income Tax Matters

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 had also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. On April 30, 2010, the Georgia Department of Revenue filed its notice of appeal with the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on net income is expected as a significant portion of any tax benefit is expected to be returned to Georgia Power’s retail customers. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Southern Company’s cash flow. See Note 5 to the financial statements of Southern Company under “Unrecognized Tax Benefits” in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot now be determined.

Construction Projects

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including units at Southern Power, proposed new nuclear units, and a proposed IGCC facility, as well as adding environmental control equipment and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approvals in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See Note 7 to the financial statements of Southern Company under “Construction Program” in Item 8 of the Form 10-K for estimated construction expenditures for the next three years. In addition, see Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Retail Regulatory Matters – Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under “Retail Regulatory Matters – Nuclear Construction” and “Retail Regulatory Matters – Integrated Coal Gasification Combined Cycle” herein for additional information.

Other Matters

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

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

requirements such as opacity and air and water quality standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.

The extent of coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has potential impacts on certain steam plant operations as well as potential significant economic impacts on the affected areas within Southern Company’s service territory. The ultimate impact of this matter cannot be determined at this time.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $1.4 billion for the first six months of 2010, an increase of $795.3 million from the corresponding period in 2009. Significant changes in operating cash flow for the first six months of 2010 compared to the corresponding period in 2009 include an increase in net income as previously discussed and a reduction in fossil fuel stock. Net cash used for investing activities totaled $2.0 billion for the first six months of 2010, an increase of $230.5 million from the corresponding period in 2009. The increase was due to proceeds received on sales of property in 2009. Net cash provided from financing activities totaled $197.1 million for the first six months of 2010, a decrease of $1.4 billion from the corresponding period in 2009, primarily due to fewer issuances of securities in the first six months of 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

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

Significant balance sheet changes for the first six months of 2010 include a decrease in cash and cash equivalents of $423.4 million and an increase of $1.4 billion in total property, plant, and equipment for the installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other significant changes include an increase in equity of $655.6 million.

The market price of Southern Company’s common stock at June 30, 2010 was $33.28 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $18.70 per share, representing a market-to-book ratio of 178%, compared to $33.32, $18.15, and 184%, respectively, at the end of 2009. The dividend for the second quarter 2010 was $0.455 per share compared to $0.4375 per share in the second quarter 2009.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $1.51 billion will be required through June 30, 2011 to fund maturities of long-term debt. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of Southern Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2010, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. The traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those utilized in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company.

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

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

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

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

Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs (which are backed by bank credit facilities), to meet liquidity needs. At June 30, 2010, Southern Company and its subsidiaries had approximately $266 million of cash and cash equivalents and approximately $4.8 billion of unused committed credit arrangements with banks. Of the unused credit arrangements, $519 million expire in 2010, $1.0 billion expire in 2011, and $3.2 billion expire in 2012. Of the credit arrangements expiring in 2010 and 2011, $81 million contain provisions allowing two-year term loans executable at expiration and $907 million contain provisions allowing one-year term loans executable at expiration. At June 30, 2010, approximately $1.8 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. Subsequent to June 30, 2010, Alabama Power renewed a $200 million credit agreement which contains a provision allowing a one-year term loan executable at expiration and extended the expiration date to 2011. In addition, subsequent to June 30, 2010, Georgia Power renewed a $40 million credit agreement which contains a provision allowing a two-year term loan executable at expiration and extended the expiration date to 2011. In addition, subsequent to June 30, 2010, Gulf Power increased it existing lines of credit by $15 million with an expiration of 2011. See Note 6 to the financial statements of Southern Company under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial 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, 2010, the Southern Company system had approximately $879 million of commercial paper borrowings outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

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

Credit Rating Risk

Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, emissions allowances, energy price risk management, and construction of new generation. At June 30, 2010, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $469 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.6 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.

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

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

On June 17, 2010, Moody’s placed the issuer and long-term debt ratings of Southern Company (A3 senior unsecured), Georgia Power (A2 senior unsecured), Gulf Power (A2 senior unsecured), and Mississippi Power (A1 senior unsecured) on review for a possible downgrade. Moody’s also placed the P-1 short-term rating of Southern Company and a financing subsidiary that issues commercial paper for the benefit of Southern Company subsidiaries on review for a possible downgrade. In addition, Moody’s placed the preferred stock and variable rate demand obligation ratings of Georgia Power (Baa1 and VMIG1), Gulf Power (Baa1 and VMIG1), and Mississippi Power (A3 and VMIG1) on review for a possible downgrade. Moody’s announced that it did not expect the review to result in more than a one notch downgrade of any of these ratings. The ultimate outcome of this matter cannot be determined at this time.

Market Price Risk

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

Due to cost-based rate regulation, the traditional operating companies continue to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, during 2010, Southern Power is exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the registrants may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. As such, Southern Company had no material change in market risk exposure for the second quarter 2010 when compared with the December 31, 2009 reporting period.

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


	Second Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(272	)	$	(178	)
Contracts realized or settled		67			111
Current period changes^(a)		3			(135	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(202	)	$	(202	)

(a)

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

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

The change in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2010 was an increase of $70 million and a decrease of $24 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At June 30, 2010, Southern Company had a net hedge volume of 134 million mmBtu with a weighted average contract cost of approximately $1.56 per mmBtu above market prices, compared to 141 million mmBtu (includes location basis of 2 million mmBtu) at March 31, 2010 with a weighted average contract cost of approximately $2.05 per mmBtu above market prices and compared to 145 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.23 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the traditional operating companies’ fuel cost recovery clauses.

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


Asset (Liability) Derivatives	June 30, 2010			December 31, 2009
	(in millions)
Regulatory hedges	$	(201	)	$	(175	)
Cash flow hedges		(1	)		(2	)
Not designated		—			(1	)

Total fair value	$	(202	)	$	(178	)

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

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

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2010 are as follows:


	June 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
				(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(202	)		(116	)		(85	)		(1	)
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(202	)	$	(116	)	$	(85	)	$	(1	)

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.

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

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

Financing Activities

In the first six months of 2010, Georgia Power issued $350 million aggregate principal amount of Series 2010A Floating Rate Senior Notes due March 15, 2013. The proceeds were used to repay at maturity $250 million aggregate principal amount of Series 2008A Floating Rate Senior Notes due March 17, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program. Georgia Power also issued $600 million aggregate principal amount of Series 2010B 5.40% Senior Notes due June 1, 2040. The net proceeds from the sale of the Series 2010B Senior Notes were used for the redemption of all of the $200 million aggregate principal amount of Georgia Power’s Series R 6.00% Senior Notes due October 15, 2033 and all of the $150 million aggregate principal amount of Georgia Power’s Series O 5.90% Senior Notes due April 15, 2033, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Georgia Power’s continuous construction program. Southern Company issued approximately $277 million of common stock through the Southern Investment Plan and employee and director stock plans. In addition, during the three months ended June 30, 2010, Southern Company issued 2 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company’s continuous equity offering program and received cash proceeds of $69 million, net of $0.6 million in fees and commissions. The proceeds were primarily used to fund ongoing construction projects, to repay short-term and long-term indebtedness, and for general corporate purposes.

In the first six months of 2010, Gulf Power issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 5, 2020. The proceeds were used to repay at maturity $140 million aggregate principal amount of its Series 2009A Floating Rate Senior Notes due June 28, 2010, to repay a portion of its outstanding short-term indebtedness, and for general corporate purposes, including Gulf Power’s continuous construction program. In June 2010, Gulf Power incurred obligations in connection with the issuance of $21 million aggregate principal amount of the Development Authority of Monroe County, Georgia Pollution Control Revenue Bonds (Gulf Power Plant Scherer Project), First Series 2010. The proceeds were used to fund pollution control and environmental improvement facilities at Plant Scherer.

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

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

PART I

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

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

Item 4. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures.

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

(b) Changes in internal controls.

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

A new wholesale contract billing system was implemented in the second quarter 2010 for Georgia Power, Gulf Power, and Southern Power for specific wholesale contracts. This system replaces individual billing applications that were used to bill wholesale contracts. A new fuel procurement system was implemented in May 2010 for Alabama Power, Georgia Power, Gulf Power, and Mississippi Power.

The implementation of these systems provides additional operational and internal control benefits including system security and the automation of previously manual controls. These process improvement initiatives were not in response to an identified internal control deficiency.

Item 4T. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures.

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

(b) Changes in internal controls.

There have been no changes in 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 2010 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, other than as described in the next paragraph.

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	1,221,865		$	1,119,606		$	2,397,874		$	2,177,743
Wholesale revenues, non-affiliates		137,517			153,912			309,341			312,607
Wholesale revenues, affiliates		52,322			52,493			150,656			136,845
Other revenues		50,543			40,505			99,521			79,087

Total operating revenues		1,462,247			1,366,516			2,957,392			2,706,282

Operating Expenses:
Fuel		466,033			447,486			955,076			930,719
Purchased power, non-affiliates		12,718			26,123			30,601			41,667
Purchased power, affiliates		52,049			56,570			103,692			98,130
Other operations and maintenance		308,825			278,298			619,598			555,157
Depreciation and amortization		152,294			126,487			297,577			269,903
Taxes other than income taxes		81,458			82,039			163,331			162,320

Total operating expenses		1,073,377			1,017,003			2,169,875			2,057,896

Operating Income		388,870			349,513			787,517			648,386
Other Income and (Expense):
Allowance for equity funds used during construction		7,136			19,153			20,374			35,878
Interest income		3,976			4,148			8,014			8,270
Interest expense, net of amounts capitalized		(76,132	)		(76,768	)		(150,694	)		(148,975	)
Other income (expense), net		(5,189	)		(4,491	)		(11,690	)		(10,863	)

Total other income and (expense)		(70,209	)		(57,958	)		(133,996	)		(115,690	)

Earnings Before Income Taxes		318,661			291,555			653,521			532,696
Income taxes		118,884			105,357			241,130			190,366

Net Income		199,777			186,198			412,391			342,330
Dividends on Preferred and Preference Stock		9,866			9,866			19,732			19,732

Net Income After Dividends on Preferred and Preference Stock	$	189,911		$	176,332		$	392,659		$	322,598

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	189,911		$	176,332		$	392,659		$	322,598
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(39), $(700), $(10), and $(1,586), respectively		(63	)		(1,152	)		(17	)		(2,609	)
Reclassification adjustment for amounts included in net income, net of tax of $(67), $1,178, $543, and $2,239, respectively		(111	)		1,938			892			3,683

Total other comprehensive income (loss)		(174	)		786			875			1,074

Comprehensive Income	$	189,737		$	177,118		$	393,534		$	323,672

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

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Six Months
	Ended June 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	412,391		$	342,330
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		342,542			311,868
Deferred income taxes		123,648			5,182
Allowance for equity funds used during construction		(20,374	)		(35,878	)
Pension, postretirement, and other employee benefits		(16,596	)		(16,568	)
Stock based compensation expense		3,614			3,168
Other, net		(26,671	)		680
Changes in certain current assets and liabilities —
-Receivables		(48,514	)		206,523
-Fossil fuel stock		15,211			(59,418	)
-Materials and supplies		(7,805	)		(9,094	)
-Other current assets		(48,541	)		(62,618	)
-Accounts payable		(88,154	)		(133,138	)
-Accrued taxes		(44,836	)		25,199
-Accrued compensation		(21,023	)		(56,429	)
-Other current liabilities		(77,168	)		18,302

Net cash provided from operating activities		497,724			540,109

Investing Activities:
Property additions		(483,493	)		(641,598	)
Distribution of restricted cash from pollution control revenue bonds		5,241			32,758
Nuclear decommissioning trust fund purchases		(84,057	)		(124,057	)
Nuclear decommissioning trust fund sales		84,057			124,057
Cost of removal, net of salvage		(15,708	)		(13,004	)
Change in construction payables		(27,552	)		17,575
Other investing activities		(25,020	)		(19,448	)

Net cash used for investing activities		(546,532	)		(623,717	)

Financing Activities:
Increase (decrease) in notes payable, net		59,997			(24,995	)
Proceeds —
Capital contributions from parent company		10,821			11,510
Pollution control revenue bonds		—			53,000
Senior notes issuances		—			500,000
Payment of preferred and preference stock dividends		(19,727	)		(19,740	)
Payment of common stock dividends		(271,350	)		(261,400	)
Other financing activities		1,028			(6,033	)

Net cash provided from (used for) financing activities		(219,231	)		252,342

Net Change in Cash and Cash Equivalents		(268,039	)		168,734
Cash and Cash Equivalents at Beginning of Period		368,016			28,181

Cash and Cash Equivalents at End of Period	$	99,977		$	196,915

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $7,941 and $15,005 capitalized for 2010 and 2009, respectively)	$	125,212		$	122,624
Income taxes (net of refunds)	$	204,060		$	203,248

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

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	99,977		$	368,016
Restricted cash and cash equivalents		31,471			36,711
Receivables —
Customer accounts receivable		366,455			322,292
Unbilled revenues		166,593			134,875
Under recovered regulatory clause revenues		3,773			37,338
Other accounts and notes receivable		37,068			33,522
Affiliated companies		65,042			61,508
Accumulated provision for uncollectible accounts		(12,121	)		(9,551	)
Fossil fuel stock, at average cost		387,625			394,511
Materials and supplies, at average cost		333,856			326,074
Vacation pay		54,255			53,607
Prepaid expenses		188,453			111,320
Other regulatory assets, current		31,971			34,347
Other current assets		6,076			6,203

Total current assets		1,760,494			1,910,773

Property, Plant, and Equipment:
In service		19,668,405			18,574,229
Less accumulated provision for depreciation		6,752,418			6,558,864

Plant in service, net of depreciation		12,915,987			12,015,365
Nuclear fuel, at amortized cost		303,851			253,308
Construction work in progress		511,864			1,256,311

Total property, plant, and equipment		13,731,702			13,524,984

Other Property and Investments:
Equity investments in unconsolidated subsidiaries		61,257			59,628
Nuclear decommissioning trusts, at fair value		475,516			489,795
Miscellaneous property and investments		70,028			69,749

Total other property and investments		606,801			619,172

Deferred Charges and Other Assets:
Deferred charges related to income taxes		412,681			387,447
Prepaid pension costs		150,777			132,643
Other regulatory assets, deferred		752,469			750,492
Other deferred charges and assets		224,551			198,582

Total deferred charges and other assets		1,540,478			1,469,164

Total Assets	$	17,639,475		$	17,524,093

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

ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Liabilities and Stockholder’s Equity	2010			2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	300,000		$	100,000
Notes payable		59,997			—
Accounts payable —
Affiliated		208,729			194,675
Other		197,549			328,400
Customer deposits		86,716			86,975
Accrued taxes —
Accrued income taxes		1,686			14,789
Other accrued taxes		75,017			31,918
Accrued interest		66,757			65,455
Accrued vacation pay		44,415			44,751
Accrued compensation		52,176			71,286
Liabilities from risk management activities		32,097			37,844
Over recovered regulatory clause revenues		103,103			181,565
Other current liabilities		53,495			40,020

Total current liabilities		1,281,737			1,197,678

Long-term Debt		5,882,547			6,082,489

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,400,633			2,293,468
Deferred credits related to income taxes		86,888			88,705
Accumulated deferred investment tax credits		160,751			164,713
Employee benefit obligations		386,697			387,936
Asset retirement obligations		504,017			491,007
Other cost of removal obligations		690,982			668,151
Other regulatory liabilities, deferred		127,646			169,224
Deferred over recovered regulatory clause revenues		16,874			22,060
Other deferred credits and liabilities		41,088			37,113

Total deferred credits and other liabilities		4,415,576			4,322,377

Total Liabilities		11,579,860			11,602,544

Redeemable Preferred Stock		341,715			341,715

Preference Stock		343,373			343,373

Common Stockholder’s Equity:
Common stock, par value $40 per share —
Authorized - 40,000,000 shares
Outstanding - 30,537,500 shares		1,221,500			1,221,500
Paid-in capital		2,135,696			2,119,818
Retained earnings		2,021,839			1,900,526
Accumulated other comprehensive loss		(4,508	)		(5,383	)

Total common stockholder’s equity		5,374,527			5,236,461

Total Liabilities and Stockholder’s Equity	$	17,639,475		$	17,524,093

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

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

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

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income

Alabama Power’s net income after dividends on preferred and preference stock for the second quarter 2010 was $189.9 million compared to $176.3 million for the corresponding period in 2009. Alabama Power’s net income after dividends on preferred and preference stock for year-to-date 2010 was $392.7 million compared to $322.6 million for the corresponding period in 2009. The increases when compared to the corresponding periods in 2009 were primarily due to increases in rates under Rate Stabilization and Equalization Plan (Rate RSE) and Rate Certificated New Plant for environmental costs (Rate CNP Environmental) that took effect January 2010, warmer weather in the second quarter 2010 as well as significantly colder weather in the first quarter 2010, and increases in industrial sales. The increases in revenues were partially offset by increases in operations and maintenance expenses and depreciation and amortization and a reduction in AFUDC equity.

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

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

Retail Revenues

In the second quarter 2010, retail revenues were $1.22 billion compared to $1.12 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $2.40 billion compared to $2.18 billion for the corresponding period in 2009.

Details of the change to retail revenues are as follows:


	Second Quarter					Year-to-Date
	2010					2010
	(in millions)		(% change)			(in millions)		(% change)
Retail – prior year	$	1,119.6				$	2,177.7
Estimated change in —
Rates and pricing		66.4		5.9			128.3		5.9
Sales growth (decline)		6.4		0.6			8.1		0.4
Weather		23.0		2.1			81.1		3.7
Fuel and other cost recovery		6.5		0.6			2.7		0.1

Retail – current year	$	1,221.9		9.2	%	$	2,397.9		10.1	%

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

Revenues attributable to changes in sales increased in the second quarter 2010 when compared to the corresponding period in 2009. Industrial KWH energy sales increased 18.4% due to an increase in demand primarily in the chemicals and primary metals sectors. Weather-adjusted residential KWH energy sales increased 1.4% driven by an increase in demand. Weather-adjusted commercial KWH energy sales decreased 3.0% due to a decline in the number of customers and demand.

Revenues attributable to changes in sales increased year-to-date 2010 when compared to the corresponding period in 2009. Industrial KWH energy sales increased 14.4% due to an increase in demand primarily in the chemicals and primary metals sectors. Weather-adjusted residential KWH energy sales increased 2.0% driven by an increase in demand. Weather-adjusted commercial KWH energy sales decreased 2.0% driven by a decline in the number of customers.

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

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

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

Wholesale Revenues – Non-Affiliates

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 2010, wholesale revenues from non-affiliates were $137.5 million compared to $153.9 million for the corresponding period in 2009. This decrease was primarily due to 25.2% decrease in KWH sales, partially offset by a 19.5% increase in the price of energy. In May 2010, the long-term unit power sales contracts expired and the unit power sales capacity revenues ceased, resulting in a $23.0 million revenue reduction. Beginning in June 2010, such capacity subject to the unit power sales contracts became available for retail service. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Operating Revenues” of Alabama Power in Item 7 of the Form 10-K for additional information.

For year-to-date 2010, the decrease in wholesale revenues from non-affiliates when compared to the corresponding period in 2009 was not material.

Wholesale Revenues – Affiliates

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

In the second quarter 2010, the decrease in wholesale revenues from affiliates when compared to the corresponding period in 2009 was not material.

For year-to-date 2010, wholesale revenues from affiliates were $150.7 million compared to $136.8 million for the corresponding period in 2009. The increase was primarily due to a 6.2% increase in price and a 3.7% increase in KWH sales.

Other Revenues

In the second quarter 2010, other revenues were $50.5 million compared to $40.5 million for the corresponding period in 2009. This increase was due to a $4.9 million increase in revenues from gas-fueled co-generation steam facilities as a

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

result of greater sales volume; a $3.1 million increase in transmission sales; and a $1.1 million increase in customer charges related to reconnection fees.

For year-to-date 2010, other revenues were $99.5 million compared to $79.1 million for the corresponding period in 2009. This increase was due to a $7.7 million increase in revenues from gas-fueled co-generation steam facilities as a result of greater sales volume; a $4.5 million increase in transmission sales; a $1.7 million increase in customer charges related to reconnection and late fees; a $1.2 million increase in pole attachment rentals; and a $1.1 million increase in miscellaneous service revenues.

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 2010						Year-to-Date 2010
	vs.						vs.
	Second Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)			(% change)

Fuel*	$	18.6			4.1		$	24.4			2.6
Purchased power – non-affiliates		(13.5	)		(51.3	)		(11.1	)		(26.6	)
Purchased power – affiliates		(4.5	)		(8.0	)		5.6			5.7

Total fuel and purchased power expenses	$	0.6					$	18.9

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

In the second quarter and year-to-date 2010, the increase in total fuel and purchased power expenses, when compared to the corresponding periods in 2009, was not material.

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

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	2010		2009		Change		2010		2009		Change
	(cents per net KWH)						(cents per net KWH)
Fuel		2.82		2.78		1.4		2.81		2.85		(1.4	)
Purchased power		6.19		6.01		3.0		6.65		6.06		9.7

In the second quarter and year-to-date 2010, the increase in fuel expense, when compared to the corresponding periods in 2009, was not material.

Non-Affiliates

In the second quarter 2010, purchased power expense from non-affiliates was $12.7 million compared to $26.2 million for the corresponding period in 2009. This decrease was primarily related to a 53.3% decrease in the amount of energy purchased.

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

For year-to-date 2010, purchased power expense from non-affiliates was $30.6 million compared to $41.7 million for the corresponding period in 2009. This decrease was related to a 38.2% decrease in the amount of energy purchased, partially offset by an 18.9% increase in the average cost per KWH.

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

Affiliates

In the second quarter 2010, the decrease in purchased power expense from affiliates when compared to the corresponding period in 2009 was not material. For year-to-date 2010, the increase in purchased power expense from affiliates when compared to the corresponding period in 2009 was not material.

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

Other Operations and Maintenance Expenses

In the second quarter 2010, other operations and maintenance expenses were $308.8 million compared to $278.3 million for the corresponding period in 2009. Steam production expenses increased $11.0 million due to environmental mandates (which are offset by revenues associated with Rate CNP Environmental) and maintenance costs related to increases in labor. Administrative and general expenses increased $10.5 million related to increases in affiliated service companies’ expenses and the injuries and damages reserve. Nuclear production expenses increased $4.7 million due to maintenance costs related to increases in labor.

For year-to-date 2010, other operations and maintenance expenses were $619.6 million compared to $555.2 million for the corresponding period in 2009. Steam production expenses increased $36.1 million due to scheduled outage costs, environmental mandates (which are offset by revenues associated with Rate CNP Environmental), and maintenance costs related to increases in labor and materials expenses. Administrative and general expenses increased $22.7 million due to increases in affiliated service companies’ expenses, the injuries and damages reserve, property insurance expenses, and labor, partially offset by a reduction in employee medical and other benefit-related expenses. Nuclear production expenses increased $4.0 million due to maintenance costs related to increases in labor.

Depreciation and Amortization

In the second quarter 2010, depreciation and amortization was $152.3 million compared to $126.5 million for the corresponding period in 2009. This increase was due to additions of property, plant, and equipment primarily related to steam power, environmental mandates (which are offset by revenues associated with Rate CNP Environmental), and transmission projects.

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

For year-to-date 2010, depreciation and amortization was $297.6 million compared to $269.9 million for the corresponding period in 2009. This increase was due to additions of property, plant, and equipment primarily related to environmental mandates (which are offset by revenues associated with Rate CNP Environmental), distribution, and transmission projects.

Allowance for Funds Used During Construction

In the second quarter 2010, AFUDC equity was $7.1 million compared to $19.1 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $20.4 million compared to $35.8 million for the corresponding period in 2009. These decreases were due to the completion of construction projects related to environmental mandates at generating facilities, partially offset by increases in nuclear facility and general plant projects.

Income Taxes

In the second quarter 2010, income taxes were $118.9 million compared to $105.4 million for the corresponding period in 2009. For year-to-date 2010, income taxes were $241.1 million compared to $190.3 million for the corresponding period in 2009. These increases were primarily due to higher pre-tax earnings and a reduction of the tax benefits associated with a decrease in AFUDC equity.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

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

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Alabama Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO₂) regulations. On June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO₂, including the establishment of a new short-term standard. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

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

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Alabama Power in Item 7 of the Form 10-K for information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards,

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

the proposed Transport Rule would also require D.C. and 25 states, including Alabama, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Alabama Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, the final regulation could significantly alter the options available for beneficial reuse. The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Alabama Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Global Climate Issues

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

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

FERC and Alabama PSC Matters

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Alabama Power’s fuel cost recovery. Alabama Power’s over recovered fuel costs as of June 30, 2010 totaled $98.8 million as compared to $199.6 million at December 31, 2009. These over recovered fuel costs at June 30, 2010 are included in over recovered regulatory clause revenues and deferred over recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. The current and deferred classifications are based on estimates which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any return of the over recovered fuel costs.

Natural Disaster Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Natural Disaster Reserve” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for information regarding natural disaster cost recovery. At June 30, 2010, Alabama Power had an accumulated balance of $77.3 million in the target reserve for future storms, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred.

Hydro Relicensing

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

Legislation

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

Healthcare Reform

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

retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the MPDIMA, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Under the Acts, beginning in 2013, an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in the period enacted regardless of the effective date; however, as a result of state regulatory treatment, this change had no material impact on the financial statements of Alabama Power. Southern Company is in the process of assessing the extent to which the legislation may affect its future health care and related employee benefit plan costs. Any future impact on the financial statements of Alabama Power cannot be determined at this time.

Stimulus Funding

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

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

Other Matters

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

The extent of coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has potential impacts on certain steam plant operations as well as potential significant economic impacts on the affected areas within Alabama Power’s service territory. The ultimate impact of this matter cannot be determined at this time.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $497.7 million for the first six months of 2010, compared to $540.1 million for the corresponding period in 2009. The $42.4 million decrease in cash provided from operating activities was primarily due to less cash collections of regulatory clause revenues when compared to the prior year, partially offset by increases in net income and deferred income taxes. Net cash used for investing activities totaled $546.5 million in the first six months of 2010 primarily due to gross property additions related to steam generation equipment and construction payables. Net cash used for financing activities totaled $219.2 million for the first six months of 2010, compared to $252.3 million provided in the corresponding period in 2009. The $471.5 million decrease is primarily due to fewer issuances of securities and an increase in notes payable. 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 2010 include increases of $206.7 million in total property, plant, and equipment primarily due to increases in environmental-related equipment and nuclear fuel; $107.2 million in accumulated deferred income taxes; $77.1 million in prepaid expenses; $44.2 million in customer accounts receivable; $31.7 million in unbilled revenues; and $26.0 million in other deferred charges and assets.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $300 million will be required through June 30, 2011 to fund maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory

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

requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

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, 2010 cash and cash equivalents of approximately $100 million and unused committed credit arrangements with banks of approximately $1.3 billion. Of the unused credit arrangements, $333 million expire in 2010, $173 million expire in 2011, and $765 million expire in 2012. Of the credit arrangements that expire in 2010, $333 million contain provisions allowing for one-year term loans executable at expiration. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Alabama Power’s commercial paper borrowings and $744 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Subsequent to June 30, 2010, Alabama Power renewed a $200 million credit agreement which contains a provision allowing a one-year term loan executable at expiration and extended the expiration date to 2011. 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, 2010, Alabama Power had $60 million of commercial paper borrowings 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

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At June 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $2 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $336 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power’s ability to access capital markets, particularly the short-term debt market.

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

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

Market Price Risk

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

Due to cost-based rate regulation, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. As such, Alabama Power had no material change in market risk exposure for the second quarter 2010 when compared with the December 31, 2009 reporting period.

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


	Second Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(67	)	$	(44	)
Contracts realized or settled		20			34
Current period changes^(a)		2			(35	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(45	)	$	(45	)

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

The change in the fair value positions of the energy-related derivative contracts for the three months and six months ended June 30, 2010 was an increase of $22 million and a decrease of $1 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At June 30, 2010, Alabama Power had a net hedge volume of 31 million mmBtu with a weighted average contract cost of approximately $1.47 per mmBtu above market prices, compared to 32 million mmBtu at March 31, 2010 with a weighted average contract cost of approximately $2.07 per mmBtu above market prices and 36 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.22 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the fuel cost recovery clause.

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

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

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, 2010 are as follows:


	June 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(45	)		(32	)		(13	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(45	)	$	(32	)	$	(13	)	$	—

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

Financing Activities

Alabama Power did not issue or redeem any securities during the six months ended June 30, 2010.

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

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	1,826,411		$	1,682,225		$	3,617,985		$	3,274,620
Wholesale revenues, non-affiliates		88,605			96,570			198,229			192,556
Wholesale revenues, affiliates		11,863			29,623			26,274			44,833
Other revenues		72,626			65,896			141,182			128,146

Total operating revenues		1,999,505			1,874,314			3,983,670			3,640,155

Operating Expenses:
Fuel		757,380			652,889			1,514,881			1,253,379
Purchased power, non-affiliates		83,843			70,817			165,541			132,770
Purchased power, affiliates		132,061			172,418			293,998			369,641
Other operations and maintenance		399,972			353,562			789,253			744,055
Depreciation and amortization		130,046			175,080			244,228			342,191
Taxes other than income taxes		85,166			81,008			165,640			157,256

Total operating expenses		1,588,468			1,505,774			3,173,541			2,999,292

Operating Income		411,037			368,540			810,129			640,863
Other Income and (Expense):
Allowance for equity funds used during construction		35,923			22,313			70,655			43,067
Interest income		382			(197	)		795			1,033
Interest expense, net of amounts capitalized		(87,333	)		(99,425	)		(180,322	)		(197,815	)
Other income (expense), net		(1,665	)		2,531			(7,213	)		(4,189	)

Total other income and (expense)		(52,693	)		(74,778	)		(116,085	)		(157,904	)

Earnings Before Income Taxes		358,344			293,762			694,044			482,959
Income taxes		115,810			99,682			209,182			162,310

Net Income		242,534			194,080			484,862			320,649
Dividends on Preferred and Preference Stock		4,346			4,346			8,691			8,691

Net Income After Dividends on Preferred and Preference Stock	$	238,188		$	189,734		$	476,171		$	311,958

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Net Income After Dividends on Preferred and Preference Stock	$	238,188		$	189,734		$	476,171		$	311,958
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(11), $(905), $(6), and $275, respectively		(17	)		(1,435	)		(9	)		435
Reclassification adjustment for amounts included in net income, net of tax of $1,959, $2,427, $3,757, and $4,170, respectively		3,105			3,848			5,956			6,611

Total other comprehensive income (loss)		3,088			2,413			5,947			7,046

Comprehensive Income	$	241,276		$	192,147		$	482,118		$	319,004

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

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Six Months
	Ended June 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	484,862		$	320,649
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		325,760			402,086
Deferred income taxes		85,220			54,721
Deferred revenues		(42,679	)		(20,929	)
Deferred expenses		17,653			20,523
Allowance for equity funds used during construction		(70,655	)		(43,067	)
Pension, postretirement, and other employee benefits		(10,197	)		(11,543	)
Hedge settlements		—			(16,167	)
Insurance cash surrender value		—			23,041
Other, net		(26,623	)		19,094
Changes in certain current assets and liabilities —
-Receivables		(146,893	)		(126,080	)
-Fossil fuel stock		59,474			(222,837	)
-Prepaid income taxes		12,115			(20,298	)
-Other current assets		(9,879	)		(14,914	)
-Accounts payable		80,057			120,228
-Accrued taxes		(104,101	)		(74,291	)
-Accrued compensation		13,061			(103,764	)
-Other current liabilities		26,458			31,345

Net cash provided from operating activities		693,633			337,797

Investing Activities:
Property additions		(1,112,468	)		(1,208,114	)
Distribution of restricted cash from pollution control revenue bonds		—			15,566
Nuclear decommissioning trust fund purchases		(431,844	)		(699,359	)
Nuclear decommissioning trust fund sales		404,504			664,633
Nuclear decommissioning trust securities lending collateral		23,878			31,264
Cost of removal, net of salvage		(29,769	)		(33,041	)
Change in construction payables, net of joint owner portion		22,584			103,558
Other investing activities		4,667			12,646

Net cash used for investing activities		(1,118,448	)		(1,112,847	)

Financing Activities:
Increase (decrease) in notes payable, net		(8,033	)		114,439
Proceeds —
Capital contributions from parent company		569,709			602,968
Senior notes issuances		950,000			500,000
Other long-term debt issuances		—			750
Redemptions —
Senior notes		(601,400	)		(151,928	)
Other long-term debt		(2,500	)		—
Payment of preferred and preference stock dividends		(8,700	)		(8,758	)
Payment of common stock dividends		(410,000	)		(369,450	)
Other financing activities		(13,964	)		(7,963	)

Net cash provided from financing activities		475,112			680,058

Net Change in Cash and Cash Equivalents		50,297			(94,992	)
Cash and Cash Equivalents at Beginning of Period		14,309			132,739

Cash and Cash Equivalents at End of Period	$	64,606		$	37,747

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $26,404 and $18,986 capitalized for 2010 and 2009, respectively)	$	172,335		$	167,890
Income taxes (net of refunds)	$	95,814		$	79,141

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

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	64,606		$	14,309
Receivables —
Customer accounts receivable		596,015			486,885
Unbilled revenues		224,951			172,035
Under recovered regulatory clause revenues		177,265			291,837
Joint owner accounts receivable		137,400			146,932
Other accounts and notes receivable		61,281			62,758
Affiliated companies		32,906			11,775
Accumulated provision for uncollectible accounts		(10,130	)		(9,856	)
Fossil fuel stock, at average cost		666,792			726,266
Materials and supplies, at average cost		362,247			362,803
Vacation pay		74,291			74,566
Prepaid income taxes		108,523			132,668
Other regulatory assets, current		80,500			76,634
Other current assets		49,415			62,651

Total current assets		2,626,062			2,612,263

Property, Plant, and Equipment:
In service		25,931,241			25,120,034
Less accumulated provision for depreciation		9,731,877			9,493,068

Plant in service, net of depreciation		16,199,364			15,626,966
Nuclear fuel, at amortized cost		373,327			339,810
Construction work in progress		2,732,607			2,521,091

Total property, plant, and equipment		19,305,298			18,487,867

Other Property and Investments:
Equity investments in unconsolidated subsidiaries		67,666			66,106
Nuclear decommissioning trusts, at fair value		579,520			580,322
Miscellaneous property and investments		38,225			38,516

Total other property and investments		685,411			684,944

Deferred Charges and Other Assets:
Deferred charges related to income taxes		692,440			608,851
Deferred under recovered regulatory clause revenues		479,896			373,245
Other regulatory assets, deferred		1,385,830			1,321,904
Other deferred charges and assets		197,930			205,492

Total deferred charges and other assets		2,756,096			2,509,492

Total Assets	$	25,372,867		$	24,294,566

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

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Liabilities and Stockholder’s Equity	2010			2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	403,898		$	253,882
Notes payable		315,925			323,958
Accounts payable —
Affiliated		303,599			238,599
Other		659,546			602,003
Customer deposits		202,327			200,103
Accrued taxes —
Accrued income taxes		30,533			548
Unrecognized tax benefits		167,618			164,863
Other accrued taxes		171,328			290,174
Accrued interest		88,719			89,228
Accrued vacation pay		55,098			57,662
Accrued compensation		58,593			42,756
Liabilities from risk management activities		52,390			49,788
Other cost of removal obligations, current		108,000			216,000
Other regulatory liabilities, current		52,838			99,807
Other current liabilities		137,394			84,319

Total current liabilities		2,807,806			2,713,690

Long-term Debt		7,971,643			7,782,340

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,527,777			3,389,907
Deferred credits related to income taxes		131,218			133,683
Accumulated deferred investment tax credits		235,876			242,496
Employee benefit obligations		914,733			923,177
Asset retirement obligations		694,213			676,705
Other cost of removal obligations		119,709			124,662
Other deferred credits and liabilities		153,752			139,024

Total deferred credits and other liabilities		5,777,278			5,629,654

Total Liabilities		16,556,727			16,125,684

Preferred Stock		44,991			44,991

Preference Stock		220,966			220,966

Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - 9,261,500 shares		398,473			398,473
Paid-in capital		5,167,490			4,592,350
Retained earnings		2,999,105			2,932,934
Accumulated other comprehensive loss		(14,885	)		(20,832	)

Total common stockholder’s equity		8,550,183			7,902,925

Total Liabilities and Stockholder’s Equity	$	25,372,867		$	24,294,566

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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Georgia Power’s business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain energy sales given the effects of the recession, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, and fuel prices. Georgia Power is currently constructing two new nuclear and three new combined cycle generating units. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future. Georgia Power filed a general rate case on July 1, 2010, requesting a base rate increase effective January 1, 2011. On March 11, 2010, the Georgia PSC approved Georgia Power’s request to increase its fuel cost recovery rate effective April 1, 2010. Georgia Power is required to file its next fuel cost recovery case by March 1, 2011.

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

RESULTS OF OPERATIONS

Net Income


Second Quarter 2010 vs. Second Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)		(change in millions)	(% change)
$48.5	25.5		$164.2	52.6

Georgia Power’s net income after dividends on preferred and preference stock for the second quarter 2010 was $238.2 million compared to $189.7 million for the corresponding period in 2009. Georgia Power’s year-to-date 2010 net income after dividends on preferred and preference stock was $476.2 million compared to $312.0 million for the corresponding period in 2009. These increases were due primarily to higher residential base revenues resulting from warmer weather in the second quarter 2010 and significantly colder weather in the first quarter 2010, and the amortization of the regulatory liability related to other cost of removal obligations that began in July 2009 as authorized by the Georgia PSC. These increases were partially offset by increases in operation and maintenance expenses.

Retail Revenues


Second Quarter 2010 vs. Second Quarter 2009		Year-to-Date 2010 vs. Year-to-Date 2009
(change in millions)	(% change)		(change in millions)	(% change)
$144.2	8.6		$343.4	10.5

In the second quarter 2010, retail revenues were $1.8 billion compared to $1.7 billion for the corresponding period in 2009. For year-to-date 2010, retail revenues were $3.6 billion compared to $3.3 billion for the corresponding period in 2009.

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
	2010						2010
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	1,682.2					$	3,274.6
Estimated change in —
Rates and pricing		(25.2	)		(1.5	)		(27.7	)		(0.8	)
Sales growth (decline)		26.1			1.6			40.1			1.2
Weather		29.6			1.8			77.6			2.4
Fuel cost recovery		113.7			6.8			253.4			7.7

Retail – current year	$	1,826.4			8.7	%	$	3,618.0			10.5	%

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

Revenues attributable to changes in sales increased in the second quarter and year-to-date 2010 when compared to the corresponding periods in 2009. Weather-adjusted residential KWH sales increased 2.0%, weather-adjusted commercial KWH sales decreased 0.1%, and weather-adjusted industrial KWH sales increased 10.4% in the second quarter 2010 when compared to the corresponding period in 2009. Weather-adjusted residential KWH sales increased 1.6%, weather-adjusted commercial KWH sales increased 0.4%, and weather-adjusted industrial KWH sales increased 7.5% year-to-date 2010 when compared to the corresponding period in 2009.

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

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $113.7 million in the second quarter 2010 and $253.4 million for year-to-date 2010 when compared to the corresponding periods in 2009 due to the increase in the fuel cost recovery rate effective April 1, 2010. See Note (B) to the Condensed Financial Statements under “Retail Regulatory Matters — Fuel Cost Recovery” herein for additional information.

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

Wholesale Revenues – Non-Affiliates

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

In the second quarter 2010, wholesale revenues from non-affiliates were $88.6 million compared to $96.6 million in the corresponding period in 2009. This decrease was due to a 23.9% decrease in KWH sales due to lower demand because the market cost of available energy was lower than the cost of Georgia Power-owned generation.

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2010, wholesale revenues from non-affiliates were $198.2 million compared to $192.6 million in the corresponding period in 2009. This increase was due to higher capacity revenues of $7.9 million related to increased contributions from the environmental control component of market-based wholesale rates, partially offset by an 8.9% decrease in KWH sales due to lower demand because the market cost of available energy was lower than the cost of Georgia Power-owned generation.

Wholesale Revenues – Affiliates

In the second quarter 2010, wholesale revenues from affiliates were $11.9 million compared to $29.6 million for the corresponding period in 2009. For year-to-date 2010, wholesale revenues from affiliates were $26.3 million compared to $44.8 million for the corresponding period in 2009. These decreases were due to a 54.9% decrease and a 37.7% decrease in KWH sales due to lower demand in the second quarter 2010 and year-to-date 2010, respectively, because the market cost of available energy was lower than the cost of Georgia Power-owned generation.

Other Revenues

In the second quarter 2010, other revenues were $72.6 million compared to $65.9 million for the corresponding period in 2009. This increase was primarily due to a $3.4 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies and an increase of $1.3 million in outdoor lighting revenues.

For year-to-date 2010, other revenues were $141.2 million compared to $128.1 million for the corresponding period in 2009. This increase was due to a $6.3 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies, an increase of $1.8 million in pole attachment and equipment rental revenue, and an increase of $1.4 million in outdoor lighting revenues.

Fuel and Purchased Power Expenses


	Second Quarter 2010						Year-to-Date 2010
	vs.						vs.
	Second Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel*	$	104.5			16.0		$	261.5			20.9
Purchased power — non-affiliates		13.0			18.4			32.7			24.7
Purchased power — affiliates		(40.3	)		(23.4	)		(75.6	)		(20.5	)

Total fuel and purchased power expenses	$	77.2					$	218.6


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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the second quarter 2010, total fuel and purchased power expenses were $973.3 million compared to $896.1 million in the corresponding period in 2009. This increase was primarily due to a $79.4 million increase in the average cost of fuel and purchased power.

For year-to-date 2010, total fuel and purchased power expenses were $2.0 billion compared to $1.8 billion in the corresponding period in 2009. This increase was due to a $179.5 million increase in the average cost of fossil and nuclear fuel and $39.1 million related to higher KWHs generated primarily due to higher customer demand as a result of significantly colder weather in the first quarter 2010 and warmer weather in the second quarter 2010.

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

Details of Georgia 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	2010		2009		Change		2010		2009		Change
	(cents per net KWH)						(cents per net KWH)
Fuel		3.75		3.40		10.3		3.76		3.32		13.3
Purchased power		5.96		5.63		5.9		6.16		5.99		2.8

In the second quarter 2010, fuel expense was $757.4 million compared to $652.9 million in the corresponding period in 2009. This increase was due to a 10.3% increase in the average cost of fuel per KWH and a 9.5% increase of KWHs generated as a result of higher KWH demand.

For year-to-date 2010, fuel expense was $1.5 billion compared to $1.3 billion in the corresponding period in 2009. This increase was due to a 13.3% increase in the average cost of fuel per KWH and a 9.9% increase of KWHs generated as a result of higher KWH demand.

Non-Affiliates

In the second quarter 2010, purchased power expense from non-affiliates was $83.8 million compared to $70.8 million in the corresponding period in 2009. This increase was due to a 41.3% increase in the average cost per KWH purchased reflecting additional tolling agreements associated with PPAs that went into effect in June 2009, partially offset by an 8.8% decrease in the volume of KWHs purchased.

For year-to-date 2010, purchased power expense from non-affiliates was $165.5 million compared to $132.8 million in the corresponding period in 2009. This increase was due to a 40.5% increase in the average cost per KWH purchased reflecting additional tolling agreements associated with PPAs that went into effect in June 2009, partially offset by a 4.8% decrease in the volume of KWHs purchased.

Affiliates

In the second quarter 2010, purchased power expense from affiliates was $132.1 million compared to $172.4 million in the corresponding period in 2009. This decrease was due to a 5.6% decrease in the average cost per KWH purchased following the expiration of a PPA in December 2009 and a 20.5% decrease in the volume of KWHs purchased.

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2010, purchased power expense from affiliates was $294.0 million compared to $369.6 million in the corresponding period in 2009. This decrease was due to a 7.7% decrease in the average cost per KWH purchased and a 12.4% decrease in the volume of KWHs purchased following the expiration of a PPA in December 2009.

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

Other Operations and Maintenance Expenses

In the second quarter 2010, other operations and maintenance expenses were $400.0 million compared to $353.6 million in the corresponding period in 2009. This increase was due to increases of $29.0 million in power generation, $14.6 million in transmission and distribution, and $5.9 million in customer accounting, service, and sales primarily due to cost containment efforts as a result of the economic conditions in 2009.

For year-to-date 2010, other operations and maintenance expenses were $789.3 million compared to $744.1 million in the corresponding period in 2009. This increase was due to increases of $45.8 million in power generation and $20.1 million in transmission and distribution due to cost containment efforts as a result of the economic conditions in 2009, partially offset by a decrease of $21.4 million in administrative and general expenses primarily due to a 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.

Depreciation and Amortization

In the second quarter 2010, depreciation and amortization was $130.1 million compared to $175.1 million in the corresponding period in 2009. This decrease was due to the amortization of $54 million of the regulatory liability related to the other cost of removal obligations as authorized by the Georgia PSC, partially offset by depreciation on additional plant in service related to transmission, distribution, and environmental projects.

For year-to-date 2010, depreciation and amortization was $244.2 million compared to $342.2 million in the corresponding period in 2009. This decrease was due to the amortization of $114.3 million of the regulatory liability related to the other cost of removal obligations as authorized by the Georgia PSC, partially offset by depreciation on additional plant in service related to transmission, distribution, and environmental projects.

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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

In the second quarter 2010, taxes other than income taxes were $85.2 million compared to $81.0 million in the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $165.6 million compared to $157.3 million in the corresponding period in 2009. These increases were due to higher municipal franchise fees resulting from increased retail revenues in the second quarter and year-to-date 2010.

Allowance for Funds Used During Construction

In the second quarter 2010, AFUDC equity was $35.9 million compared to $22.3 million in the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $70.7 million compared to $43.1 million in the corresponding period in 2009. These increases were due to the increase in construction work in progress balances related to three new combined cycle units at Plant McDonough, two new nuclear generating units at Plant Vogtle, and ongoing environmental and transmission projects.

Income Taxes

In the second quarter 2010, income taxes were $115.8 million compared to $99.7 million in the corresponding period in 2009. This increase was due to higher pre-tax earnings, partially offset by increased state investment tax credits and non-taxable AFUDC equity.

For year-to-date 2010, income taxes were $209.2 million compared to $162.3 million in the corresponding period in 2009. This increase was due to higher pre-tax earnings, partially offset by a decrease in uncertain tax positions related to state income tax credits that remain subject to litigation and an increase in non-taxable AFUDC equity and state investment tax credits.

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

FUTURE EARNINGS POTENTIAL

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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Environmental Matters

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — New York Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters — Carbon Dioxide Litigation — New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters — Carbon Dioxide Litigation — Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Georgia Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO₂) regulations. On June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO₂, including the establishment of a new short-term standard. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

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

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Georgia Power in Item 7 of the Form 10-K for information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Georgia, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Georgia, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Coal Combustion Byproducts” of Georgia Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, the final regulation could significantly alter the options available for beneficial reuse. The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

regulation of coal combustion byproducts could have a significant impact on Georgia Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Global Climate Issues

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

Georgia PSC Matters

Retail Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters — Fuel Cost Recovery” in Item 8 of the Form 10-K for information regarding Georgia Power’s fuel cost recovery. As of June 30, 2010, Georgia Power had a total under recovered fuel cost balance of approximately $657.2 million compared to $665.1 million at December 31, 2009. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.

Rate Plans

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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	§		Continuation of a plus or minus 100 basis point range for ROE.

	§		Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.

			The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.

	§		Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.

	§		Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.

	§		Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Georgia Power expects the Georgia PSC to issue a final order in this matter during December 2010. The final outcome of this matter cannot now be determined.

Legislation

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

Healthcare Reform

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

Stimulus Funding

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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Tax Matters

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 had also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. On April 30, 2010, the Georgia Department of Revenue filed its notice of appeal with the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Georgia Power’s cash flow. See Note 5 to the financial statements of Georgia Power under “Unrecognized Tax Benefits” in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot now be determined.

Construction

Nuclear

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

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

In August 2009 and June 2010, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors in response to concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. Georgia Power is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible delays in the AP1000 design certification schedule, including those addressed by the NRC in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units 3 and 4.

There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds.

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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Construction

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

On May 6, 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand.

Other Matters

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $693.6 million for the first six months of 2010, compared to $337.8 million for the corresponding period in 2009. The $355.8 million increase in cash provided from operating activities in the first six months of 2010 is primarily due to a $164.2 million increase in net income and fuel inventory reductions in 2010. Net cash used for investing activities totaled $1.1 billion primarily due to gross property additions to utility plant in the first six months of 2010. Net cash provided from financing activities totaled $475.1 million for the first six months of 2010, compared to $680.1 million for the corresponding period in 2009. The $205.0 million decrease is primarily due to higher issuance of short-term debt in 2009 and higher common stock dividends in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2010 include an increase of $817.4 million in total property, plant, and equipment, an increase of $189.3 million in long-term debt to replace short-term debt and provide funds for Georgia Power’s continuous construction program, and an increase in paid in capital of $575.1 million reflecting equity contributions from Southern Company.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $403.9 million will be required through June 30, 2011 to fund maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

On June 18, 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future Georgia Power borrowings related to Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

not exceed 70% of eligible project costs, or approximately $3.4 billion, and are expected to be funded by the Federal Financing Bank. Final approval and issuance of loan guarantees by the DOE are subject to receipt of the combined construction and operating license for Plant Vogtle Units 3 and 4 from the NRC, negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. There can be no assurance that the DOE will issue loan guarantees for Georgia Power.

Georgia Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at June 30, 2010 cash and cash equivalents of approximately $64.6 million and unused committed credit arrangements with banks of approximately $1.7 billion. Of the unused credit arrangements, $40.0 million expire in 2010, $555.0 million expire in 2011, and $1.1 billion expire in 2012. Of the credit arrangements that expire in 2010 and 2011, $40.0 million contain provisions allowing two-year term loans executable at expiration and $220.0 million contain provisions allowing one-year term loans executable at expiration. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Georgia Power’s commercial paper program and approximately $901 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. Subsequent to June 30, 2010, Georgia Power renewed a $40 million credit agreement which contains a provision allowing a two-year term loan executable at expiration and extended the expiration date to 2011. See Note 6 to the financial statements of Georgia Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At June 30, 2010, Georgia Power had approximately $313 million of commercial paper borrowings 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, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $29 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.5 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

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

On June 17, 2010, Moody’s placed the issuer and long-term debt ratings of Georgia Power (A2 senior unsecured) on review for a possible downgrade. Moody’s also placed the P-1 short-term rating of a Southern Company financing subsidiary that issues commercial paper for the benefit of Georgia Power and other Southern Company subsidiaries on review for a possible downgrade. In addition, Moody’s placed the preferred stock and variable rate demand obligation

GEORGIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ratings of Georgia Power (Baa1 and VMIG1) on review for a possible downgrade. Moody’s announced that it did not expect the review to result in more than a one notch downgrade of any of these ratings. The ultimate outcome of this matter cannot be determined at this time.

Market Price Risk

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

Due to cost-based rate regulation, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. As such, Georgia Power had no material change in market risk exposure for the second quarter 2010 when compared with the December 31, 2009 reporting period.

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


	Second Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value

	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(125	)	$	(75	)
Contracts realized or settled		31			50
Current period changes^(a)		1			(68	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(93	)	$	(93	)


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

The change in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2010 was an increase of $32 million and a decrease of $18 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At June 30, 2010, Georgia Power had a net hedge volume of 67 million mmBtu with a weighted average contract cost of approximately $1.40 per mmBtu above market prices, compared to 68 million mmBtu at March 31, 2010 with a weighted average contract cost of approximately $1.85 per mmBtu above market prices and compared to 65 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.16 per mmBtu above market prices. The natural gas hedges are recovered through the fuel cost recovery mechanism.

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

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

GEORGIA 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, 2010 are as follows:


	June 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(93	)		(52	)		(41	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(93	)	$	(52	)	$	(41	)	$	—

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

Financing Activities

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

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

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

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	320,109		$	290,050		$	624,859		$	528,441
Wholesale revenues, non-affiliates		26,916			22,700			54,830			44,666
Wholesale revenues, affiliates		40,873			10,727			50,391			16,087
Other revenues		15,273			17,618			29,803			36,185

Total operating revenues		403,171			341,095			759,883			625,379

Operating Expenses:
Fuel		195,452			156,195			348,164			271,748
Purchased power, non-affiliates		14,409			6,051			21,844			10,489
Purchased power, affiliates		11,030			13,240			31,443			28,621
Other operations and maintenance		64,606			64,983			135,024			137,474
Depreciation and amortization		28,548			23,317			56,619			46,376
Taxes other than income taxes		24,060			22,989			49,293			45,437

Total operating expenses		338,105			286,775			642,387			540,145

Operating Income		65,066			54,320			117,496			85,234
Other Income and (Expense):
Allowance for equity funds used during construction		1,695			5,707			3,080			10,525
Interest income		39			85			56			294
Interest expense, net of amounts capitalized		(13,137	)		(9,907	)		(24,522	)		(19,739	)
Other income (expense), net		(351	)		(487	)		(884	)		(1,103	)

Total other income and (expense)		(11,754	)		(4,602	)		(22,270	)		(10,023	)

Earnings Before Income Taxes		53,312			49,718			95,226			75,211
Income taxes		19,445			15,899			34,508			23,299

Net Income		33,867			33,819			60,718			51,912
Dividends on Preference Stock		1,550			1,550			3,101			3,101

Net Income After Dividends on Preference Stock	$	32,317		$	32,269		$	57,617		$	48,811

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2010		2009		2010			2009
	(in thousands)				(in thousands)
Net Income After Dividends on Preference Stock	$	32,317	$	32,269	$	57,617		$	48,811
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $412, $-, $(542), and $-, respectively		655		—		(863	)		—
Reclassification adjustment for amounts included in net income, net of tax of $91, $104, $196, and $209, respectively		146		167		312			334

Total other comprehensive income (loss)		801		167		(551	)		334

Comprehensive Income	$	33,118	$	32,436	$	57,066		$	49,145

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

GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Six Months
	Ended June 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	60,718		$	51,912
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		59,786			48,831
Deferred income taxes		6,192			(10,224	)
Allowance for equity funds used during construction		(3,080	)		(10,525	)
Pension, postretirement, and other employee benefits		1,487			(597	)
Stock based compensation expense		813			637
Hedge settlements		1,530			—
Other, net		(421	)		(1,759	)
Changes in certain current assets and liabilities —
-Receivables		(61,159	)		(3,606	)
-Fossil fuel stock		(5,088	)		(50,999	)
-Materials and supplies		457			(459	)
-Prepaid income taxes		1,579			416
-Property damage cost recovery		22			10,816
-Other current assets		1,324			1,319
-Accounts payable		21,861			(1,002	)
-Accrued taxes		26,345			13,591
-Accrued compensation		(157	)		(9,347	)
-Other current liabilities		11,193			10,640

Net cash provided from operating activities		123,402			49,644

Investing Activities:
Property additions		(137,133	)		(240,336	)
Investment in restricted cash from pollution control revenue bonds		—			(49,188	)
Distribution of restricted cash from pollution control revenue bonds		6,161			11,417
Cost of removal, net of salvage		(8,241	)		(5,439	)
Construction payables		(18,694	)		9,661
Payments pursuant to long-term service agreements		(2,294	)		(3,514	)
Other investing activities		(187	)		139

Net cash used for investing activities		(160,388	)		(277,260	)

Financing Activities:
Decrease in notes payable, net		(2,692	)		(73,944	)
Proceeds —
Common stock issued to parent		50,000			135,000
Capital contributions from parent company		2,167			1,897
Pollution control revenue bonds		21,000			130,400
Senior notes		175,000			140,000
Redemptions —
Senior notes		(140,305	)		(722	)
Payment of preference stock dividends		(3,101	)		(3,101	)
Payment of common stock dividends		(52,150	)		(44,650	)
Other financing activities		(2,105	)		(1,547	)

Net cash provided from financing activities		47,814			283,333

Net Change in Cash and Cash Equivalents		10,828			55,717
Cash and Cash Equivalents at Beginning of Period		8,677			3,443

Cash and Cash Equivalents at End of Period	$	19,505		$	59,160

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $1,228 and $4,195 capitalized for 2010 and 2009, respectively)	$	19,542		$	19,502
Income taxes (net of refunds)	$	12,463		$	25,642

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

GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	19,505		$	8,677
Restricted cash and cash equivalents		185			6,347
Receivables —
Customer accounts receivable		86,031			64,257
Unbilled revenues		71,966			60,414
Under recovered regulatory clause revenues		12,961			4,285
Other accounts and notes receivable		10,763			4,107
Affiliated companies		18,175			7,503
Accumulated provision for uncollectible accounts		(1,983	)		(1,913	)
Fossil fuel stock, at average cost		187,898			183,619
Materials and supplies, at average cost		43,113			38,478
Other regulatory assets, current		19,167			19,172
Prepaid expenses		12,423			44,760
Other current assets		971			3,634

Total current assets		481,175			443,340

Property, Plant, and Equipment:
In service		3,537,498			3,430,503
Less accumulated provision for depreciation		1,024,948			1,009,807

Plant in service, net of depreciation		2,512,550			2,420,696
Construction work in progress		182,235			159,499

Total property, plant, and equipment		2,694,785			2,580,195

Other Property and Investments		16,112			15,923

Deferred Charges and Other Assets:
Deferred charges related to income taxes		44,523			39,018
Other regulatory assets, deferred		212,385			190,971
Other deferred charges and assets		26,741			24,160

Total deferred charges and other assets		283,649			254,149

Total Assets	$	3,475,721		$	3,293,607

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

GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Liabilities and Stockholder’s Equity	2010			2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	110,000		$	140,000
Notes payable		86,041			90,331
Accounts payable —
Affiliated		71,971			47,421
Other		62,045			80,184
Customer deposits		34,730			32,361
Accrued taxes —
Accrued income taxes		15,911			1,955
Other accrued taxes		19,521			7,297
Accrued interest		11,111			10,222
Accrued compensation		9,180			9,337
Other regulatory liabilities, current		27,311			22,416
Liabilities from risk management activities		9,506			9,442
Other current liabilities		16,947			20,092

Total current liabilities		474,274			471,058

Long-term Debt		1,063,618			978,914

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		307,752			297,405
Accumulated deferred investment tax credits		8,881			9,652
Employee benefit obligations		109,924			109,271
Other cost of removal obligations		194,244			191,248
Other regulatory liabilities, deferred		41,622			41,399
Other deferred credits and liabilities		115,065			92,370

Total deferred credits and other liabilities		777,488			741,345

Total Liabilities		2,315,380			2,191,317

Preference Stock		97,998			97,998

Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - June 30, 2010: 3,642,717 shares
- December 31, 2009: 3,142,717 shares		303,060			253,060
Paid-in capital		537,712			534,577
Retained earnings		224,584			219,117
Accumulated other comprehensive loss		(3,013	)		(2,462	)

Total common stockholder’s equity		1,062,343			1,004,292

Total Liabilities and Stockholder’s Equity	$	3,475,721		$	3,293,607

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

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

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

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income

N/M-Not Meaningful

Gulf Power’s net income after dividends on preference stock for the second quarter 2010 was $32.3 million compared to $32.3 million for the corresponding period in 2009. Gulf Power’s net income after dividends on preference stock for year-to-date 2010 was $57.6 million compared to $48.8 million for the corresponding period in 2009. The increase was primarily due to significantly colder weather in the first quarter 2010, partially offset by a decline in sales.

Retail Revenues

In the second quarter 2010, retail revenues were $320.1 million compared to $290.1 million for the corresponding period in 2009. For year-to-date 2010, retail revenues were $624.9 million compared to $528.4 million for the corresponding period in 2009.

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
	2010						2010
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	290.1					$	528.4
Estimated change in –
Rates and pricing		16.2			5.6			33.8			6.4
Sales growth (decline)		(0.7	)		(0.2	)		(3.6	)		(0.7	)
Weather		(1.0	)		(0.3	)		11.9			2.2
Fuel and other cost recovery		15.5			5.3			54.4			10.3

Retail – current year	$	320.1			10.4	%	$	624.9			18.2	%

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

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

Revenues attributable to changes in sales decreased in the second quarter 2010 when compared to the corresponding period in 2009. KWH energy sales to industrial customers decreased 4.5% due to decreased customer demand. Weather-adjusted KWH energy sales to residential and commercial customers remained relatively flat.

Revenues attributable to changes in sales decreased for year-to-date 2010 when compared to the corresponding period in 2009. KWH energy sales to industrial customers and weather-adjusted KWH energy sales to commercial customers decreased 3.7% and 1.4%, respectively, due to decreased customer demand. Weather-adjusted KWH energy sales to residential customers remained relatively flat.

Revenues attributable to changes in weather decreased in the second quarter 2010 when compared to the corresponding period in 2009 due to less favorable weather in the second quarter 2010.

Revenues attributable to changes in weather increased year-to-date 2010 when compared to the corresponding period for 2009 due to significantly colder weather in the first quarter 2010.

Fuel and other cost recovery revenues increased in the second quarter and year-to-date 2010 when compared to the corresponding periods for 2009 primarily due to higher fuel and purchased power expenses in the second quarter of 2010. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and revenues related to the recovery of storm damage restoration costs.

Annually, Gulf Power petitions the Florida PSC for recovery of projected fuel and purchased power costs including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material effect on net income. See FUTURE EARNINGS POTENTIAL – “Florida PSC Matters – Retail 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 “Property Damage Reserve” and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.

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

Wholesale Revenues – Non-Affiliates

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

In the second quarter 2010, wholesale revenues from non-affiliates were $26.9 million compared to $22.7 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to an 8.4% increase in KWH sales to serve customer demand and a 6.8% increase in price related to energy rates.

For year-to-date 2010, wholesale revenues from non-affiliates were $54.8 million compared to $44.7 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 13.9% increase in KWH sales to serve weather-related increases in customer demand and a 10.5% increase in price related to energy rates.

Wholesale Revenues – Affiliates

In the second quarter 2010, wholesale revenues from affiliates were $40.9 million compared to $10.7 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 233.6% increase in KWH sales to serve customer demand and a 14.2% increase in price related to energy rates.

For year-to-date 2010, wholesale revenues from affiliates were $50.4 million compared to $16.1 million for the corresponding period in 2009. The increase was primarily due to increased energy revenues related to a 171.7% increase in KWH sales to serve customer demand and a 15.3% increase in price related to energy rates.

Other Revenues

In the second quarter 2010, other revenues were $15.3 million compared to $17.6 million for the corresponding period in 2009. The decrease was primarily due to a $2.5 million decrease in revenues from other energy services.

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

For year-to-date 2010, other revenues were $29.8 million compared to $36.2 million for the corresponding period in 2009. The decrease was primarily due to a $7.7 million decrease in revenues from other energy services, partially offset by higher franchise fees of $1.4 million.

The decreased 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 2010						Year-to-Date 2010
	vs.						vs.
	Second Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)		(% change)
Fuel*	$	39.2			25.1		$	76.4		28.1
Purchased power – non-affiliates		8.4			138.1			11.4		108.3
Purchased power – affiliates		(2.2	)		(16.7	)		2.8		9.9

Total fuel and purchased power expenses	$	45.4					$	90.6


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

In the second quarter 2010, total fuel and purchased power expenses were $220.9 million compared to $175.5 million for the corresponding period in 2009. The net increase in fuel and purchased power expenses was due to a $58.4 million increase related to total KWHs generated and purchased, partially offset by a $13.0 million decrease in the average cost of purchased power.

For year-to-date 2010, total fuel and purchased power expenses were $401.4 million compared to $310.8 million for the corresponding period in 2009. The net increase in fuel and purchased power expenses was due to a $72.3 million increase related to total KWHs generated and purchased and an $18.3 million increase as a result of an increase in the average cost of fuel.

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 – “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	2010		2009		Change			2010		2009		Change
	(cents per net KWH)							(cents per net KWH)
Fuel		4.93		4.45		10.79			5.01		4.39		14.12
Purchased power		4.37		6.71		(34.87	)		4.77		5.87		(18.74	)

In the second quarter 2010, fuel expense was $195.4 million compared to $156.2 million for the corresponding period in 2009. The increase was primarily due to a 15.1% increase in the average cost of coal, partially offset by a 2.7% decrease in KWHs generated.

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

For year-to-date 2010, fuel expense was $348.1 million compared to $271.7 million for the corresponding period in 2009. The increase was primarily due to a 19.8% increase in the average cost of coal, a 6.5% increase in the average cost of natural gas prices, and a 1.2% increase in KWHs generated as a result of increased demand.

Non-Affiliates

In the second quarter 2010, purchased power expense from non-affiliates was $14.4 million compared to $6.0 million for the corresponding period in 2009. The increase was primarily due to a 942.1% increase in the volume of KWHs purchased, which was primarily due to a PPA which began in the third quarter 2009, partially offset by a 44.1% decrease in the average cost per KWH purchased.

For year-to-date 2010, purchased power expense from non-affiliates was $21.9 million compared to $10.5 million for the corresponding period in 2009. The increase was primarily due to a 510.3% increase in the volume of KWHs purchased, which was primarily due to a PPA which began in the third quarter 2009, partially offset by a 20.7% decrease in the average cost per KWH purchased.

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

Affiliates

In the second quarter 2010, purchased power expense from affiliates was $11.0 million compared to $13.2 million for the corresponding period in 2009. The decrease was primarily due to a 26.8% decrease in average cost per KWH purchased, partially offset by a 15.3% increase in the volume of KWHs purchased from lower-priced Power Pool resources.

For year-to-date 2010, purchased power expense from affiliates was $31.4 million compared to $28.6 million for the corresponding period in 2009. The increase was primarily due to a 37.3% increase in the volume of KWHs purchased, partially offset by a 19.2% decrease in the average cost per KWH purchased from lower-priced Power Pool resources.

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

Other Operations and Maintenance Expenses

In the second quarter 2010, other operations and maintenance expenses were $64.6 million compared to $65.0 million for the corresponding period in 2009. For year-to-date 2010, other operations and maintenance expenses were $135.0 million compared to $137.5 million for the corresponding period in 2009. These decreases were primarily due to decreases in storm recovery costs and expenses from other energy services. The decreases were partially offset by increases in maintenance expenses, labor, and benefits expenses.

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

Depreciation and Amortization

In the second quarter 2010, depreciation and amortization was $28.5 million compared to $23.3 million for the corresponding period in 2009.

For year-to-date 2010, depreciation and amortization was $56.6 million compared to $46.4 million for the corresponding period in 2009. These increases were primarily due to the addition of an environmental control project at Plant Crist in December 2009 and other net additions to generation and distribution facilities.

Taxes Other Than Income Taxes

In the second quarter 2010, taxes other than income taxes were $24.1 million compared to $23.0 million for the corresponding period in 2009. For year-to-date 2010, taxes other than income taxes were $49.3 million compared to $45.4 million for the corresponding period in 2009. These increases were primarily due to increases in property taxes, gross receipt taxes, and franchise fees. Gross receipt taxes and franchise fees have no impact on net income.

Allowance for Funds Used During Construction

In the second quarter 2010, AFUDC equity was $1.7 million compared to $5.7 million for the corresponding period in 2009. For year-to-date 2010, AFUDC equity was $3.1 million compared to $10.5 million for the corresponding period in 2009. These decreases were primarily due to an environmental control project at Plant Crist being placed into service in December 2009.

Interest Expense, Net of Amounts Capitalized

In the second quarter 2010, interest expense, net of amounts capitalized was $13.1 million compared to $9.9 million for the corresponding period in 2009. For year-to-date 2010, interest expense, net of amounts capitalized was $24.5 million compared to $19.8 million for the corresponding period in 2009. These increases were primarily due to the change in capitalization of the AFUDC debt related to an environmental control project at Plant Crist being placed into service in December 2009 and to an increase in long-term debt levels resulting from the issuance of additional senior notes in the first quarter 2010 to fund general corporate purposes, including Gulf Power’s continuous construction program.

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

Income Taxes

In the second quarter 2010, income taxes were $19.4 million compared to $15.9 million for the corresponding period in 2009. For year-to-date 2010, income taxes were $34.5 million compared to $23.3 million for the corresponding period in 2009. These increases were primarily due to higher pre-tax earnings.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K

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

for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Gulf Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO₂) regulations. On June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO₂, including the establishment of a new short-term standard. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

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

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Gulf Power in Item 7 of the Form 10-K for information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Florida and Georgia, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Florida, Georgia, and Mississippi, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

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

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Gulf Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management and disposal of coal combustion byproducts: regulation as a solid waste or regulation as a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, the final regulation could significantly alter the options available for beneficial reuse. The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Gulf Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Global Climate Issues

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

Florida PSC Matters

Retail Fuel Cost Recovery

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In recent years, Gulf Power has experienced volatility in pricing of fuel commodities with higher than expected pricing for coal and volatile price swings in natural gas. If 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, 2010 totaled $11.2 million, compared to $2.4 million at December 31, 2009. This amount is included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a

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

significant effect on Gulf Power’s revenues or net income, but will 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.

Environmental Compliance Recovery

On July 22, 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $600 million and is scheduled for completion in the fourth quarter 2014. Gulf Power’s portion of the cost, if approved by the Florida PSC, is expected to be recovered through its environmental compliance recovery clause. Hearings on the certificate request are expected to be held with the Mississippi PSC by late 2010. The final outcome of this matter cannot now be determined.

Legislation

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

Healthcare Reform

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

Stimulus Funding

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

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

Other Matters

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

The extent of coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has potential impacts on certain steam plant operations as well as potential significant economic impacts on the affected areas within Gulf Power’s service territory. The ultimate impact of this matter cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $123.4 million for the first six months of 2010 compared to $49.6 million for the corresponding period in 2009. The $73.8 million increase in cash provided from operating activities was primarily due to an increase in cash from fossil fuel stock resulting from an increase in generation and a decrease in cash payments related to fuel inventory as well as increases in deferred income taxes, and affiliated payables. The increase was partially offset by a decrease in collections attributable to regulatory fuel clause revenues. Net cash used for

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

investing activities totaled $160.4 million in the first six months of 2010 compared to $277.3 million for the corresponding period in 2009. The $116.9 million decrease was primarily due to a $109.2 million decrease in gross property additions. Net cash provided from financing activities totaled $47.8 million for the first six months of 2010, compared to $283.3 million for the corresponding period in 2009. The $235.5 million decrease was primarily due to the redemption of senior notes in 2010 and the higher issuance of pollution control bonds in 2009. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2010 include a net increase of $114.6 million in property, plant, and equipment, primarily related to environmental control projects; the issuance of common stock to Southern Company for $50 million; a decrease of $32.3 million in prepaid expenses, primarily due to a planned inspection under a long-term service agreement, and a decrease in PPA deferred capacity expense due to seasonality; a net decrease of $30.0 million in securities due within one year; and an increase in other regulatory assets, deferred and other deferred credits and liabilities of $21.4 million and $22.7 million, respectively, primarily due to an increase in PPA deferred capacity expense.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, derivative obligations, preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $110 million will be required through June 30, 2011 to fund maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power had at June 30, 2010 cash and cash equivalents of approximately $19.5 million and unused committed credit arrangements with banks of $220 million. Of the unused credit arrangements, $80 million expire in 2010 and $155 million expire in 2011. Of these credit arrangements, $205 million contain provisions allowing one-year term loans executable at expiration. Subsequent to June 30, 2010, Gulf Power increased its existing lines of credit by $15 million with an expiration of 2011. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Gulf Power’s commercial paper borrowings and $69 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. All of these facilities contain provisions allowing one-year term loans executable at expiration. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements”

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

in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At June 30, 2010, Gulf Power had approximately $86 million of commercial paper borrowings outstanding. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At June 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $127 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $566 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power’s ability to access capital markets, particularly the short-term debt market.

On June 17, 2010, Moody’s placed the issuer and long-term debt ratings of Gulf Power (A2 senior unsecured) on review for a possible downgrade. Moody’s also placed the P-1 short-term rating of a Southern Company financing subsidiary that issues commercial paper for the benefit of Gulf Power and other Southern Company subsidiaries on review for a possible downgrade. In addition, Moody’s placed the preferred stock and variable rate demand obligation ratings of Gulf Power (Baa1 and VMIG1) on review for a possible downgrade. Moody’s announced that it did not expect the review to result in more than a one notch downgrade of any of these ratings. The ultimate outcome of this matter cannot be determined at this time.

Market Price Risk

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

Due to cost-based rate regulation, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Gulf Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Gulf Power continues to manage a fuel-hedging program implemented per the guidelines of the Florida PSC. As such, Gulf Power had no material change in market risk exposure for the second quarter 2010 when compared with the December 31, 2009 reporting period.

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

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


	Second Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(21	)	$	(14	)
Contracts realized or settled		6			10
Current period changes^(a)		—			(11	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(15	)	$	(15	)


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

The change in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2010 was an increase of $6 million and a decrease of $1 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to both the volume and prices of natural gas. At June 30, 2010, Gulf Power had a net hedge volume of 9 million mmBtu with a weighted average contract cost of approximately $1.61 per mmBtu above market prices, compared to 10 million mmBtu at March 31, 2010 with a weighted average contract cost of approximately $2.09 per mmBtu above market prices and compared to 11 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.29 per mmBtu above market prices. Natural gas hedges are recovered through the fuel cost recovery clause.

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

Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2010 and 2009 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, 2010 are as follows:


	June 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(15	)		(10	)		(5	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(15	)	$	(10	)	$	(5	)	$	—

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

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

Financing Activities

In the first six months of 2010, Gulf Power issued to Southern Company 500,000 shares of common stock, without par value, and realized proceeds of $50 million. The proceeds were used to repay a portion of Gulf Power’s short-term debt and for other general corporate purposes. Gulf Power issued $175 million aggregate principal amount of Series 2010A 4.75% Senior Notes due April 15, 2020. The proceeds were used to repay at maturity $140 million aggregate principal amount of Series 2009A Floating Rate Senior Notes due June 28, 2010, to repay a portion of its outstanding short-term debt, and for general corporate purposes, including Gulf Power’s continuous construction program. Gulf Power settled $100 million of interest rate hedges related to the Series 2010A Senior Note issuance at a gain of approximately $1.5 million. The gain will be amortized to interest expense over 10 years.

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

In 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.

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	203,094		$	201,132		$	389,681		$	376,867
Wholesale revenues, non-affiliates		66,201			73,693			145,090			153,847
Wholesale revenues, affiliates		3,936			7,963			18,611			17,381
Other revenues		3,590			3,893			7,077			7,309

Total operating revenues		276,821			286,681			560,459			555,404

Operating Expenses:
Fuel		103,575			125,832			234,372			245,797
Purchased power, non-affiliates		1,498			2,873			5,119			5,708
Purchased power, affiliates		34,490			21,595			49,211			43,400
Other operations and maintenance		71,764			61,601			139,102			121,362
Depreciation and amortization		18,786			17,660			37,461			35,675
Taxes other than income taxes		17,173			16,221			35,633			31,145

Total operating expenses		247,286			245,782			500,898			483,087

Operating Income		29,535			40,899			59,561			72,317
Other Income and (Expense):
Interest income		40			163			73			795
Interest expense, net of amounts capitalized		(5,946	)		(6,254	)		(12,125	)		(11,016	)
Other income (expense), net		1,152			1,136			2,701			2,765

Total other income and (expense)		(4,754	)		(4,955	)		(9,351	)		(7,456	)

Earnings Before Income Taxes		24,781			35,944			50,210			64,861
Income taxes		9,129			13,578			18,872			24,091

Net Income		15,652			22,366			31,338			40,770
Dividends on Preferred Stock		433			433			866			866

Net Income After Dividends on Preferred Stock	$	15,219		$	21,933		$	30,472		$	39,904

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010		2009
	(in thousands)						(in thousands)
Net Income After Dividends on Preferred Stock	$	15,219		$	21,933		$	30,472	$	39,904
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(8), $(139), $4, and $27, respectively		(14	)		(224	)		6		44

Comprehensive Income	$	15,205		$	21,709		$	30,478	$	39,948

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

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Six Months
	Ended June 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	31,338		$	40,770
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		40,362			39,202
Deferred income taxes		(7,593	)		(11,019	)
Pension, postretirement, and other employee benefits		3,638			2,852
Stock based compensation expense		917			747
Generation construction screening costs		(50,554	)		(14,049	)
Other, net		(1,150	)		2,092
Changes in certain current assets and liabilities —
-Receivables		(8,183	)		(20,557	)
-Under recovered regulatory clause revenues		—			33,831
-Fossil fuel stock		(3,557	)		(44,024	)
-Materials and supplies		(4,167	)		(1,464	)
-Prepaid income taxes		—			(446	)
-Other current assets		(8,330	)		(12,644	)
-Other accounts payable		6,462			(14,103	)
-Accrued taxes		(3,576	)		(14,243	)
-Accrued compensation		(4,452	)		(12,990	)
-Over recovered regulatory clause revenues		2,106			—
-Other current liabilities		1,591			2,260

Net cash used for operating activities		(5,148	)		(23,785	)

Investing Activities:
Property additions		(55,263	)		(50,943	)
Cost of removal, net of salvage		(5,749	)		(7,287	)
Construction payables		8,781			(4,709	)
Other investing activities		(6,227	)		(1,412	)

Net cash used for investing activities		(58,458	)		(64,351	)

Financing Activities:
Increase in notes payable, net		38,993			20,501
Proceeds —
Capital contributions from parent company		1,696			2,101
Senior notes issuances		—			125,000
Redemptions —
Capital leases		(652	)		—
Senior notes		—			(40,000	)
Payment of preferred stock dividends		(866	)		(866	)
Payment of common stock dividends		(34,300	)		(34,250	)
Other financing activities		(8	)		(1,720	)

Net cash provided from financing activities		4,863			70,766

Net Change in Cash and Cash Equivalents		(58,743	)		(17,370	)
Cash and Cash Equivalents at Beginning of Period		65,025			22,413

Cash and Cash Equivalents at End of Period	$	6,282		$	5,043

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $167 and $117 capitalized for 2010 and 2009, respectively)	$	11,022		$	8,873
Income taxes (net of refunds)	$	9,233		$	27,149

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

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Assets	2010			2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	6,282		$	65,025
Receivables —
Customer accounts receivable		39,329			36,766
Unbilled revenues		32,487			27,168
Other accounts and notes receivable		6,454			11,337
Affiliated companies		18,399			13,215
Accumulated provision for uncollectible accounts		(735	)		(940	)
Fossil fuel stock, at average cost		130,794			127,237
Materials and supplies, at average cost		31,960			27,793
Other regulatory assets, current		60,475			53,273
Prepaid income taxes		33,020			32,237
Other current assets		15,884			12,625

Total current assets		374,349			405,736

Property, Plant, and Equipment:
In service		2,346,147			2,316,494
Less accumulated provision for depreciation		967,537			950,373

Plant in service, net of depreciation		1,378,610			1,366,121
Construction work in progress		184,302			48,219

Total property, plant, and equipment		1,562,912			1,414,340

Other Property and Investments		6,413			7,018

Deferred Charges and Other Assets:
Deferred charges related to income taxes		13,778			8,536
Other regulatory assets, deferred		151,580			209,100
Other deferred charges and assets		24,378			27,951

Total deferred charges and other assets		189,736			245,587

Total Assets	$	2,133,410		$	2,072,681

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

MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)


	At June 30,		At December 31,
Liabilities and Stockholder’s Equity	2010		2009
	(in thousands)
Current Liabilities:
Securities due within one year	$	81,382	$	1,330
Notes payable		38,993		—
Accounts payable —
Affiliated		59,056		49,209
Other		43,901		38,662
Customer deposits		11,852		11,143
Accrued taxes —
Accrued income taxes		27,463		10,590
Other accrued taxes		29,101		49,547
Accrued interest		5,764		5,739
Accrued compensation		9,333		13,785
Other regulatory liabilities, current		5,750		7,610
Over recovered regulatory clause liabilities		50,702		48,596
Liabilities from risk management activities		22,521		19,454
Other current liabilities		24,689		21,142

Total current liabilities		410,507		276,807

Long-term Debt		412,859		493,480

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		222,009		223,066
Deferred credits related to income taxes		12,470		13,937
Accumulated deferred investment tax credits		12,231		12,825
Employee benefit obligations		164,222		161,778
Other cost of removal obligations		104,096		97,820
Other regulatory liabilities, deferred		55,916		54,576
Other deferred credits and liabilities		48,787		47,090

Total deferred credits and other liabilities		619,731		611,092

Total Liabilities		1,443,097		1,381,379

Redeemable Preferred Stock		32,780		32,780

Common Stockholder’s Equity:
Common stock, without par value —
Authorized - 1,130,000 shares
Outstanding - 1,121,000 shares		37,691		37,691
Paid-in capital		328,395		325,562
Retained earnings		291,441		295,269
Accumulated other comprehensive income (loss)		6		—

Total common stockholder’s equity		657,533		658,522

Total Liabilities and Stockholder’s Equity	$	2,133,410	$	2,072,681

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

100

MISSISSIPPI POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW

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

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

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

RESULTS OF OPERATIONS

Net Income

Mississippi Power’s net income after dividends on preferred stock for the second quarter 2010 was $15.2 million compared to $21.9 million for the corresponding period in 2009. The decrease in net income after dividends on preferred stock for the second quarter 2010 was primarily due to a decrease in wholesale energy revenue from non-affiliate customers served outside Mississippi Power’s service territory and increases in operations and maintenance expenses and depreciation. The decrease in net income after dividends on preferred stock for the second quarter 2010 was partially offset by an increase in territorial base revenue primarily resulting from warmer weather in the second quarter 2010 compared to the second quarter 2009.

Mississippi Power’s net income after dividends on preferred stock for year-to-date 2010 was $30.5 million compared to $39.9 million for the corresponding period in 2009. The decrease in net income after dividends on preferred stock for year-to-date 2010 was primarily due to a decrease in wholesale energy revenue from non-affiliate customers served outside Mississippi Power’s service territory and increases in operations and maintenance expenses, interest expense, net of amounts capitalized, and depreciation expense. The decrease in net income after dividends on preferred stock for year-to-date 2010 was partially offset by an increase in territorial base revenue primarily resulting from warmer weather in the second quarter 2010 and significantly colder weather in the first quarter 2010 compared to year-to-date 2009.

101

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

Retail Revenues

In the second quarter 2010, retail revenues were $203.1 million compared to $201.1 million for the corresponding period in 2009. For year-to-date 2010, retail revenues were $389.7 million compared to $376.9 million for the corresponding period in 2009.

Details of the change to retail revenues are as follows:


	Second Quarter						Year-to-Date
	2010						2010
	(in millions)			(% change)			(in millions)			(% change)
Retail – prior year	$	201.1					$	376.9
Estimated change in —
Rates and pricing		0.5			0.2			0.2			0.1
Sales growth (decline)		(0.8	)		(0.4	)		(2.0	)		(0.5	)
Weather		2.3			1.2			9.3			2.4
Fuel and other cost recovery		—			—			5.3			1.4

Retail – current year		203.1			1.0			389.7			3.4

Revenues associated with changes in rates and pricing increased in the second quarter 2010 when compared to the corresponding period in 2009 primarily due to an increase of $0.5 million related to the ECO Plan rate.

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

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

Revenues attributable to changes in sales decreased in the second quarter 2010 when compared to the corresponding period in 2009 primarily due to a decline in residential and commercial customers. Weather-adjusted KWH energy sales to residential and commercial customers decreased 1.6% and 4.2%, respectively, primarily due to the declining number of residential and commercial customers in Mississippi Power’s service territory. KWH energy sales to industrial customers increased 4.8% as a result of increased production for several large industrial customers due to improving economic conditions.

Revenues attributable to changes in sales decreased for year-to-date 2010 when compared to the corresponding period in 2009 primarily due to a decline in residential and commercial customers. Weather-adjusted KWH energy sales to residential customers increased 1.6% primarily due to an increase in customer usage. Weather-adjusted KWH energy sales to commercial customers decreased 5.4% primarily due to the declining number of commercial customers in Mississippi Power’s service territory. KWH energy sales to industrial customers increased 6.0% as a result of increased production for several large industrial customers due to improving economic conditions.

Revenues attributable to changes in weather increased in the second quarter and year-to-date 2010 due to warmer weather in the second quarter 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding periods in 2009.

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Fuel and other cost recovery revenues had no significant change in the second quarter 2010 when compared to the corresponding period in 2009. Fuel and other cost recovery revenues increased year-to-date 2010 when compared to the corresponding period in 2009 primarily as a result of higher recoverable fuel costs and an increase in revenues related to ad valorem taxes. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power’s service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

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

In the second quarter 2010, wholesale revenues from non-affiliates were $66.2 million compared to $73.7 million for the corresponding period in 2009. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $7.8 million, partially offset by a $0.3 million increase in revenues from customers inside Mississippi Power’s service territory. The $7.8 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $9.0 million decrease in sales volume, partially offset by a $1.1 million increase associated with higher prices, resulting from the higher marginal cost of fuel, and a $0.1 million increase in capacity revenues. The $0.3 million increase in revenues from customers inside Mississippi Power’s service territory was primarily due to a $0.1 million increase in fuel revenues, and a $0.2 million increase in wholesale base revenues resulting from warmer weather in the second quarter 2010 when compared to the corresponding period in 2009.

For year-to-date 2010, wholesale revenues from non-affiliates were $145.1 million compared to $153.8 million for the corresponding period in 2009. The decrease was due to decreased revenues from customers outside Mississippi Power’s service territory of $16.2 million, partially offset by a $7.5 million increase in revenues from customers inside Mississippi Power’s service territory. The $16.2 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to an $18.7 million decrease in sales volume, partially offset by a $2.3 million increase associated with higher prices, resulting from the higher marginal cost of fuel, and a $0.2 million increase in capacity revenues. The $7.5 million increase in revenues from customers inside Mississippi Power’s service territory was primarily due to a $4.3 million increase in fuel revenues and a $3.2 million increase in wholesale base revenues resulting from warmer weather in the second quarter 2010 and significantly colder weather in the first quarter 2010 when compared to the corresponding period in 2009.

Wholesale Revenues – Affiliates

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In the second quarter 2010, wholesale revenues from affiliates were $3.9 million compared to $8.0 million for the corresponding period in 2009. The decrease was primarily due to a $4.2 million decrease in energy revenues, of which $4.7 million was associated with decreased sales volume, partially offset by an increase of $0.5 million associated with higher prices. Capacity revenues increased $0.1 million.

For year-to-date 2010, wholesale revenues from affiliates were $18.6 million compared to $17.4 million for the corresponding period in 2009. The increase was primarily due to a $0.7 million increase in energy revenues, of which $1.2 million was associated with higher prices, partially offset by a decrease of $0.5 million associated with decreased sales volume. Capacity revenues increased $0.5 million.

Fuel and Purchased Power Expenses


	Second Quarter 2010						Year-to-Date 2010
	vs.						vs.
	Second Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	(22.2	)		(17.7	)	$	(11.4	)		(4.6	)
Purchased power – non-affiliates		(1.4	)		(47.9	)		(0.6	)		(10.3	)
Purchased power – affiliates		12.9			59.7			5.8			13.4

Total fuel and purchased power expenses	$	(10.7	)				$	(6.2	)

In the second quarter 2010, total fuel and purchased power expenses were $139.6 million compared to $150.3 million for the corresponding period in 2009. The decrease was primarily due to a $17.4 million decrease related to the total KWHs generated and purchased, partially offset by a $6.7 million increase in the cost of fuel and purchased power.

For year-to-date 2010, total fuel and purchased power expenses were $288.7 million compared to $294.9 million for the corresponding period in 2009. The decrease was primarily due to a $5.8 million decrease related to the total KWHs generated and purchased and a $0.4 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	2010		2009		Change		2010		2009		Change
	(cents per net KWH)						(cents per net KWH)
Fuel		4.39		4.21		4.3		4.30		4.32		(0.5	)
Purchased power		3.60		3.36		7.0		3.65		3.62		0.9

In the second quarter 2010, fuel expense was $103.6 million compared to $125.8 million for the corresponding period in 2009. The decrease was primarily due to a 21.1% decrease in generation from Mississippi Power facilities resulting from outages and purchased power available at lower costs, partially offset by a 4.3% increase in the price of fuel resulting from higher natural gas prices.

For year-to-date 2010, fuel expense was $234.4 million compared to $245.8 million for the corresponding period in 2009. The decrease was primarily due to a 4.3% decrease in generation from Mississippi Power facilities resulting from outages and a 0.5% decrease in the price of fuel resulting from lower coal prices.

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Non-Affiliates

In the second quarter 2010, purchased power expense from non-affiliates was $1.5 million compared to $2.9 million for the corresponding period in 2009. The decrease was primarily the result of an 81.7% decrease in KWH volume purchased, partially offset by a 185.0% increase in the average cost of purchased power per KWH. The decrease in KWH volume was the result of higher cost opportunity purchases, while the increase in prices was due to a higher marginal cost of fuel.

For year-to-date 2010, purchased power expense from non-affiliates was $5.1 million compared to $5.7 million for the corresponding period in 2009. The decrease was primarily the result of a 67.8% decrease in KWH volume purchased, partially offset by a 178.0% increase in the average cost of purchased power per KWH. The decrease in KWH volume purchased was a result of higher cost opportunity purchases, while the increase in prices was due to a higher marginal cost of fuel.

Affiliates

In the second quarter 2010, purchased power expense from affiliates was $34.5 million compared to $21.6 million for the corresponding period in 2009. The increase was primarily due to an 82.1% increase in KWH volume purchased, partially offset by a 12.3% decrease in the average cost of purchased power per KWH.

For year-to-date 2010, purchased power expense from affiliates was $49.2 million compared to $43.4 million for the corresponding period in 2009. The increase was primarily due to a 40.5% increase in KWH volume purchased, partially offset by a 19.3% decrease in the average cost of purchased power per KWH.

Other Operations and Maintenance Expenses

In the second quarter 2010, other operations and maintenance expenses were $71.8 million compared to $61.6 million for the corresponding period in 2009. The increase was primarily due to a $7.0 million increase in planned generation maintenance expenses for several major outages, a $1.2 million increase in routine generation expenses, and a $1.0 million increase in distribution maintenance expenses.

For year-to-date 2010, other operations and maintenance expenses were $139.1 million compared to $121.4 million for the corresponding period in 2009. The increase was primarily due to an $8.9 million increase in generation planned maintenance expenses for several major outages, a $1.6 million increase in routine generation expenses, a $1.2 million increase in environmental expenses, a $2.4 million increase in transmission and distribution maintenance expenses related to substation and overhead line maintenance and vegetation management, and a $2.4 million increase in administrative and general expenses.

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Depreciation and Amortization

In the second quarter 2010, depreciation and amortization was $18.8 million compared to $17.7 million for the corresponding period in 2009. The increase is primarily due to a $0.6 million increase in ECO Plan amortization from the prior year and a $0.5 million increase in depreciation resulting from an increase in plant in service.

For year-to-date 2010, depreciation and amortization was $37.5 million compared to $35.7 million for the corresponding period in 2009. The increase is primarily due to a $0.6 million increase in ECO Plan amortization from the prior year and a $1.2 million increase in depreciation resulting from an increase in plant in service.

Taxes Other Than Income Taxes

In the second quarter 2010, taxes other than income taxes were $17.2 million compared to $16.2 million for the corresponding period in 2009. The increase was primarily due to a $0.7 million increase in ad valorem taxes and a $0.2 million increase in payroll taxes.

For year-to-date 2010, taxes other than income taxes were $35.6 million compared to $31.1 million for the corresponding period in 2009. The increase was primarily due to a $4.0 million increase in ad valorem taxes, a $0.3 million increase in payroll taxes, and a $0.2 million increase in franchise taxes.

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

Interest Expense, Net of Amounts Capitalized

In the second quarter 2010, interest expense, net of amounts capitalized was $5.9 million compared to $6.3 million for the corresponding period in 2009. The decrease was primarily due to a $0.2 million increase in AFUDC debt expense primarily associated with the Kemper IGCC project and a $0.1 million decrease related to lower commitment fees and lower interest rates associated with long-term debt.

For year-to-date 2010, interest expense, net of amounts capitalized was $12.1 million compared to $11.0 million for the corresponding period in 2009. The increase was primarily due to a $0.9 million increase in interest expense associated with the issuance of new long-term debt in March 2009 and a $0.3 million increase in interest expense related to a regulatory recovery mechanism for fuel and energy cost hedging.

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

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Income Taxes

In the second quarter 2010, income taxes were $9.1 million compared to $13.6 million for the corresponding period in 2009. For year-to-date 2010, income taxes were $18.9 million compared to $24.1 million for the corresponding period in 2009. These decreases were primarily due to lower pre-tax earnings.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

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

Carbon Dioxide Litigation

New York Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – New York Case” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – Carbon Dioxide Litigation – New York Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina.

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On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Mississippi Power in Item 7 of the Form 10-K for information regarding proposed sulfur dioxide (SO₂) regulations. On June 2, 2010, the EPA issued its final revisions to the National Ambient Air Quality Standard for SO₂, including the establishment of a new short-term standard. The ultimate impact of the revised standard will depend on additional regulatory action, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

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

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Mississippi Power in Item 7 of the Form 10-K for information regarding the Clean Air Interstate Rule (CAIR). On August 2, 2010, the EPA published a proposed rule to replace CAIR, which was overturned by the U.S. Court of Appeals for the D.C. Circuit in 2008 but left in place pending the promulgation of a replacement rule. This proposed rule, referred to as the Transport Rule, would require 31 eastern states and the District of Columbia (D.C.) to reduce power plant emissions of SO₂ and nitrogen oxides (NO_x) that contribute to downwind states’ nonattainment of federal ozone and/or fine particulate matter ambient air quality standards. To address fine particulate matter standards, the proposed Transport Rule would require D.C. and 27 eastern states, including Alabama, to reduce annual emissions of SO₂ and NO_x from power plants. To address ozone standards, the proposed Transport Rule would also require D.C. and 25 states, including Alabama and Mississippi, to achieve additional reductions in NO_x emissions from power plants during the ozone season. The proposed Transport Rule contains a “preferred option” that would allow limited interstate trading of emissions allowances; however, the EPA also requests comment on two alternative approaches that would not allow interstate trading of emissions allowances. The EPA states that it also intends to develop a second phase of the Transport Rule next year to address the more stringent ozone air quality standards as they are finalized. The EPA expects to finalize the Transport Rule in late spring of 2011 and to set the initial compliance deadline starting in 2012. The impact of this proposed regulation and potential future regulation will depend on its final form, state implementation, and the outcome of any legal challenges, and cannot be determined at this time.

Coal Combustion Byproducts

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Byproducts” of Mississippi Power in Item 7 of the Form 10-K for information regarding potential additional regulation of coal combustion byproducts. On June 21, 2010, the EPA published a rulemaking proposal which requested comments on two potential regulatory options for management

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and disposal of coal combustion byproducts: regulation as a solid waste or regulation as a hazardous waste. Adoption of either option could require closure of or significant change to existing storage units and construction of lined landfills, as well as additional waste management and groundwater monitoring requirements. Under both options, the EPA proposes to exempt the beneficial reuse of coal combustion byproducts from regulation; however, the final regulation could significantly alter the options available for beneficial reuse. The outcome of these proposed regulations will depend on their final form and the outcome of any legal challenges, and cannot be determined at this time. However, additional regulation of coal combustion byproducts could have a significant impact on Mississippi Power’s management, beneficial use, and disposal of such byproducts. These changes could result in significant additional compliance and operational costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Global Climate Issues

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

FERC and Mississippi PSC Matters

Retail Regulatory Matters

Performance Evaluation Plan

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

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

On March 15, 2010, Mississippi Power submitted its annual PEP lookback filing for 2009, which recommended no surcharge or refund. The ultimate outcome of this matter cannot now be determined.

System Restoration Rider

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

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In September 2009, the Mississippi PSC issued an order requiring Mississippi Power to develop SRR factors designed to reduce SRR revenue by approximately $1.5 million. The revised factors were in effect from November 2009 to March 2010. Beginning in April 2010, the SRR factors were reset to zero. On January 29, 2010, Mississippi Power submitted its 2010 SRR rate filing with the Mississippi PSC and expects to accrue approximately $3.0 million to the property damage reserve in 2010.

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters – Environmental Compliance Overview Plan” in Item 8 of the Form 10-K for information on Mississippi Power’s annual environmental filing with the Mississippi PSC.

On February 12, 2010, Mississippi Power submitted its 2010 ECO Plan notice which proposes an increase in annual revenues for Mississippi Power of approximately $3.9 million. In its 2010 ECO Plan filing, Mississippi Power is proposing to change the true-up provision of the ECO Plan rate schedule to consider actual revenues collected in addition to actual costs. Hearings on the ECO Plan are expected to be held with the Mississippi PSC by late 2010. The final outcome of this matter cannot now be determined.

On July 22, 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership, respectively. The estimated total cost of the project is approximately $600 million and is scheduled for completion in the fourth quarter 2014. Mississippi Power’s portion of the cost, if approved by the Mississippi PSC, is expected to be recovered through its ECO Plan. Hearings on the certificate request are expected to be held with the Mississippi PSC by late 2010. The final outcome of this matter 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. Mississippi Power establishes an annual retail fuel cost recovery factor that is approved by the Mississippi PSC. Mississippi Power is required to file for an adjustment to the retail fuel cost recovery factor annually; such filing occurred in November 2009. The Mississippi PSC approved the retail fuel cost recovery factor on December 15, 2009 with the new rates effective January 2010. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 11.3% of total 2009 retail revenues. As of June 30, 2010, the amount of over recovered retail fuel costs included in the balance sheet was $33.9 million compared to $29.4 million at December 31, 2009. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2010, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 20.9% of total 2009 MRA revenue. Effective February 1, 2010, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 16.9% of total 2009 MB revenue. As of June 30, 2010, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheet was $13.8 million and $3.0 million, respectively, compared to $16.8 million and $2.4 million, respectively, at December 31, 2009. Mississippi Power’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, this decrease to the billing factor will not have a significant effect on Mississippi Power’s revenues or net income, but will decrease annual cash flow.

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Depreciation Study

See Note 1 to the financial statements of Mississippi Power under “Depreciation and Amortization” in Item 8 of the Form 10-K for additional information. In September 2009, Mississippi Power filed a depreciation study, as of December 31, 2008, with the Mississippi PSC and the FERC. The FERC accepted this study in October 2009. On April 20, 2010, the Mississippi PSC issued an order approving the depreciation rates effective January 1, 2010.

Integrated Coal Gasification Combined Cycle

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

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

In addition to the Internal Revenue Code Section 48A Phase I tax credits of $133 million certified by the IRS in May 2009, Mississippi Power filed an application in November 2009 with the DOE and in December 2009 with the IRS for certain tax credits available to projects using advanced coal technologies under the Energy Improvement and Extension Act of 2008. The DOE subsequently certified the Kemper IGCC, and on April 30, 2010, the IRS allocated $279 million of Phase II tax credits under Section 48A of the Internal Revenue Code to Mississippi Power. The utilization of these credits is dependent upon meeting the IRS certification requirements and completing the Kemper IGCC in a timely manner. Mississippi Power has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for these credits.

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

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

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

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2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted Mississippi Power’s motion and issued a certificate of public convenience and necessity authorizing acquisition, construction, and operation of the Kemper IGCC.

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

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

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

As of June 30, 2010, Mississippi Power had spent a total of $142.4 million on the Kemper IGCC, including regulatory filing costs. Of this total, $129.1 million was included in CWIP, $11.3 million was recorded in other regulatory assets, $0.8 million was recorded in other deferred charges and assets, and $1.3 million was expensed. Upon receipt of the issuance of the final certificate order in May 2010, construction screening costs including regulatory filing costs totaled $129.0 million. As of May 31, 2010, construction related screening costs of $116.2 million were reclassified to CWIP while the non-capital related costs of $11.2 million and $0.6 million were classified in other regulatory assets and other deferred charges, respectively, and $1.0 million was previously expensed. Costs incurred for the six months ended June 30, 2010 totaled $68.9 million compared to $14.1 million for the six months ended June 30, 2009.

The ultimate outcome of these matters cannot now be determined.

Legislation

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

Healthcare Reform

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

Stimulus Funding

On April 8, 2010, Mississippi Power received notice that an award had been granted under the American Recovery and Reinvestment Act of 2009 grant application for smart grid workforce training. Mississippi Power will receive, and will match, $2.6 million under this agreement. Receipt of this award is subject to negotiation of definitive agreements with the DOE. The ultimate impact of these matters cannot be determined at this time.

On April 28, 2010, Southern Company signed a Smart Grid Investment Grant agreement with the DOE, formally accepting a $165 million grant under the American Recovery and Reinvestment Act of 2009. This funding will be used for transmission and distribution automation and modernization projects. Mississippi Power will receive, and will match, $25 million under this agreement.

Other Matters

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

The extent of coastal contamination resulting from the oil spill that began in April 2010 in the Gulf of Mexico has potential impacts on certain steam plant operations as well as potential significant economic impacts on the affected areas within Mississippi Power’s service territory. The ultimate impact of this matter cannot be determined at this time.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash used for operating activities totaled $5.1 million for the first six months of 2010, compared to $23.8 million for the corresponding period in 2009. The $18.7 million decrease in cash used for operating activities was primarily due to an increase in cash from fossil fuel stock of $40.5 million primarily resulting from an a decrease in cash payments related to fuel inventory, and an increase in accounts payable of $20.6 million primarily due to timing of cash payments. These increases in cash were partially offset by an increase in spending related to the Kemper IGCC generation construction screening costs of $36.5 million and a decrease in cash related to lower fuel rates effective in the first quarter 2010. Net cash used for investing activities totaled $58.5 million for the first six months of 2010, compared to $64.4 million for the corresponding period in 2009. The $5.9 million decrease in net cash used for investing activities was primarily due to an increase in construction payables. Net cash provided from financing activities totaled $4.9 million for the first six months of 2010, compared to net cash provided from financing activities of $70.8 million for the corresponding period in 2009. The $65.9 million decrease in net cash provided from financing activities was primarily due to the issuance of $125 million in senior notes in the first quarter 2009, partially offset by the repayment of $40 million of senior notes and an increase of $18.5 million in notes payable in the second quarter 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2010 include a decrease in cash and cash equivalents of $58.7 million. Total property, plant, and equipment increased by $148.6 million primarily due to the increase in CWIP related to the Kemper IGCC. The capital expenditures of $116.2 million associated with the Kemper IGCC generation screening costs as of May 31, 2010 were reclassified from other regulatory assets, deferred to CWIP upon the Mississippi PSC’s issuance of the final certificate order for the project. Securities due within one year increased by $80.1 million primarily due to the reclassification of a long term bank loan maturing in March 2011. Notes payable increased by $39.0 million primarily due to an increase in commercial paper borrowings. Accrued income taxes increased by $16.9 million primarily due to the tax accrual for 2010. Other accrued taxes decreased by $20.4 million primarily due to property tax payments of $42.8 million in the first quarter 2010, partially offset by a $23.3 million property tax accrual for 2010.

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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 Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $81.4 million will be required through June 30, 2011 to fund maturities of long-term debt. The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; changes in generating plants to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

Mississippi Power’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, 2010 cash and cash equivalents of $6.3 million and unused committed credit arrangements with banks of $161.0 million. Of the unused credit arrangements, $56.0 million expire in 2010 and $105.0 million expire in 2011. Of these credit arrangements, $41.0 million contain provisions allowing two-year term loans executable at expiration and $65.0 million contain provisions allowing one-year term loans executable at expiration. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Mississippi Power’s commercial paper program and $41.0 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Mississippi Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and other Southern Company subsidiaries. At June 30, 2010, Mississippi Power had $39.0 million of commercial paper borrowings 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

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lease of a combined cycle generating facility at Plant Daniel. In April 2010, Mississippi Power was required to notify the lessor, Juniper Capital L.P., if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the units or renew the lease. Mississippi Power will have to provide notice of its intent to either renew the lease or purchase the facility by July 2011. The ultimate outcome of this matter cannot be determined at this time.

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At June 30, 2010, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $2 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $371 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.

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

On June 17, 2010, Moody’s placed the issuer and long-term debt ratings of Mississippi Power (A1 senior unsecured) on review for a possible downgrade. Moody’s also placed the P-1 short-term rating of a Southern Company financing subsidiary that issues commercial paper for the benefit of Mississippi Power and other Southern Company subsidiaries on review for a possible downgrade. In addition, Moody’s placed the preferred stock and variable rate demand obligation ratings of Mississippi Power (A3 and VMIG1) on review for a possible downgrade. Moody’s announced that it did not expect the review to result in more than a one notch downgrade of any of these ratings. The ultimate outcome of this matter cannot be determined at this time.

Market Price Risk

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

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

Due to cost-based rate regulation, Mississippi Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the

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wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power had no material change in market risk exposure for the second quarter 2010 when compared with the December 31, 2009 reporting period.

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


	Second Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(59	)	$	(42	)
Contracts realized or settled		11			17
Current period changes^(a)		—			(23	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(48	)	$	(48	)


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

The change in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2010 was an increase of $11 million and a decrease of $6 million, respectively, substantially all of which is due to natural gas positions. The change is attributable to the price of natural gas. At June 30, 2010, Mississippi Power had a net hedge volume of 22 million mmBtu with a weighted average contract cost of approximately $2.24 per mmBtu above market prices, compared to 23 million mmBtu at March 31, 2010 with a weighted average contract cost of approximately $2.62 per mmBtu above market prices and compared to 23 million mmBtu at December 31, 2009 with a weighted average contract cost of approximately $1.83 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the energy cost management clause.

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

Unrealized pre-tax gains and losses recognized in income for the three and six months ended June 30, 2010 and 2009 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, 2010 are as follows:


	June 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(48	)		(23	)		(25	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(48	)	$	(23	)	$	(25	)	$	—

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.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	153,989		$	90,877		$	307,326		$	185,489
Wholesale revenues, affiliates		92,784			137,718			194,541			273,002
Other revenues		1,703			2,003			3,097			3,624

Total operating revenues		248,476			230,598			504,964			462,115

Operating Expenses:
Fuel		76,678			51,731			174,192			117,512
Purchased power, non-affiliates		15,622			24,778			34,164			46,260
Purchased power, affiliates		25,009			13,860			48,420			29,062
Other operations and maintenance		38,007			34,966			76,885			67,939
Depreciation and amortization		28,892			27,198			58,001			51,537
Taxes other than income taxes		5,137			4,789			10,243			9,548

Total operating expenses		189,345			157,322			401,905			321,858

Operating Income		59,131			73,276			103,059			140,257
Other Income and (Expense):
Interest expense, net of amounts capitalized		(19,553	)		(21,592	)		(39,607	)		(43,151	)
Other income (expense), net		(108	)		(23	)		311			(234	)

Total other income and (expense)		(19,661	)		(21,615	)		(39,296	)		(43,385	)

Earnings Before Income Taxes		39,470			51,661			63,763			96,872
Income taxes		9,766			20,607			19,249			37,902

Net Income	$	29,704		$	31,054		$	44,514		$	58,970

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months					For the Six Months
	Ended June 30,					Ended June 30,
	2010			2009		2010		2009
	(in thousands)					(in thousands)
Net Income	$	29,704		$	31,054	$	44,514	$	58,970
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1,303), $-, $410, and $302, respectively		(2,036	)		—		641		466
Reclassification adjustment for amounts included in net income, net of tax of $990, $931, $1,993, and $1,866, respectively		1,546			1,435		3,113		2,875

Total other comprehensive income (loss)		(490	)		1,435		3,754		3,341

Comprehensive Income	$	29,214		$	32,489	$	48,268	$	62,311

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Six Months
	Ended June 30,
	2010			2009
	(in thousands)
Operating Activities:
Net income	$	44,514		$	58,970
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		64,467			57,610
Deferred income taxes		18,173			24,442
Convertible investment tax credits received		22,150			—
Deferred revenues		(23,439	)		(21,070	)
Mark-to-market adjustments		(1,233	)		991
Accumulated billings on construction contract		401			24,565
Accumulated costs on construction contract		(20	)		(31,113	)
Other, net		3,126			3,834
Changes in certain current assets and liabilities —
-Receivables		(49,768	)		(50,026	)
-Fossil fuel stock		6,176			1,389
-Materials and supplies		3,950			(1,826	)
-Prepaid income taxes		(10,683	)		5,510
-Other current assets		1,739			1,493
-Accounts payable		1,920			(15,940	)
-Accrued taxes		7,815			8,642
-Accrued interest		12			27
-Other current liabilities		326			(158	)

Net cash provided from operating activities		89,626			67,340

Investing Activities:
Property additions		(129,312	)		(7,835	)
Sale of property		—			52
Change in construction payables		19,138			(1,624	)
Payments pursuant to long-term service agreements		(15,988	)		(15,450	)
Other investing activities		(249	)		(184	)

Net cash used for investing activities		(126,411	)		(25,041	)

Financing Activities:
Increase in notes payable, net		85,972			—
Proceeds — Capital contributions		1,626			1,680
Payment of common stock dividends		(53,550	)		(53,050	)

Net cash provided from (used for) financing activities		34,048			(51,370	)

Net Change in Cash and Cash Equivalents		(2,737	)		(9,071	)
Cash and Cash Equivalents at Beginning of Period		7,152			37,894

Cash and Cash Equivalents at End of Period	$	4,415		$	28,823

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $4,370 and $163 capitalized for 2010 and 2009, respectively)	$	33,274		$	37,508
Income taxes (net of refunds)	$	(10,536	)	$	7,725

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	At June 30,		At December 31,
Assets	2010		2009
	(in thousands)
Current Assets:
Cash and cash equivalents	$	4,415	$	7,152
Receivables —
Customer accounts receivable		83,044		28,873
Other accounts receivable		2,996		2,064
Affiliated companies		35,874		38,561
Fossil fuel stock, at average cost		10,111		15,351
Materials and supplies, at average cost		27,657		31,607
Prepaid service agreements — current		18,805		44,090
Prepaid income taxes		15,891		5,177
Other prepaid expenses		1,437		3,176
Assets from risk management activities		6,357		4,901
Other current assets		4,400		6,754

Total current assets		210,987		187,706

Property, Plant, and Equipment:
In service		3,030,908		2,994,463
Less accumulated provision for depreciation		480,637		439,457

Plant in service, net of depreciation		2,550,271		2,555,006
Construction work in progress		271,461		153,982

Total property, plant, and equipment		2,821,732		2,708,988

Other Property and Investments:
Goodwill		1,835		1,794
Other intangible assets, net of amortization of $302 and $17 at June 30, 2010 and December 31, 2009, respectively		48,818		49,102

Total other property and investments		50,653		50,896

Deferred Charges and Other Assets:
Prepaid long-term service agreements		70,682		74,513
Other deferred charges and assets — affiliated		3,408		3,540
Other deferred charges and assets — non-affiliated		15,793		17,410

Total deferred charges and other assets		89,883		95,463

Total Assets	$	3,173,255	$	3,043,053

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	At June 30,			At December 31,
Liabilities and Stockholder’s Equity	2010			2009
	(in thousands)
Current Liabilities:
Notes payable	$	204,920		$	118,948
Accounts payable —
Affiliated		72,223			58,493
Other		30,848			31,128
Accrued taxes —
Accrued income taxes		1,820			1,449
Other accrued taxes		10,607			2,576
Accrued interest		29,935			29,923
Liabilities from risk management activities		6,865			8,119
Other current liabilities		325			323

Total current liabilities		357,543			250,959

Long-term Debt		1,297,734			1,297,607

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		258,315			238,293
Deferred convertible investment tax credits		38,950			16,800
Deferred capacity revenues — affiliated		13,200			36,369
Other deferred credits and liabilities — affiliated		5,133			5,651
Other deferred credits and liabilities — non-affiliated		10,914			2,252

Total deferred credits and other liabilities		326,512			299,365

Total Liabilities		1,981,789			1,847,931

Common Stockholder’s Equity:
Common stock, par value $.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		866,087			864,462
Retained earnings		343,026			352,061
Accumulated other comprehensive loss		(17,647	)		(21,401	)

Total common stockholder’s equity		1,191,466			1,195,122

Total Liabilities and Stockholder’s Equity	$	3,173,255		$	3,043,053

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

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

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

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income

Southern Power’s net income for the second quarter 2010 was $29.7 million compared to $31.1 million for the corresponding period in 2009. This decrease was primarily due to lower revenues associated with the expiration of PPAs covering Plant Wansley Units 6 and 7 in December 2009 and higher operations and maintenance expenses. These decreases were partially offset by higher revenues on energy sales that were not covered by PPAs, lower interest expense, and higher tax benefits associated with the construction of Plant Nacogdoches.

Southern Power’s net income for year-to-date 2010 was $44.5 million compared to $59.0 million for the corresponding period in 2009. This decrease was primarily due to lower revenues associated with the expiration of PPAs covering Plant Wansley Units 6 and 7 in December 2009, higher operations and maintenance expenses, and higher depreciation and amortization. These decreases were partially offset by higher revenues on energy sales that were not covered by PPAs, lower interest expense, and higher tax benefits associated with the construction of Plant Nacogdoches.

Wholesale Revenues – Non-Affiliates

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

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Wholesale energy sales to non-affiliates for the second quarter 2010 were $154.0 million compared to $90.9 million for the corresponding period in 2009. The increase was mainly due to $52.1 million of energy and capacity revenues under new PPAs that began in January and June 2010 and $25.0 million of energy sales that were not covered by PPAs as a result of more favorable weather in the second quarter 2010 compared to the corresponding period in 2009. These increases were partially offset by a $13.8 million decrease in power sales under the IIC.

Wholesale energy sales to non-affiliates for year-to-date 2010 were $307.3 million compared to $185.5 million for the corresponding period in 2009. The increase was mainly due to $73.8 million of energy and capacity revenues under new PPAs that began in January and June 2010, $5.6 million of energy sales under requirements contracts, and $60.3 million of energy sales that were not covered by PPAs due to more favorable weather year-to-date 2010 compared to the corresponding period in 2009. These increases were partially offset by a $16.8 million decrease in power sales under the IIC.

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

Wholesale Revenues – Affiliates

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 2010 were $92.8 million compared to $137.7 million for the corresponding period in 2009. The decrease was primarily the result of $55.7 million of lower energy and capacity revenues associated with the expiration of PPAs covering Plant Wansley Units 6 and 7 in December 2009. These decreases were partially offset by increased energy revenues of $14.2 million related to increased power sales under the IIC.

Wholesale revenues from affiliates for year-to-date 2010 were $194.5 million compared to $273.0 million for the corresponding period in 2009. The decrease was primarily the result of $113.7 million of lower energy and capacity revenues associated with the expiration of PPAs covering Plant Wansley Units 6 and 7 in December 2009. These decreases were partially offset by increased energy revenues of $35.1 million related to increased power sales under the IIC.

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

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Fuel and Purchased Power Expenses


	Second Quarter 2010						Year-to-Date 2010
	vs.						vs.
	Second Quarter 2009						Year-to-Date 2009
	(change in millions)			(% change)			(change in millions)			(% change)
Fuel	$	25.0			48.2		$	56.7			48.2
Purchased power – non-affiliates		(9.2	)		(37.0	)		(12.1	)		(26.1	)
Purchased power – affiliates		11.1			80.4			19.4			66.6

Total fuel and purchased power expenses	$	26.9					$	64.0

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

In the second quarter 2010, total fuel and purchased power expenses were $117.3 million compared to $90.4 million for the corresponding period in 2009. Fuel and purchased power expenses increased $20.1 million due to a 23.3% increase in the average cost of natural gas and a 16.0% increase in the average cost of purchased power. Additionally, fuel and purchased power expenses increased $6.8 million due to an increase in KWHs generated and purchased.

For year-to-date 2010, total fuel and purchased power expenses were $256.8 million compared to $192.8 million for the corresponding period in 2009. Fuel and purchased power expenses increased $37.8 million due to a 12.4% increase in the average cost of natural gas and a 28.3% increase in the average cost of purchased power. Additionally, fuel and purchased power expenses increased $26.2 million due to an increase in KWHs generated and purchased.

In the second quarter 2010, fuel expense was $76.7 million compared to $51.7 million for the corresponding period in 2009. Fuel expense increased $14.5 million due to a 23.3% increase in the average cost of natural gas and $10.5 million due to an increase in KWHs generated.

For year-to-date 2010, fuel expense was $174.2 million compared to $117.5 million for the corresponding period in 2009. Fuel expense increased $19.5 million due to a 12.4% increase in the average cost of natural gas and $37.2 million due to an increase in KWHs generated.

In the second quarter 2010, purchased power expense was $40.6 million compared to $38.6 million for the corresponding period in 2009. Purchased power expenses increased $5.6 million due to an increase in the average cost of purchased power, partially offset by a $3.6 million decrease due to fewer KWHs purchased.

For year-to-date 2010, purchased power expense was $82.6 million compared to $75.3 million for the corresponding period in 2009. Purchased power expenses increased $18.2 million due to an increase in the average cost of purchased power, partially offset by a $10.9 million decrease due to fewer KWHs purchased.

Other Operations and Maintenance Expenses

In the second quarter 2010, other operations and maintenance expenses were $38.0 million compared to $35.0 million for the corresponding period in 2009. This increase was primarily related to additional expense associated with employee benefits.

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For year-to-date 2010, other operations and maintenance expenses were $76.9 million compared to $67.9 million for the corresponding period in 2009. This increase was primarily due to $4.1 million of additional expense associated with the passage of healthcare legislation in March 2010, $3.3 million related to generating plant outages and maintenance, and $1.2 million related to salaries and wages, primarily payroll taxes.

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

Depreciation and Amortization

In the second quarter 2010, depreciation and amortization was $28.9 million compared to $27.2 million for the corresponding period in 2009. The increase was primarily related to $1.5 million associated with the acquisition of West Georgia Generating Company LLC (West Georgia) and the divestiture of DeSoto County Generating Company LLC (DeSoto) which resulted in an increase in property, plant, and equipment of approximately $120.2 million. The increase was also due to $0.7 million of equipment retirements and $0.4 million related to other increases in property, plant, and equipment. These increases were partially offset by a $1.0 million decrease related to changes in depreciation rates.

For year-to-date 2010, depreciation and amortization was $58.0 million compared to $51.5 million for the corresponding period in 2009. The increase was primarily related to $3.2 million associated with the West Georgia/DeSoto acquisition/divestiture described above, $4.8 million of equipment retirements, and $0.7 million related to other increases in property, plant, and equipment. These increases were partially offset by a $2.2 million decrease related to changes in depreciation rates.

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

Interest Expense, Net of Amounts Capitalized

In the second quarter 2010, interest expense, net of amounts capitalized was $19.6 million compared to $21.6 million for the corresponding period in 2009. This decrease was primarily related to $2.4 million of additional capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant, partially offset by $0.2 million associated with an increase in interest expense on commercial paper and $0.2 million associated with interest rate swaps on senior notes.

For year-to-date 2010, interest expense, net of amounts capitalized was $39.6 million compared to $43.2 million for the corresponding period in 2009. This decrease was primarily related to $4.2 million of additional capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant, partially offset by $0.3 million associated with an increase in interest expense on commercial paper and $0.4 million associated with interest rate swaps on senior notes.

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

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Income Taxes

In the second quarter 2010, income taxes were $9.8 million compared to $20.6 million for the corresponding period in 2009. The decrease was primarily due to $5.0 million associated with lower pre-tax earnings and $2.9 million of tax benefits associated with the construction of Plant Nacogdoches.

For year-to-date 2010, income taxes were $19.2 million compared to $37.9 million for the corresponding period in 2009. The decrease was primarily due to $13.1 million associated with lower pre-tax earnings and $5.1 million of tax benefits associated with the construction of Plant Nacogdoches.

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

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power’s future earnings potential. The level of Southern Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power’s competitive wholesale business. These factors include Southern Power’s ability to achieve sales growth while containing costs. The level of future earnings also depends on numerous factors including regulatory matters (such as those related to affiliate contracts), creditworthiness of customers, total generating capacity available in the Southeast, the successful remarketing of capacity as current contracts expire, and Southern Power’s ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. Recessionary conditions have lowered demand and have negatively impacted capacity revenues under Southern Power’s PPAs where the amounts purchased are based on demand. Southern Power is unable to predict whether demand under these PPAs will return to pre-recession levels. The timing and extent of the economic recovery will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Environmental Matters

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

Air Quality

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be designated as nonattainment for the standard, based on current ambient air quality monitoring data, the new NO₂ standard could result in significant additional compliance and operational costs for units that require new source permitting.

Carbon Dioxide Litigation

Other Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Other Litigation” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Carbon Dioxide Litigation – Other Litigation” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation related to Hurricane Katrina. On May 28, 2010, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.

Environmental Statutes and Regulations

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

Global Climate Issues

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

Legislation

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Legislation” of Southern Power in Item 7 of the Form 10-K for additional information. On March 23, 2010, the Patient Protection and Affordable Care Act (PPACA) was signed into law and, on March 30, 2010, the Health Care and Education

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

Construction Projects

Cleveland County Units 1-4

In December 2008, Southern Power announced that it would build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total capacity of 720 MWs. The units are expected to go into commercial operation in 2012. Costs incurred through June 30, 2010 were $103.1 million. The total estimated construction cost is expected to be between $350 million and $400 million.

Nacogdoches

On October 8, 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power LLC from American Renewables LLC, the original developer of the project. Nacogdoches is constructing a biomass generating plant in Sacul, Texas with an estimated capacity of 100 MWs. The generating plant will be fueled from wood waste. Construction commenced in 2009 and the plant is expected to begin commercial operation in 2012. Costs incurred through June 30, 2010 were $167.7 million. The total estimated cost of the project is expected to be between $475 million and $500 million.

Other Matters

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $89.6 million for the first six months of 2010, compared to $67.3 million for the corresponding period in 2009. The $22.3 million increase was mainly due to an increase in accounts payable associated with an increase in the volume of fuel purchased and an increase in convertible investment tax credits. Net cash used for investing activities totaled $126.4 million for the first six months of 2010, compared to $25.0 million for the corresponding period in 2009. The $101.4 million increase was primarily due to an increase in construction work in progress related to construction activities at Cleveland County and Nacogdoches. Net cash provided from financing activities totaled $34.0 million for the first six months of 2010, compared to $51.4 million cash used for financing activities for the corresponding period in 2009. The increase was primarily due to an increase in short-term borrowings in 2010. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

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

Significant liability and stockholder’s equity changes in the balance sheet for the first six months of 2010 include an increase in notes payable mainly related to Cleveland County and Nacogdoches construction activities.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Power in Item 7 of the Form 10-K for a description of Southern Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. The construction program is subject to

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

Sources of Capital

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

Southern Power’s current liabilities frequently exceed current assets due to the use of short-term indebtedness as a funding source to meet cash needs which can fluctuate significantly due to the seasonality of the business. To meet liquidity and capital resource requirements, Southern Power had at June 30, 2010 cash and cash equivalents of approximately $4.4 million and committed credit arrangements with banks of $400 million, all of which expire in 2012. Proceeds from these credit arrangements may be used for working capital and general corporate purposes as well as liquidity support for Southern Power’s commercial paper program. See Note 6 to the financial statements of Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Southern Power’s commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. At June 30, 2010, Southern Power had $204.9 million of commercial paper borrowings 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

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, 2010, the maximum potential collateral requirements under these contracts at a BBB and Baa2 rating were approximately $9 million and at a BBB- and/or Baa3 rating were approximately $340 million. At June 30, 2010, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.1 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Power’s ability to access capital markets, particularly the short-term debt market.

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

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Market Price Risk

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

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

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

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


	Second Quarter			Year-to-Date
	2010			2010
	Changes			Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	0.1		$	(3.5	)
Contracts realized or settled		—			0.5
Current period changes^(a)		(1.3	)		1.8

Contracts outstanding at the end of the period, assets (liabilities), net	$	(1.2	)	$	(1.2	)

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

The changes in the fair value positions of the energy-related derivative contracts for the three and six months ended June 30, 2010 were a decrease of $1.3 million and an increase of $2.3 million, respectively, which is due to both power and natural gas positions. This change is attributable to both the volume and prices of power and natural gas as follows:


	June 30,		March 31,			December 31,
	2010		2010			2009

Power (net sold)

MWHs (in millions)		0.7		1.3			2.7
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	6.77	$	9.03		$	(0.36	)

Natural gas (net purchase)

Commodity – million mmBtu		5.6		6.4			8.3
Location basis – million mmBtu		—		1.2			2.0

Commodity – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	1.31	$	2.41		$	0.29

Location basis – Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	—	$	(0.03	)	$	(0.04	)

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


Asset (Liability) Derivatives	June 30, 2010			December 31, 2009
	(in millions)
Cash flow hedges	$	(1.4	)	$	(2.5	)
Not designated		0.2			(1.0	)

Total fair value	$	(1.2	)	$	(3.5	)

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

Total net unrealized pre-tax gains recognized in income for the three and six months ended June 30, 2010 for energy-related derivative contracts that are not hedges were $2.0 million and $1.2 million, respectively, and will continue to be marked to market until the settlement date. For the three months ended June 30, 2009, the total net unrealized pre-tax gains (losses) recognized in the statements of income were immaterial. For the six months ended June 30, 2009, the total net unrealized pre-tax losses recognized in the statements of income were $1.0 million.

The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at June 30, 2010 are as follows:


	June 30, 2010
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(1.2	)		(0.5	)		(0.8	)		0.1
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(1.2	)	$	(0.5	)	$	(0.8	)	$	0.1

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

For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Southern Power in Item 7 and Note 1 under “Financial Instruments” and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

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

134

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(A)

INTRODUCTION

			The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2009 have been derived from the audited financial statements of each registrant. In the opinion of each registrant’s management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2010 and 2009. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

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

			Affiliate Transactions

			In January 2010, Gulf Power purchased turbine rotor assembly parts owned by Georgia Power and Southern Power for approximately $4 million and $6 million, respectively. In June 2010, Mississippi Power purchased a turbine rotor assembly part from Gulf Power for approximately $6 million. These affiliate transactions were in accordance with FERC and state PSC rules and guidelines.


			Variable Interest Entities

			Effective January 1, 2010, the traditional operating companies and Southern Power adopted new accounting guidance which modified the consolidation model and expanded disclosures related to variable interest entities (VIE). The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the traditional operating companies or Southern Power consolidating any VIEs that were not already consolidated under previous guidance, nor deconsolidating any VIEs.

			Southern Power has certain wholly-owned subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.

(B)

CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

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			General Litigation Matters

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

			Mirant Matters

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

			In July 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Texas. The Bankruptcy Court entered an order confirming Mirant’s plan of reorganization in December 2005, and Mirant announced that this plan became effective in January 2006. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant).

			Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for certain costs. As a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in Mirant’s Chapter 11 proceeding. If Southern Company’s claims for indemnification with respect to these costs are allowed, then Mirant’s indemnity obligations to Southern Company would constitute unsecured claims against Mirant entitled to stock in Reorganized Mirant. As a result of the $202 million settlement in March 2009 of another suit related to Mirant (MC Asset Recovery litigation), the maximum amount Southern Company can assert by proof of claim in the Mirant bankruptcy is capped at $9.5 million. See Note 5 to the financial statements of Southern Company under “Effective Tax Rate” in Item 8 of the Form 10-K for more information regarding the MC Asset Recovery litigation settlement. By settlement agreement, dated as of July 7, 2010, substantially all the claims filed by Southern Company against Mirant have been resolved. Pursuant to the agreement, Southern Company will be given allowed unsecured claims against Mirant in the aggregate amount of approximately $8.8 million, which claims will be treated pursuant to the terms of the Mirant plan of reorganization. The parties also released each other from any other claims arising from events or conduct prior to the effective date of Mirant’s plan of reorganization, with certain limited exceptions. Mirant has requested bankruptcy court approval of the settlement and the matter is scheduled to be heard on August 26, 2010. The final outcome of this matter cannot now be determined.

			Environmental Matters

			*New Source Review Actions*

			In November 1999, the EPA brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the NSR provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. After Alabama Power was dismissed from the original action, the EPA filed a separate action in January 2001 against Alabama Power in the U.S. District Court for the Northern District of Alabama. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power and Georgia Power, including

137

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			facilities co-owned by Mississippi Power and Gulf Power. The civil actions request penalties and injunctive relief, including an order requiring installation of the best available control technology at the affected units. The EPA concurrently issued notices of violation to Gulf Power and Mississippi Power relating to Gulf Power’s Plant Crist and Mississippi Power’s Plant Watson. In early 2000, the EPA filed a motion to amend its complaint to add Gulf Power and Mississippi Power as defendants based on the allegations in the notices of violation. However, in March 2001, the court denied the motion based on lack of jurisdiction, and the EPA has not re-filed. The original action, now solely against Georgia Power, has been administratively closed since the spring of 2001, and the case has not been reopened.

			In June 2006, the U.S. District Court for the Northern District of Alabama entered a consent decree between Alabama Power and the EPA, resolving a portion of the Alabama Power lawsuit relating to the alleged NSR violations at Plant Miller. In July 2008, the U.S. District Court for the Northern District of Alabama granted partial summary judgment in favor of Alabama Power with respect to its other affected units regarding the proper legal test for determining whether projects are routine maintenance, repair, and replacement and therefore are excluded from NSR permitting. The decision did not resolve the case, which remains ongoing.

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

			*Carbon Dioxide Litigation*

			New York Case

			In July 2004, three environmental groups and attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed complaints in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. The plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit in October 2005 and, in September 2009, the U.S. Court of Appeals for the Second Circuit reversed the district court’s ruling, vacating the dismissal of the plaintiffs’ claim, and remanding the case to the district court. In November 2009, the defendants, including Southern Company, sought rehearing en banc. The U.S. Court of Appeals for the Second Circuit denied the defendants’ petition for rehearing en banc on March 5, 2010 and granted the defendants’ request to stay the mandate to allow the defendants to file a petition for writ of certiorari with the U.S. Supreme Court on March 16, 2010. On August 2, 2010, the defendants filed a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of these matters cannot be determined at this time.

			Kivalina Case

			In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of

138

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. The ultimate outcome of this matter cannot be determined at this time.

			Other Litigation

			Common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas emissions have become more frequent, and courts have recently determined that private parties and states have standing to bring such claims. For example, in October 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi’s dismissal of private party claims against certain oil, coal, chemical, and utility companies alleging damages as a result of Hurricane Katrina. In reversing the dismissal, the U.S. Court of Appeals for the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass, and negligence claims and none of these claims are barred by the political question doctrine. On May 28, 2010, however, the U.S. Court of Appeals for the Fifth Circuit dismissed the plaintiffs’ appeal of the case based on procedural grounds relating to the loss of a quorum by the full court on reconsideration, reinstating the district court decision in favor of the defendants. The plaintiffs have until August 26, 2010 to file a petition for writ of certiorari with the U.S. Supreme Court. Southern Company is not currently a party to this litigation, but the traditional operating companies and Southern Power were named as defendants in an amended complaint which was rendered moot in August 2007 by the U.S. District Court for the Southern District of Mississippi when such court dismissed the original matter. The ultimate outcome of this matter cannot be determined at this time.

			Environmental Remediation

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

			Georgia Power’s environmental remediation liability as of June 30, 2010 was $14.1 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; however, they are not expected to have a material impact on Georgia Power’s financial statements.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $63.1 million as of June 30, 2010. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power’s environmental cost recovery clause; therefore, there was no impact on net income as a result of these estimates.

			In 2003, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power’s transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with Mississippi Power and several other utilities to investigate and remediate the site. Amounts expensed related to this work were not material. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The final impact of this matter on Mississippi Power will depend upon further environmental assessment and the ultimate number of PRPs. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan.

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

			FERC Matters

			*Market-Based Rate Authority*

			Each of the traditional operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

			In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation market power within its retail service territory. The ability to charge market-based rates in other markets was not an issue in the proceeding. Any new market-based rate sales by any subsidiary of Southern Company in Southern Company’s retail service territory entered into during a 15-month refund period that ended in May 2006 could have been subject to refund to a cost-based rate level.

			In December 2009, Southern Company and the FERC trial staff reached an agreement in principle that would resolve the proceeding in its entirety. The agreement does not reflect any finding or suggestion that any subsidiary of Southern Company possesses or has exercised any market power. The agreement likewise does not require Southern Company to make any refunds related to sales during the 15-month refund period. The agreement does provide for the traditional operating companies and Southern Power to donate a total of $1.7 million to nonprofit organizations in the states in which they operate for the purpose of offsetting the electricity bills of low-income retail customers. The joint offer of settlement was filed on March 2, 2010. On July 13, 2010, the FERC issued an order approving the filed settlement, finding it to be fair, reasonable, and in the public interest. There is a 30-day period within which a rehearing request may be filed. If the 30-day period expires and no rehearing request has been filed, then the payment shall be made within 15 days after the order becomes final and non-appealable.

			*Intercompany Interchange Contract*

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

140

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct.

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

			Right of Way Litigation

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

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

			In addition, in late 2001, certain subsidiaries of Southern Company, including Mississippi Power, were named as defendants in a lawsuit brought in Troup County, Georgia, Superior Court by Interstate Fiber Network, a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses rights of way. This lawsuit alleges, among other things, that the defendants are contractually obligated to indemnify, defend, and hold harmless the telecommunications company from any liability that may be assessed against it in pending and future right of way litigation. Southern Company and Mississippi Power believe that the plaintiff’s claims are without merit. In the fall of 2004, the trial court stayed the case until resolution of the underlying landowner litigation discussed above. In January 2005, the Georgia Court of Appeals dismissed the telecommunications company’s appeal of the trial court’s order for lack of jurisdiction. 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 approximately $30 million, based on its ownership interests, and awarded Alabama Power approximately $17 million, representing substantially all of the direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley, Hatch, and Vogtle from 1998 through 2004. In November 2007, the government’s motion for reconsideration was denied. In January 2008, the government filed an appeal and, in February 2008, filed a motion to stay the appeal, which the U.S. Court of Appeals for the Federal Circuit granted in April 2008. On May 5, 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			In April 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim), due to the government’s alleged continuing breach of contract. In October 2008, the U.S. Court of Appeals for the Federal Circuit denied a similar request by the government to stay this proceeding. The complaint does not contain any specific dollar amount for recovery of damages. Damages will continue to accumulate until the issue is resolved or the storage is provided. No amounts have been recognized in the financial statements as of June 30, 2010 for either claim. The final outcome of these matters cannot be determined at this time, but no material impact on net income is expected as any damage amounts collected from the government are expected to be returned to customers.

			Income Tax Matters

			*Georgia State Income Tax Credits*

			Georgia Power’s 2005 through 2008 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power had also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue has not responded to these claims. In July 2007, Georgia Power filed a complaint in the Superior Court of Fulton County to recover the credits claimed for the years 2002 through 2004. On March 22, 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. On April 30, 2010, the Georgia Department of Revenue filed its notice of appeal with the Georgia Court of Appeals. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s or Georgia Power’s net income is expected, as a significant portion of any tax benefit is expected to be returned to Georgia Power’s retail customers. If Georgia Power is not successful, payment of the related state tax could have a significant, and possibly material, negative effect on Georgia Power’s and Southern Company’s cash flow. See Note 5 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K under “Unrecognized Tax Benefits” and Note (G) herein for additional information. The ultimate outcome of this matter cannot now be determined.

			Retail Regulatory Matters

			*Rate Plans*

			See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” and of Southern Company under “Retail Regulatory Matters – Georgia Power – Retail Rate Plans” and “– Cost of Removal” in Item 8 of the Form 10-K for information regarding the 2007 Retail Rate Plan.

			On August 27, 2009, the Georgia PSC approved an accounting order that would allow Georgia Power to amortize up to $324 million of its regulatory liability related to other cost of removal obligations. Under the terms of the accounting order, Georgia Power was entitled to amortize up to one-third of the regulatory liability ($108 million) in 2009, limited to the amount needed to earn no more than a 9.75% retail return on equity (ROE). In addition, Georgia Power may amortize up to two-thirds of the regulatory liability ($216 million) in 2010, limited to the amount needed to earn no more than a 10.15% retail ROE. Through June 30, 2010, Georgia Power had amortized $155.3 million of the regulatory liability.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

	•		Continuation of a plus or minus 100 basis point range for ROE.

	•		Creation of an Adjustable Cost Recovery (ACR) tariff. If approved, beginning with an effective date of January 1, 2012, the ACR will work to maintain Georgia Power’s earnings within the ROE band established by the Georgia PSC in this case. If Georgia Power’s earnings projected for the upcoming year are within the ROE band, no adjustment under the ACR tariff will be requested. If Georgia Power’s earnings projected for the upcoming year are outside (either above or below) the approved ROE band, the ACR tariff will be used to adjust projected earnings back to the mid-point of the approved ROE band.

			The ACR tariff would also return to the sharing mechanism used prior to the 2007 Retail Rate Plan whereby two-thirds of any actual earnings for the previous year above the approved ROE band would be refunded to customers, with the remaining one-third retained by Georgia Power as incentive to manage expenses and operate as efficiently as possible. In addition, if earnings are below the approved ROE band, Georgia Power would accept one-third of the shortfall and retail customers would be responsible for the remaining two-thirds.

	•		Creation of a new Certified Capacity Cost Recovery (CCCR) tariff to recover costs related to new capacity additions certified by the Georgia PSC and updated through applicable project construction monitoring reports and hearings.

	•		Continuation and enhancement of the ECCR and DSM-Residential tariffs from the 2007 Retail Rate Plan and creation of a DSM-Commercial tariff to recover environmental capital and operating costs resulting from governmental mandates and DSM costs approved and certified by the Georgia PSC.

	•		Implementation of an annual review of the MFF tariff to adjust for changes in relative gross receipts between customers served inside and outside municipal boundaries.

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

			Georgia Power expects the Georgia PSC to issue a final order in this matter during December 2010. The final outcome of this matter cannot now be determined.

			*Fuel Cost Recovery*

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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

			*Nuclear Construction*

			See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Construction – Nuclear,” respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power’s construction of two nuclear generating units at Plant Vogtle.

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

			In August 2009 and June 2010, the NRC issued letters to Westinghouse revising the review schedules needed to certify the AP1000 standard design for new reactors and expressing concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. Georgia Power is continuing to work with Westinghouse and the NRC to resolve these concerns. Any possible delays in the AP1000 design certification schedule, including those addressed by the NRC in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units 3 and 4.

			There are pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4. Similar additional challenges at the state and federal level are expected as construction proceeds.

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

			*Other Construction*

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

			On May 6, 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand.

			*Integrated Coal Gasification Combined Cycle*

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

144

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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

			In addition to the Internal Revenue Code Section 48A Phase I tax credits of $133 million certified by the IRS in May 2009, Mississippi Power filed an application in November 2009 with the DOE and in December 2009 with the IRS for certain tax credits available to projects using advanced coal technologies under the Energy Improvement and Extension Act of 2008. The DOE subsequently certified the Kemper IGCC, and on April 30, 2010, the IRS allocated $279 million of Phase II tax credits under Section 48A of the Internal Revenue Code to Mississippi Power. The utilization of these credits is dependent upon meeting the IRS certification requirements and completing the Kemper IGCC in a timely manner. Mississippi Power has secured all environmental reviews and permits necessary to commence construction of the Kemper IGCC and has entered into a binding contract for the steam turbine generator, completing two milestone requirements for these credits.

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

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

			On May 26, 2010, the Mississippi PSC issued an order revising its findings from the April 29, 2010 order. Among other things, the Mississippi PSC’s May 26, 2010 order (1) approved the alternate construction cost cap of up to $2.88 billion (and any amounts that fall within specified exemptions from the cost cap; such exemptions include the costs of the lignite mine and equipment), subject to determinations by the Mississippi PSC that such costs in excess of $2.4 billion are prudent and required by the public convenience and necessity; (2) provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power’s proposal; and (3) approved financing cost recovery on construction work in progress (CWIP) balances under the State of Mississippi Baseload Act of 2008 (Baseload Act), which provides for the accrual of allowance for funds used during construction in 2010 and 2011 and recovery of financing costs on 100% of CWIP in 2012, 2013, and through May 1, 2014 (provided that the amount of CWIP allowed is (i) reduced by the amount of government construction cost incentives received by Mississippi Power in excess of $296 million to the extent that such amount increases cash flow for the pertinent regulatory period and (ii) justified by a showing that such CWIP allowance will benefit customers over the life of the plant). The Mississippi PSC order established periodic prudence reviews during the annual CWIP review process. More frequent prudence determinations may be requested at a later time. On May 27, 2010, Mississippi Power filed a motion with the Mississippi PSC accepting the conditions contained in the order. On June 3, 2010, the Mississippi PSC issued the final certificate order which granted Mississippi Power’s motion and issued a certificate of public convenience and necessity authorizing acquisition, construction, and operation of the Kemper IGCC.

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

			On June 17, 2010, the Sierra Club filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant a certificate of public convenience and necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, on July 6, 2010, the Sierra Club also filed an appeal directly with the Mississippi

145

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			Supreme Court. On July 20, 2010, the Chancery Court issued a stay of the proceeding pending the resolution of the jurisdictional issues raised in a motion filed by Mississippi Power on July 16, 2010 to confirm jurisdiction in the Mississippi Supreme Court.

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

			As of June 30, 2010, Mississippi Power had spent a total of $142.4 million on the Kemper IGCC, including regulatory filing costs. Of this total, $129.1 million was included in CWIP, $11.3 million was recorded in other regulatory assets, $0.8 million was recorded in other deferred charges and assets, and $1.3 million was expensed. Upon receipt of the issuance of the final certificate order in May 2010, construction screening costs including regulatory filing costs totaled $129.0 million. As of May 31, 2010, construction related screening costs of $116.2 million were reclassified to CWIP while the non-capital related costs of $11.2 million and $0.6 million were classified in other regulatory assets and other deferred charges, respectively, and $1.0 million was previously expensed. Costs incurred for the six months ended June 30, 2010 totaled $68.9 million compared to $14.1 million for the six months ended June 30, 2009.

			The ultimate outcome of these matters cannot now be determined.

(C)

FAIR VALUE MEASUREMENTS

As of June 30, 2010, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, 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, 2010:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Interest rate derivatives		—		8		—		8
Nuclear decommissioning trusts^(a)(b)		677		384		—		1,061
Cash equivalents and restricted cash		142		—		—		142
Other investments		24		48		19		91

Total	$	843	$	447	$	19	$	1,309

Liabilities:
Energy-related derivatives	$	—	$	209	$	—	$	209
Interest rate derivatives		—		1		—		1

Total	$	—	$	210	$	—	$	210


Alabama Power
Assets:
Nuclear decommissioning trusts:^(a)
Domestic equity	$	272	$	50	$	—	$	322
U.S. Treasury and government agency securities		17		7		—		24
Corporate bonds		—		80		—		80
Mortgage and asset backed securities		—		36		—		36
Other		—		12		—		12
Cash equivalents and restricted cash		32		—		—		32

Total	$	321	$	185	$	—	$	506

Liabilities:
Energy-related derivatives	$	—	$	45	$	—	$	45

146

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, 2010:	(Level 1)		(Level 2)		(Level 3)		Total
	(in millions)
Georgia Power
Assets:
Nuclear decommissioning trusts:^(a)
Domestic equity	$	388	$	1	$	—	$	389
U.S. Treasury and government agency securities		—		24		—		24
Municipal bonds		—		37		—		37
Corporate bonds		—		78		—		78
Mortgage and asset backed securities		—		41		—		41
Other		—		18		—		18
Cash equivalents		52		—		—		52

Total	$	440	$	199	$	—	$	639

Liabilities:
Energy-related derivatives	$	—	$	93	$	—	$	93


Gulf Power
Assets:
Cash equivalents and restricted cash	$	12	$	—	$	—	$	12

Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15


Mississippi Power
Liabilities:
Energy-related derivatives	$	—	$	48	$	—	$	48


Southern Power
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7

Liabilities:
Energy-related derivatives	$	—	$	8	$	—	$	8


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

			*Valuation Methodologies*

			The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR interest rates. Interest rate derivatives are also standard over-the-counter financial products valued using the market approach. Inputs include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. See Note (H) herein for additional information on how these derivatives are used.

			“Other investments” include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings

147

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.

			For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and significant unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics.

			A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts’ judgment are also obtained when available.


			As of June 30, 2010, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, are as follows:

Fair

Unfunded

Redemption

As of June 30, 2010:

Value

Commitments

Frequency

Notice Period

(in millions)

Southern Company

Nuclear decommissioning trusts:

Corporate bonds – commingled funds

None

Daily

1 to 3 days

Other – commingled funds

None

Daily

Not applicable

Trust owned life insurance

None

Daily

15 days

Cash equivalents and restricted cash:

Money market funds

142

None

Daily

Not applicable

Other:

Deferred compensation – money market funds

None

Daily

Not applicable

Alabama Power

Nuclear decommissioning trusts:

Trust owned life insurance

None

Daily

15 days

Cash equivalents and restricted cash:

Money market funds

None

Daily

Not applicable

Georgia Power

Nuclear decommissioning trusts:

Corporate bonds – commingled funds

None

Daily

1 to 3 days

Other – commingled funds

None

Daily

Not applicable

Cash equivalents:

Money market funds

None

Daily

Not applicable

Gulf Power

Cash equivalents and restricted cash:

Money market funds

None

Daily

Not applicable

The commingled funds in the nuclear decommissioning trusts invest primarily in a diversified portfolio of investment high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset rate date of 13 months or less. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity.

148

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			Alabama Power’s nuclear decommissioning trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the tables above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.

			Southern Company, Alabama Power, and Georgia Power account for investment securities held in the nuclear decommissioning trust funds at fair value. For the three months and six months ended June 30, 2010, the reduction in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $36 million and $16 million, respectively, for Alabama Power, $50 million and $26 million, respectively, for Georgia Power, and $86 million and $42 million, respectively, for Southern Company.

			The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investments in the money market funds.


			Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at June 30, 2010 are as follows:


	Level 3
	Other
	Three Months Ended		Six Months Ended
	June 30, 2010		June 30, 2010
	(in millions)
Beginning balance	$	19	$	35
Total gains (losses) — realized/unrealized:
Included in OCI		—		4
Transfers out of Level 3		—		(20	)

Ending balance at June 30, 2010	$	19	$	19

Transfers in and out of the levels of fair value hierarchy are recognized as of the end of the reporting period. At March 31, 2010, the value of one of the investments was reclassified from Level 3 to Level 1 because the securities began trading on the public market. The reclassification is reflected in the table above as a transfer out of Level 3 at its fair value.


			At June 30, 2010, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
Southern Company	$	19,548	$	20,641
Alabama Power	$	6,183	$	6,607
Georgia Power	$	8,315	$	8,719
Gulf Power	$	1,174	$	1,232
Mississippi Power	$	491	$	521
Southern Power	$	1,298	$	1,417

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

149

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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:

Three Months

Three Months

Six Months

Six Months

Ended

Ended

Ended

Ended

June 30, 2010

June 30, 2009

June 30, 2010

June 30, 2009

(in thousands)

As reported shares

828,363

790,748

825,444

785,303

Effect of options

4,259

1,320

3,308

1,562

Diluted shares

832,622

792,068

828,752

786,865

			There were 20 million and 37.8 million stock options that were not included in the diluted earnings per share calculation for the three and six months ended June 30, 2010 and 2009, respectively, 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 would have increased by 2 million and 3.5 million shares for the three months ended June 30, 2010 and 2009, respectively, and 2 million and 3.1 million shares for the six months ended June 30, 2010 and 2009, respectively.

			Changes in Stockholders’ Equity


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


									Preferred and
	Number of					Common			Preference		Total
	Common Shares					Stockholders’			Stock of		Stockholders’
	Issued		Treasury			Equity			Subsidiaries		Equity
	(in thousands)					(in millions)
Balance at December 31, 2009		820,152		(505	)	$	14,878		$	707	$	15,585
Net income after dividends on preferred and preference stock		—		—			1,005			—		1,005
Other comprehensive income (loss)		—		—			13			—		13
Stock issued		10,996		—			371			—		371
Cash dividends on common stock		—		—			(735	)		—		(735	)
Other		—		63			1			—		1

Balance at June 30, 2010		831,148		(442	)	$	15,533		$	707	$	16,240


Balance at December 31, 2008		777,616		(424	)	$	13,276		$	707	$	13,983
Net income after dividends on preferred and preference stock		—		—			604			—		604
Other comprehensive income (loss)		—		—			16			—		16
Stock issued		18,894		—			559			—		559
Cash dividends on common stock		—		—			(670	)		—		(670	)
Other		—		(34	)		(1	)		—		(1	)

Balance at June 30, 2009		796,510		(458	)	$	13,784		$	707	$	14,491

150

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(E)

FINANCING

			Bank Credit Arrangements

			Bank credit arrangements provide liquidity support to the registrants’ commercial paper borrowings and the traditional operating companies’ variable rate pollution control revenue bonds. See Note 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information.


			The following table outlines the credit arrangements by company as of June 30, 2010:


					Executable
					Term-Loans				Expires
					One		Two
Company	Total		Unused		Year		Years		2010		2011		2012
	(in millions)
Southern Company	$	950	$	950	$	—	$	—	$	—	$	—	$	950
Alabama Power		1,271		1,271		372		—		333		173		765
Georgia Power		1,715		1,703		220		40		40		555		1,120
Gulf Power		220		220		190		—		80		140		—
Mississippi Power		161		161		65		41		56		105		—
Southern Power		400		400		—		—		—		—		400
Other		60		60		60		—		10		50		—

Total	$	4,777	$	4,765	$	907	$	81	$	519	$	1,023	$	3,235

			Subsequent to June 30, 2010, Alabama Power renewed a $200 million credit agreement which contains a provision allowing a one-year term loan executable at expiration and extended the expiration date to 2011.

			Subsequent to June 30, 2010, Georgia Power renewed a $40 million credit agreement which contains a provision allowing a two-year term loan executable at expiration and extended the expiration date to 2011.

			Subsequent to June 30, 2010, Gulf Power increased its existing lines of credit by $15 million with an expiration of 2011.

(F)

RETIREMENT BENEFITS

			Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the plan are expected for the year ending December 31, 2010. 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.

151

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Components of the net periodic benefit costs for the three and six months ended June 30, 2010 and 2009 are as follows:


	Southern			Alabama			Georgia			Gulf			Mississippi
PENSION PLANS	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended June 30, 2010
Service cost	$	43		$	11		$	13		$	2		$	2
Interest cost		97			24			37			4			5
Expected return on plan assets		(137	)		(42	)		(55	)		(6	)		(6	)
Net amortization		10			2			3			—			—

Net cost (income)	$	13		$	(5	)	$	(2	)	$	—		$	1


Six Months Ended June 30, 2010
Service cost	$	86		$	21		$	27		$	4		$	4
Interest cost		195			48			73			8			9
Expected return on plan assets		(275	)		(84	)		(110	)		(12	)		(11	)
Net amortization		21			5			7			1			1

Net cost (income)	$	27		$	(10	)	$	(3	)	$	1		$	3


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

152

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


	Southern			Alabama			Georgia			Gulf			Mississippi
POSTRETIREMENT BENEFITS	Company			Power			Power			Power			Power
	(in millions)
Three Months Ended June 30, 2010
Service cost	$	7		$	1		$	2		$	1		$	1
Interest cost		25			7			11			1			1
Expected return on plan assets		(16	)		(6	)		(7	)		(1	)		(1	)
Net amortization		5			1			3			—			—

Net cost (income)	$	21		$	3		$	9		$	1		$	1


Six Months Ended June 30, 2010
Service cost	$	13		$	3		$	4		$	1		$	1
Interest cost		50			13			22			2			2
Expected return on plan assets		(32	)		(12	)		(15	)		(1	)		(1	)
Net amortization		10			3			6			—			—

Net cost (income)	$	41		$	7		$	17		$	2		$	2


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

(G)

EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

			Effective Tax Rate

			Southern Company’s effective tax rate was 31.8% for the six months ended June 30, 2010, as compared to 38.2% for the corresponding period in 2009. Southern Company’s effective tax rate is lower than the statutory rate primarily due to its employee stock plans dividend deduction and AFUDC equity, which is not taxable. See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for information on the effective income tax rate. Southern Company’s effective tax rate decreased for the six months ended June 30, 2010 as compared to June 30, 2009 due to the $202 million charge for the MC Asset Recovery settlement, which occurred in the first quarter 2009. Southern Company is currently evaluating potential recovery of the settlement payment through various means including insurance, claims in U.S. Bankruptcy Court, and other avenues. The degree to which any recovery is realized will determine, in part, the final income tax treatment of the settlement payment. Additionally, Georgia Power’s effective tax rate decreased for the six months ended June 30, 2010 compared to June 30, 2009 from 33.6% to 30.1% primarily due to the recognition of additional Georgia state tax credits and additional AFUDC equity. Southern Power’s effective tax rate decreased for the six months ended June 30, 2010 compared to June 30, 2009 from 39.1% to 30.2% primarily due to tax benefits associated with the construction of its biomass facility.

153

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Unrecognized Tax Benefits


			Changes during 2010 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, 2009	$	199		$	6	$	181		$	2	$	3	$	—
Tax positions from current periods		23			—		22			—		—		—
Tax positions from prior periods		(27	)		—		(23	)		—		—		—
Reductions due to settlements		—			—		—			—		—		—
Reductions due to expired statute of limitations		—			—		—			—		—		—

Balance as of June 30, 2010	$	195		$	6	$	180		$	2	$	3	$	—

All of the unrecognized tax benefits as of June 30, 2010 and December 31, 2009 would impact the effective tax rate of Southern Company and its subsidiaries if recognized. The tax positions increase from current periods relates primarily to the Georgia state tax credits litigation and other miscellaneous uncertain tax positions. The tax positions decrease from prior periods relates primarily to the Georgia state tax credits litigation. See Note (B) under “Income Tax Matters – Georgia State Income Tax Credits” herein for additional information.


			Accrued interest for unrecognized tax benefits was as follows:


	Georgia		Other		Southern
	Power		Registrants		Company
	(in millions)
Interest accrued as of December 31, 2009	$	20	$	1	$	21
Interest reclassified due to settlements		—		—		—
Interest accrued during the period		2		—		2

Balance as of June 30, 2010	$	22	$	1	$	23

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

			It is reasonably possible that the amount of the unrecognized tax benefits associated with a majority of Southern Company’s and Georgia Power’s unrecognized tax positions will significantly increase or decrease within the next 12 months. The resolution of the Georgia state tax credits litigation would substantially reduce the balances. The conclusion or settlement of state audits could also impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

(H)

DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company’s policies in areas such as counterparty exposure and risk management practices. Each company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

154

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 has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity.

			To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

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

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

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

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

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


			At June 30, 2010, the net volume of energy-related derivative contracts for power and natural gas positions for the registrants, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:


	Power						Gas
			Longest		Longest		Net		Longest		Longest
	Net Sold		Hedge		Non-Hedge		Purchased		Hedge		Non-Hedge
As of June 30, 2010:	MWH		Date		Date		mmBtu		Date		Date
	(in millions)		(in millions)
Southern Company		0.7		2010		2010		134		2014		2014
Alabama Power		—		—		—		31		2014		—
Georgia Power		—		—		—		67		2014		—
Gulf Power		—		—		—		9		2014		—
Mississippi Power		—		—		—		22		2014		—
Southern Power		0.7		2010		2010		5		2012		2014

In addition to the volumes discussed in the table above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 7 million mmBtu for Southern Company and 6 million mmBtu for Georgia Power and less than 1 million mmBtu for each of the other registrants.

155

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			For the next 12-month period ending June 30, 2011, Southern Company and Southern Power expect to reclassify $4 million in gains from OCI to revenue and $4 million in losses from OCI to fuel expense with respect to cash flow hedges. Such amounts are immaterial for all other registrants.

			*Interest Rate Derivatives*

			Southern Company and certain subsidiaries also enter into interest rate derivatives, which include forward-starting interest rate swaps, to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges. Derivatives related to existing fixed rate securities are accounted for as fair value hedges. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

			For cash flow hedges, the derivatives’ fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time the hedged transactions affect earnings. For fair value hedges, the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings, providing an offset with any difference representing ineffectiveness.


			At June 30, 2010, the following interest rate derivatives were outstanding:

Hedge

Fair Value

Notional

Interest Rate

Maturity

Gain (Loss)

Amount

Received

Paid

Date

June 30, 2010

(in millions)

Cash flow hedges of existing debt

Southern Company

300

3-month LIBOR +
0.40% spread

1.24

October 2011

)

Fair value hedges of existing debt

Southern Company

350

4.15%

3-month LIBOR +
1.96%* spread

May 2014

Total

650


*		Weighted Average

The following table reflects the estimated pre-tax gains (losses) that will be reclassified from OCI to interest expense for the next 12-month period ending June 30, 2011, together with the longest date that total deferred gains and losses are expected to be amortized into earnings.


	Estimated Gain (Loss) to
	be Reclassified for the			Total Deferred
	12 Months Ending			Gains (Losses)
Registrant	June 30, 2011			Amortized Through
	(in millions)
Southern Company	$	(19	)		2037
Alabama Power		1			2035
Georgia Power		(7	)		2037
Gulf Power		(1	)		2020
Southern Power		(11	)		2016

156

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Foreign Currency Derivatives

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At June 30, 2010, the following foreign currency derivatives were outstanding:

Fair Value

Notional

Gain (Loss)

Amount

Forward Rate

Hedge Maturity Date

June 30, 2010

(in millions)

Fair value hedges of firm commitments

Mississippi Power

EUR38.6

1.227

Various through June 2012

—


*		Weighted Average

Derivative Financial Statement Presentation and Amounts


			At June 30, 2010, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:


Asset Derivatives at June 30, 2010
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets*	$	4	$	—	$	—	$	—	$	—	$	—
Assets from risk management activities		—		—		—		—		—		4
Interest rate derivatives:
Other current assets		5		—		—		—		—		—
Other deferred charges and assets		3		—		—		—		—		—

Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	12	$	—	$	—	$	—	$	—	$	4


Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets*	$	3	$	—	$	—	$	—	$	—	$	—
Assets from risk management activities		—		—		—		—		—		3

Total derivatives not designated as hedging instruments	$	3	$	—	$	—	$	—	$	—	$	3


Total asset derivatives	$	15	$	—	$	—	$	—	$	—	$	7


*		Southern Company includes “Assets from risk management activities” in “Other current assets” where applicable.

157

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


Liability Derivatives at June 30, 2010
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	116	$	32	$	52	$	10	$	22
Other deferred credits and liabilities		85		13		41		5		26

Total derivatives designated as hedging instruments for regulatory purposes	$	201	$	45	$	93	$	15	$	48		N/A


Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities	$	5	$	—	$	—	$	—	$	—	$	5
Other deferred charges and assets		1		—		—		—		—		1
Interest rate derivatives:
Liabilities from risk management activities		1		—		—		—		—		—

Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	7	$	—	$	—	$	—	$	—	$	6


Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	2	$	—	$	—	$	—	$	—	$	2


Total liability derivatives	$	210	$	45	$	93	$	15	$	48	$	8

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


			At June 30, 2010, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheet were as follows:


Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet
Derivative Category and Balance Sheet	Southern			Alabama			Georgia			Gulf			Mississippi
Location	Company			Power			Power			Power			Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(116	)	$	(32	)	$	(52	)	$	(10	)	$	(22	)
Other regulatory assets, deferred		(85	)		(13	)		(41	)		(5	)		(26	)

Total energy-related derivative gains (losses)	$	(201	)	$	(45	)	$	(93	)	$	(15	)	$	(48	)

For the three months and six months ended June 30, 2010, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income was $9 million and $8 million, respectively. These amounts were offset with changes in the fair value of the hedged debt.

158

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months ended June 30, 2010 and June 30, 2009, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:


	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI
Derivatives in Cash Flow	on Derivative						into Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2010			2009				2010			2009
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(4	)	$	—		Fuel	$	—		$	—
Interest rate derivatives		1			(4	)	Interest expense		(8	)		(12	)

Total	$	(3	)	$	(4	)		$	(8	)	$	(12	)

Alabama Power
Interest rate derivatives	$	—		$	(2	)	Interest expense	$	1		$	(3	)

Georgia Power
Interest rate derivatives	$	—		$	(2	)	Interest expense	$	(5	)	$	(6	)

Gulf Power
Interest rate derivatives	$	1		$	—		Interest expense	$	—		$	—

Southern Power
Energy-related derivatives	$	(3	)	$	—		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(2	)		(3	)

Total	$	(3	)	$	—			$	(2	)	$	(3	)

For the six months ended June 30, 2010 and June 30, 2009, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:


	Gain (Loss)
	Recognized in OCI						Gain (Loss) Reclassified from Accumulated OCI
Derivatives in Cash Flow	on Derivative						into Income (Effective Portion)
Hedging Relationships	(Effective Portion)						Statements of Income Location	Amount
	2010			2009				2010			2009
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	1		$	1		Fuel	$	—		$	—
Interest rate derivatives		(2	)		(3	)	Interest expense		(17	)		(22	)

Total	$	(1	)	$	(2	)		$	(17	)	$	(22	)

Alabama Power
Interest rate derivatives	$	—		$	(4	)	Interest expense	$	(1	)	$	(6	)

Georgia Power
Interest rate derivatives	$	—		$	1		Interest expense	$	(10	)	$	(11	)

Gulf Power
Interest rate derivatives	$	(1	)	$	—		Interest expense	$	(1	)	$	(1	)

Southern Power
Energy-related derivatives	$	1		$	1		Fuel	$	—		$	—
Interest rate derivatives		—			—		Interest expense		(5	)		(5	)

Total	$	1		$	1			$	(5	)	$	(5	)

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

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months ended June 30, 2010 and June 30, 2009, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:


Derivatives not Designated
as Hedging Instruments	Unrealized Gain (Loss) Recognized in Income
	Statements of Income Location	Amount
		2010		2009
		(in millions)
Southern Company
Energy-related derivatives	Wholesale revenues	$	—	$	1
	Fuel		1		1
	Purchased power		1		(2	)

Total		$	2	$	—

Southern Power
Energy-related derivatives	Wholesale revenues	$	—	$	1
	Fuel		1		1
	Purchased power		1		(2	)

Total		$	2	$	—

For the six months ended June 30, 2010 and June 30, 2009, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:


Derivatives not Designated
as Hedging Instruments	Unrealized Gain (Loss) Recognized in Income
	Statements of Income Location	Amount
		2010		2009
		(in millions)
Southern Company
Energy-related derivatives	Wholesale revenues	$	1	$	5
	Fuel		—		(3	)
	Purchased power		—		(3	)

Total		$	1	$	(1	)

Southern Power
Energy-related derivatives	Wholesale revenues	$	1	$	5
	Fuel		—		(3	)
	Purchased power		—		(3	)

Total		$	1	$	(1	)

Contingent Features


			The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2010, the fair value of derivative liabilities with contingent features, by registrant, is as follows:


	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power
	(in millions)
Derivative liabilities	$	43	$	7	$	25	$	2	$	5	$	4

At June 30, 2010, the registrants had no collateral posted with their derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, is $43 million for each registrant.

160

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Currently, each of the registrants has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade.

(I)

SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $93 million and $195 million for the three months and six months ended June 30, 2010, respectively, and $138 million and $273 million for the three months and six months ended June 30, 2009, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications, renewable energy projects, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:


	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other			Eliminations			Consolidated
		(in millions)
Three Months Ended June 30, 2010:
Operating revenues	$	4,056	$	249	$	(118	)	$	4,187	$	41		$	(20	)	$	4,208
Segment net income (loss)*		475		30		—			505		5			—			510
Six Months Ended June 30, 2010:
Operating revenues	$	8,061	$	505	$	(243	)	$	8,323	$	82		$	(40	)	$	8,365
Segment net income (loss)*		956		45		—			1,001		5			(1	)		1,005
Total assets at June 30, 2010	$	49,792	$	3,173	$	(130	)	$	52,835	$	1,076		$	(537	)	$	53,374


Three Months Ended June 30, 2009:
Operating revenues	$	3,781	$	230	$	(152	)	$	3,859	$	43		$	(17	)	$	3,885
Segment net income (loss)*		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)*		723		59		—			782		(180	)		2			604
Total assets at December 31, 2009	$	48,403	$	3,043	$	(143	)	$	51,303	$	1,223		$	(480	)	$	52,046


*		After dividends on preferred and preference stock of subsidiaries

Products and Services


	Electric Utilities’ Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2010	$	3,571	$	473	$	143	$	4,187
Three Months Ended June 30, 2009		3,293		438		128		3,859

Six Months Ended June 30, 2010	$	7,030	$	1,015	$	278	$	8,323
Six Months Ended June 30, 2009		6,358		889		251		7,498

161


Item 6.		Exhibits.


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

Georgia Power

(c)1	-	Forty-First Supplemental Indenture to Senior Note Indenture dated as of June 3, 2010, providing for the issuance of the Series 2010B 5.40% Senior Notes due June 1, 2040. (Designated in Form 8-K dated May 24, 2010, File No. 1-6468, as Exhibit 4.2.)

(10) Material Contracts

Alabama Power

(b)1	-	Summary of Non-Employee Director Compensation Arrangements.

Gulf Power

(d)1	-	Summary of Non-Employee Director Compensation Arrangements.

(24) Power of Attorney and Resolutions

Southern Company

(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.)

Alabama Power

(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)

Georgia Power

(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)

Gulf Power

(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 0-2429 as Exhibit 24(d) and incorporated herein by reference.)

Mississippi Power

(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.)

Southern Power

(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2009, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)

163


(31) Section 302 Certifications

Southern Company

(a)1	-	Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(a)2	-	Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Alabama Power

(b)1	-	Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(b)2	-	Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Georgia Power

(c)1	-	Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(c)2	-	Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Gulf Power

(d)1	-	Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(d)2	-	Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Mississippi Power

(e)1	-	Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(e)2	-	Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Southern Power

(f)1	-	Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(f)2	-	Certificate of Southern Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

164


(32) Section 906 Certifications

Southern Company

(a)	-	Certificate of Southern Company’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Alabama Power

(b)	-	Certificate of Alabama Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Georgia Power

(c)	-	Certificate of Georgia Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Gulf Power

(d)	-	Certificate of Gulf Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Mississippi Power

(e)	-	Certificate of Mississippi Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Southern Power

(f)	-	Certificate of Southern Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

(101) XBRL – Related Documents

Southern Company

INS	XBRL Instance Document
SCH	XBRL Taxonomy Extension Schema Document
CAL	XBRL Taxonomy Calculation Linkbase Document
DEF	XBRL Definition Linkbase Document
LAB	XBRL Taxonomy Label Linkbase Document
PRE	XBRL Taxonomy Presentation Linkbase Document

165


		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 5.	Other Information	Inapplicable
Item 6.	Exhibits		163
	Signatures		166


		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		36
	Condensed Statements of Comprehensive Income		36
	Condensed Statements of Cash Flows		37
	Condensed Balance Sheets		38
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		40
	Georgia Power Company
	Condensed Statements of Income		55
	Condensed Statements of Comprehensive Income		55
	Condensed Statements of Cash Flows		56
	Condensed Balance Sheets		57
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		59
	Gulf Power Company
	Condensed Statements of Income		77
	Condensed Statements of Comprehensive Income		77
	Condensed Statements of Cash Flows		78
	Condensed Balance Sheets		79
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		81
	Mississippi Power Company
	Condensed Statements of Income		97
	Condensed Statements of Comprehensive Income		97
	Condensed Statements of Cash Flows		98
	Condensed Balance Sheets		99
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		101
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		120
	Condensed Consolidated Statements of Comprehensive Income		120
	Condensed Consolidated Statements of Cash Flows		121
	Condensed Consolidated Balance Sheets		122
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		124
	Notes to the Condensed Financial Statements		135
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		33
Item 4.	Controls and Procedures		33
Item 4T.	Controls and Procedures		33


Term		Meaning
SouthernLINC Wireless		Southern Communications Services, Inc.
Southern Nuclear		Southern Nuclear Operating Company, Inc.
Southern Power		Southern Power Company
S&P		Standard and Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.
traditional operating companies		Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Westinghouse		Westinghouse Electric Company LLC
wholesale revenues		revenues generated from sales for resale


Registrant		Applicable Notes

Southern Company		A, B, C, D, E, F, G, H, I

Alabama Power		A, B, C, E, F, G, H

Georgia Power		A, B, C, E, F, G, H

Gulf Power		A, B, C, E, F, G, H

Mississippi Power		A, B, C, E, F, G, H

Southern Power		A, B, C, E, G, H


				THE SOUTHERN COMPANY

		By		David M. Ratcliffe
				Chairman and Chief Executive Officer
				(Principal Executive Officer)

		By		W. Paul Bowers
				Executive Vice President and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				ALABAMA POWER COMPANY

		By		Charles D. McCrary
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Art P. Beattie
				Executive Vice President, Chief Financial Officer, and Treasurer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				GEORGIA POWER COMPANY

		By		Michael D. Garrett
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Ronnie R. Labrato
				Executive Vice President, Chief Financial Officer, and Treasurer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				GULF POWER COMPANY

		By		Susan N. Story
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Philip C. Raymond
				Vice President and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				MISSISSIPPI POWER COMPANY

		By		Anthony J. Topazi
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Frances Turnage
				Vice President, Treasurer, and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				SOUTHERN POWER COMPANY

		By		Ronnie L. Bates
				Chief Executive Officer
				(Principal Executive Officer)

		By		Michael W. Southern
				Senior Vice President, Treasurer, and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)