TEST ONLY

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 March 31, 2011

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

For the transition period from to


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

1-3164	Alabama Power Company	63-0004250
	(An Alabama Corporation)
	600 North 18^th Street
	Birmingham, Alabama 35203
	(205) 257-1000

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

001-31737	Gulf Power Company	59-0276810
	(A Florida Corporation)
	One Energy Place
	Pensacola, Florida 32520
	(850) 444-6111

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

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

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

Non-accelerated

Reporting

Registrant

Filer

Company

The Southern Company

Alabama Power Company

Georgia Power Company

Gulf Power Company

Mississippi Power Company

Southern Power Company

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 March 31, 2011
The Southern Company	Par Value $5 Per Share		849,122,723
Alabama Power Company	Par Value $40 Per Share		30,537,500
Georgia Power Company	Without Par Value		9,261,500
Gulf Power Company	Without Par Value		4,142,717
Mississippi Power Company	Without Par Value		1,121,000
Southern Power Company	Par Value $0.01 Per Share		1,000

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

DEFINITIONS


Term		Meaning
2007 Retail Rate Plan		Georgia Power’s retail rate plan for the years 2008 through 2010
2010 ARP		Alternate Rate Plan approved by the Georgia PSC for Georgia Power which became effective January 1, 2011 and will continue through December 31, 2013
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, 2010
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
NCCR		Georgia Power’s Nuclear Construction Cost Recovery
NDR		Alabama Power’s natural disaster reserve
NRC		Nuclear Regulatory Commission
NSR		New Source Review
OCI		Other Comprehensive Income
PEP		Mississippi Power’s Performance Evaluation Plan
Plant Vogtle Units 3 and 4		Two new nuclear generating units under construction at Plant Vogtle
Power Pool		The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA		Power Purchase Agreement
PSC		Public Service Commission
Rate CNP Environmental		Alabama Power’s rate certificated new plant environmental
Rate ECR		Alabama Power’s energy cost recovery rate mechanism
registrants		Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

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

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

•		available sources and costs of fuels;

•		effects of inflation;

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

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

•		advances in technology;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•		other factors discussed elsewhere herein and in other reports filed by the registrants from time to time with the SEC.

The registrants expressly disclaim any obligation to update any forward-looking statements.

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months
	Ended March 31,
	2011			2010
	(in millions)
Operating Revenues:
Retail revenues	$	3,396		$	3,459
Wholesale revenues		449			542
Other electric revenues		150			135
Other revenues		17			21

Total operating revenues		4,012			4,157

Operating Expenses:
Fuel		1,476			1,645
Purchased power		100			127
Other operations and maintenance		944			908
Depreciation and amortization		418			343
Taxes other than income taxes		220			212

Total operating expenses		3,158			3,235

Operating Income		854			922
Other Income and (Expense):
Allowance for equity funds used during construction		35			49
Interest expense, net of amounts capitalized		(222	)		(222	)
Other income (expense), net		2			(2	)

Total other income and (expense)		(185	)		(175	)

Earnings Before Income Taxes		669			747
Income taxes		231			236

Consolidated Net Income		438			511
Dividends on Preferred and Preference Stock of Subsidiaries		16			16

Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	422		$	495

Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.50		$	0.60
Diluted EPS	$	0.49		$	0.60
Average number of shares of common stock outstanding (in millions)
Basic		848			823
Diluted		854			825
Cash dividends paid per share of common stock	$	0.4550		$	0.4375

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 Three Months
	Ended March 31,
	2011			2010
	(in millions)
Operating Activities:
Consolidated net income	$	438		$	511
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total		501			422
Deferred income taxes		174			107
Deferred revenues		(2	)		(20	)
Allowance for equity funds used during construction		(35	)		(49	)
Pension, postretirement, and other employee benefits		(11	)		5
Stock based compensation expense		21			19
Generation construction screening costs		—			(19	)
Other, net		(14	)		(37	)
Changes in certain current assets and liabilities —
-Receivables		276			43
-Fossil fuel stock		(42	)		133
-Other current assets		(77	)		(94	)
-Accounts payable		(108	)		(100	)
-Accrued taxes		131			(73	)
-Accrued compensation		(277	)		(112	)
-Other current liabilities		23			2

Net cash provided from operating activities		998			738

Investing Activities:
Property additions		(1,086	)		(1,054	)
Investment in restricted cash		(3	)		—
Distribution of restricted cash		61			8
Nuclear decommissioning trust fund purchases		(928	)		(238	)
Nuclear decommissioning trust fund sales		924			189
Proceeds from property sales		14			—
Cost of removal, net of salvage		(15	)		(28	)
Change in construction payables		136			28
Other investing activities		13			7

Net cash used for investing activities		(884	)		(1,088	)

Financing Activities:
Increase (decrease) in notes payable, net		(54	)		132
Proceeds —
Long-term debt issuances		937			350
Common stock issuances		193			147
Redemptions —
Long-term debt		(824	)		(256	)
Payment of common stock dividends		(385	)		(359	)
Payment of dividends on preferred and preference stock of subsidiaries		(16	)		(16	)
Other financing activities		(2	)		1

Net cash used for financing activities		(151	)		(1	)

Net Change in Cash and Cash Equivalents		(37	)		(351	)
Cash and Cash Equivalents at Beginning of Period		447			690

Cash and Cash Equivalents at End of Period	$	410		$	339

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $17 and $21 capitalized for 2011 and 2010, respectively)	$	197		$	182
Income taxes (net of refunds)		(357	)		6
Noncash transactions — accrued property additions at end of period		531			373

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 March 31,			At December 31,
Assets	2011			2010
	(in millions)
Current Assets:
Cash and cash equivalents	$	410		$	447
Restricted cash and cash equivalents		7			68
Receivables —
Customer accounts receivable		1,024			1,140
Unbilled revenues		341			420
Under recovered regulatory clause revenues		220			209
Other accounts and notes receivable		249			285
Accumulated provision for uncollectible accounts		(26	)		(25	)
Fossil fuel stock, at average cost		1,350			1,308
Materials and supplies, at average cost		828			827
Vacation pay		150			151
Prepaid expenses		435			784
Other regulatory assets, current		199			210
Other current assets		53			59

Total current assets		5,240			5,883

Property, Plant, and Equipment:
In service		57,408			56,731
Less accumulated depreciation		20,384			20,174

Plant in service, net of depreciation		37,024			36,557
Other utility plant, net		67			—
Nuclear fuel, at amortized cost		738			670
Construction work in progress		4,872			4,775

Total property, plant, and equipment		42,701			42,002

Other Property and Investments:
Nuclear decommissioning trusts, at fair value		1,369			1,370
Leveraged leases		630			624
Miscellaneous property and investments		267			277

Total other property and investments		2,266			2,271

Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,263			1,280
Prepaid pension costs		104			88
Unamortized debt issuance expense		178			178
Unamortized loss on reacquired debt		269			274
Deferred under recovered regulatory clause revenues		133			218
Other regulatory assets, deferred		2,432			2,402
Other deferred charges and assets		433			436

Total deferred charges and other assets		4,812			4,876

Total Assets	$	55,019		$	55,032

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 March 31,			At December 31,
Liabilities and Stockholders’ Equity	2011			2010
	(in millions)
Current Liabilities:
Securities due within one year	$	1,435		$	1,301
Notes payable		1,243			1,297
Accounts payable		1,315			1,275
Customer deposits		333			332
Accrued taxes —
Accrued income taxes		13			8
Unrecognized tax benefits		183			187
Other accrued taxes		192			440
Accrued interest		259			225
Accrued vacation pay		190			194
Accrued compensation		165			438
Liabilities from risk management activities		133			152
Other regulatory liabilities, current		83			88
Other current liabilities		493			535

Total current liabilities		6,037			6,472

Long-term Debt		18,133			18,154

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		7,673			7,554
Deferred credits related to income taxes		233			235
Accumulated deferred investment tax credits		525			509
Employee benefit obligations		1,575			1,580
Asset retirement obligations		1,283			1,257
Other cost of removal obligations		1,170			1,158
Other regulatory liabilities, deferred		335			312
Other deferred credits and liabilities		508			517

Total deferred credits and other liabilities		13,302			13,122

Total Liabilities		37,472			37,748

Redeemable Preferred Stock of Subsidiaries		375			375

Stockholders’ Equity:
Common Stockholders’ Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — March 31, 2011: 850 million shares
— December 31, 2010: 844 million shares
Treasury — March 31, 2011: 0.5 million shares
— December 31, 2010: 0.5 million shares
Par value		4,248			4,219
Paid-in capital		3,894			3,702
Treasury, at cost		(15	)		(15	)
Retained earnings		8,404			8,366
Accumulated other comprehensive loss		(66	)		(70	)

Total Common Stockholders’ Equity		16,465			16,202
Preferred and Preference Stock of Subsidiaries		707			707

Total Stockholders’ Equity		17,172			16,909

Total Liabilities and Stockholders’ Equity	$	55,019		$	55,032

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

FIRST QUARTER 2011 vs. FIRST QUARTER 2010

OVERVIEW

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

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

RESULTS OF OPERATIONS

Net Income


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(73)		(14.6)

Southern Company’s first quarter 2011 net income after dividends on preferred and preference stock of subsidiaries was $422 million ($0.50 per share) compared to $495 million ($0.60 per share) for the first quarter 2010. The decrease for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of decreases in revenues in the first quarter 2011 due to the significantly colder weather in the first quarter 2010, a decrease in wholesale revenues primarily at Alabama Power, a decrease in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power, and increases in operations and maintenance expenses. The decrease for the first quarter 2011 was partially offset by an increase in retail base revenues at Georgia Power pursuant to the 2010 ARP and by increases in revenues associated with new PPAs at Southern Power.

Retail Revenues


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(63)		(1.8)

In the first quarter 2011, retail revenues were $3.4 billion compared to $3.5 billion for the corresponding period in 2010.

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

Details of the change to retail revenues follow:


	First Quarter
	2011

	(in millions)			(% change)
Retail — prior year	$	3,459
Estimated change in —
Rates and pricing		166			4.8
Sales growth (decline)		(5	)		(0.1	)
Weather		(90	)		(2.6	)
Fuel and other cost recovery		(134	)		(3.9	)

Retail – current year	$	3,396			(1.8	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2011 when compared to the corresponding period in 2010 primarily due to Georgia Power’s retail base rate increase and NCCR revenues. Also contributing to the increase were revenues associated with Alabama Power’s Rate CNP Environmental due to the completion of construction projects related to environmental mandates, although there was no increase in the Rate CNP Environmental billing factors in 2011.

Revenues attributable to changes in sales decreased in the first quarter 2011 when compared to the corresponding period in 2010. The decrease was due to a 0.9% decrease in weather-adjusted residential KWH sales and a 0.8% decrease in weather-adjusted commercial KWH sales. In addition, weather-adjusted industrial KWH sales increased 6.4% due to increased production activity in the primary metals and chemical sectors.

Revenues resulting from changes in weather decreased $90 million in the first quarter 2011 as a result of significantly colder weather in the corresponding period in 2010.

Fuel and other cost recovery revenues decreased $134 million in the first quarter 2011 when compared to the corresponding period in 2010. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(93)		(17.2)

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

In the first quarter 2011, wholesale revenues were $449 million compared to $542 million for the corresponding period in 2010, reflecting a $71 million decrease in energy revenues and a $22 million decrease in capacity revenues. The decrease in the first quarter 2011 was primarily due to a 24.2% decrease in KWH sales mainly due to 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. The decrease was partially offset by higher energy and capacity revenues under new PPAs at Southern Power that began in June, July, and December 2010 and January 2011.

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

Other Electric Revenues


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$15		11.1

In the first quarter 2011, other electric revenues were $150 million compared to $135 million for the corresponding period in 2010. The increase in the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of an increase in transmission revenues.

Other Revenues


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(4)		(20.3)

In the first quarter 2011, other revenues were $17 million compared to $21 million for the corresponding period in 2010. The decrease in the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of a $4 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


First Quarter 2011 vs. First Quarter 2010
	(change in millions)			(% change)
Fuel*	$	(169	)		(10.3	)
Purchased power		(27	)		(20.8	)

Total fuel and purchased power expenses	$	(196	)


*		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 first quarter 2011 were $1.6 billion compared to $1.8 billion for the corresponding period in 2010. The decrease for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of a $63 million decrease related to total KWHs generated and purchased and a $133 million net decrease in the average cost of fuel and purchased power. The decrease in total KWHs generated and purchased resulted primarily from a decrease in customer demand, and the net decrease in the cost of fuel and purchased power resulted primarily from a 20.6% decrease in the average cost of gas per KWH generated and a 4.9% decrease in the average cost of coal per KWH generated.

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

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

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


	First Quarter		First Quarter		Percent
Average Cost	2011		2010		Change
	(cents per net KWH)

Fuel		3.25		3.60		(9.7	)
Purchased power		9.25		7.37		25.5

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

Other Operations and Maintenance Expenses


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$36		3.8

In the first quarter 2011, other operations and maintenance expenses were $944 million compared to $908 million for the corresponding period in 2010. The increase in the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of a $30 million increase in scheduled outage and maintenance costs, a $10 million increase in commodity and labor costs, a $9 million increase in transmission and distribution expenses, and a $3 million increase in customer service related costs. The increase was partially offset by a $16 million decrease in administrative and general costs primarily due to decreases in property insurance, pension costs, and other employee benefits.

Depreciation and Amortization


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$75		21.9

In the first quarter 2011, depreciation and amortization was $418 million compared to $343 million for the corresponding period in 2010. The increase for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of a $50 million decrease in the amortization of the regulatory liability related to other cost of removal obligations at Georgia Power as authorized by the Georgia PSC and additional depreciation on 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 — Retail Rate Plans” for additional information on the other cost of removal regulatory liability.

Taxes Other Than Income Taxes


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$8		3.9

In the first quarter 2011, taxes other than income taxes were $220 million compared to $212 million for the corresponding period in 2010. The increase for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of increases in property and payroll taxes.

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

Allowance for Equity Funds Used During Construction


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(14)		(28.6)

In the first quarter 2011, AFUDC equity was $35 million compared to $49 million for the corresponding period in 2010. The decrease for the first quarter 2011 when compared to the corresponding period in 2010 was primarily due to the inclusion of Georgia Power’s Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011 which reduced the amount of AFUDC capitalized. Also contributing to the decrease was the completion of environmental construction projects at Alabama Power. See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under “Retail Regulatory Matters — Georgia Power — Nuclear Construction” and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” herein for additional information.

Income Taxes


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(5)		(1.8)

In the first quarter 2011, income taxes were $231 million compared to $236 million for the corresponding period in 2010. The decrease for the first quarter 2011 when compared to the corresponding period in 2010 was primarily the result of lower pre-tax earnings, partially offset by a decrease in the first quarter 2010 in uncertain tax positions at Georgia Power related to state income tax credits that remain subject to litigation. See Notes (B) and (G) to the Condensed Financial Statements under “Income Tax Matters — Georgia State Income Tax Credits” and “Unrecognized Tax Benefits,” respectively, herein for additional information.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

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

operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — New Source Review Actions” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has the right to appeal within 60 days of the order. The ultimate outcome of this matter cannot be determined at this time.

Carbon Dioxide Litigation

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters — Carbon Dioxide Litigation — Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of the facilities of Southern Company’s subsidiaries which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.

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

Mitchell Unit 3 to biomass until there is greater clarity regarding these regulations. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time.

In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. In a decision published on April 6, 2011, the EPA responded to an environmental group’s request for reconsideration by attempting to rescind its previous approval of the Alabama SIP revision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s attempted rescission pending judicial review. Absent a stay, the EPA’s decision will become effective May 6, 2011 and the rule under which Alabama Power has been operating since January 2009 may not be available unless Alabama Power’s appeal is resolved in its favor by the court. If the EPA’s decision is allowed to take effect, it will likely impact unit availability and result in increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Water Quality” of Southern Company in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Southern Company affiliates’ existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of the facilities of Southern Company’s subsidiaries may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.

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 previous 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 Alabama Power, Georgia Power, and Gulf Power of approximately $348 million at March 31, 2011. Mississippi Power collected all previously under recovered fuel costs and, as of March 31, 2011, had a total over recovered fuel balance of $58 million. At December 31, 2010, total under recovered fuel costs included in the balance sheets of Alabama Power, Georgia Power, and Gulf Power were approximately $420 million and Mississippi Power had a total over recovered fuel balance of $55 million. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changing the billing factor has no significant effect on Southern Company’s revenues or net income,

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

but does impact annual cash flow. The traditional operating companies continuously monitor the under or over recovered fuel cost balances.

On March 1, 2011, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 0.61%. The decrease would reduce Georgia Power’s annual billings by approximately $43 million. The decrease in fuel costs is driven primarily by lower natural gas prices than those included in current rates. That decrease is a result of increases in natural gas supplies from the production of shale gas and lower industrial demand. If approved, the new rates will go into effect June 1, 2011. The ultimate outcome of this matter cannot be determined at this time.

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

Alabama Power Retail Regulatory Matters

Natural Disaster Reserve

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “PSC Matters — Alabama Power — Natural Disaster Reserve” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Alabama Power — Natural Disaster Reserve” in Item 8 of the Form 10-K.

On April 27, 2011, devastating storms swept through the central part of Alabama causing significant damage in parts of the service territory of Alabama Power. Over 400,000 of Alabama Power’s 1.4 million customers were without electrical service immediately after the storms, resulting from significant damage to Alabama Power’s transmission and distribution facilities. The preliminary estimated cost associated with repairing the damage to facilities and restoring electrical service to customers is between $40 million and $55 million for operations and maintenance expenses and between $180 million and $225 million for capital expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.

At March 31, 2011, the NDR had an accumulated balance of $127 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.

Georgia Power Retail Regulatory Matters

Plant Branch Units 1 and 2 De-certification

See “Environmental Matters — Air Quality” and “— Water Quality” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Environmental Statutes and Regulations — Air Quality,” “— Water Quality,” and “— Coal Combustion Byproducts” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters — Rate Plans” in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility MACT rule for coal- and oil-fired EGUs, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia’s Multi-Pollutant Rule; Georgia Power’s analysis of the potential costs and benefits of installing the required controls on its coal-fired generating units in light of these regulations; and the 2010 ARP.

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

On March 22, 2011, the board of the Georgia Department of Natural Resources began consideration of modifications to the Georgia Multi-Pollutant Rule. The proposed modifications would change the compliance dates for certain of Georgia Power’s coal-fired generating units as follows:


		Scherer 3		July 1, 2011
		Branch 1		December 31, 2013
		Branch 2		October 1, 2013
		Branch 3		October 1, 2015
		Branch 4		December 31, 2015

The Multi-Pollutant Rule is designed to reduce emissions of mercury, sulfur dioxide, and nitrogen oxides statewide. The Utility MACT rule will also regulate emissions of mercury, in addition to other air pollutants. All required controls, including SCR, scrubber, and baghouse, are expected to be operational at Plant Scherer Unit 3 by the required compliance date. As a result of these proposed rules, Georgia Power’s management expects to request that the Georgia PSC approve de-certification of its Plant Branch Units 1 and 2, totaling 569 MWs of capacity, as of the effective dates for controls under the Multi-Pollutant Rule as revised. Georgia Power continues to analyze the potential costs and benefits of installing the required controls on its remaining coal-fired units, including Plant Branch Units 3 and 4, in light of the proposed air quality rules, as well as additional potential federal regulations related to water quality and coal combustion byproducts. Georgia Power may determine that retiring and replacing certain of its existing units with new generating resources or purchased power is more economically efficient than installing the required controls.

Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets resulting from new or revised environmental regulations through 2013 that are approved by the Georgia PSC in connection with an updated integrated resource plan will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Georgia Power currently expects to file an update to its integrated resource plan in late summer 2011, which would include the Plant Branch Units 1 and 2 de-certification request. In connection with this filing, Georgia Power expects to request the Georgia PSC to approve the deferral and related amortization of the retail portion of the related costs associated with the de-certification request. Georgia Power moved the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net of depreciation. Consistent with current ratemaking treatment, Georgia Power will continue to depreciate these units using the composite straight-line rates approved by the Georgia PSC, and upon actual retirement, expects to include the units’ remaining net carrying value in rate base. However, the recovery periods for these units may change in connection with Georgia Power’s updated integrated resource plan. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Southern Company’s financial statements.

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

Storm Damage Reserve

During April 2011, severe storms in Georgia caused significant damage to Georgia Power’s distribution and transmission facilities. Georgia Power maintains a reserve for property damage to cover the operating and maintenance cost of damages from major storms to its transmission and distribution lines as mandated by the Georgia PSC. As a result of this regulatory treatment, the storms are not expected to have a material impact on Southern Company’s financial statements. See Note 1 to the financial statements of Southern Company under “Storm Damage Reserves” in Item 8 of the Form 10-K for additional information.

Income Tax Matters

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Southern Company. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Southern Company estimates the potential increased cash flow for 2011 to be between approximately $350 million and $450 million. 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

Construction Program

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Southern Company intends to continue its strategy of developing and constructing new generating facilities, including natural gas, biomass, and potentially solar units at Southern Power, natural gas and new nuclear units at Georgia Power, and the Kemper IGCC facility at Mississippi Power, 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,” “Retail Regulatory Matters — Georgia Power — Other Construction,” and “Retail Regulatory Matters — Mississippi Power Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under “State PSC Matters — Georgia Power — Nuclear Construction” and “State PSC Matters — Mississippi Power — Integrated Coal Gasification Combined Cycle” herein for additional information.

On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. According to published reports, the owner of these units is continuing work to stabilize these units following a loss of operation of the cooling systems for the units. While the Southern Company system will continue to monitor this developing situation, it has not identified any immediate impact to the licensing and construction of Plant Vogtle Units 3 and 4 or the operation of the existing nuclear generating units of Alabama Power and Georgia Power.

The events in Japan have created uncertainties that may affect transportation, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of nuclear facilities in the U.S., which could potentially impact future operations and capital requirements.

See RISK FACTORS in Item 1A of Southern Company in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company’s subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported 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 SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition remained stable at March 31, 2011. 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 $998 million for the first quarter 2011, an increase of $260 million from the corresponding period in 2010. Significant changes in operating cash flow for the first quarter 2011 as compared to the corresponding period in 2010 include a decrease in accounts receivable balances primarily due to greater recovery of fuel costs. Net cash used for investing activities totaled $884 million for the first quarter 2011, a decrease of $204 million from the corresponding period in 2010. This decrease was primarily due to an increase in construction-related accounts payable. Net cash used for financing activities totaled $151 million for the first quarter 2011, an increase of $150 million from the corresponding period in 2010. This increase was primarily due to a decrease in notes payable.

Significant balance sheet changes for the first quarter 2011 include a decrease in prepaid expenses of $349 million due to a reduction in prepaid income taxes and an increase of $699 million 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 $263 million.

The market price of Southern Company’s common stock at March 31, 2011 was $38.11 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $19.39 per share, representing a market-to-book ratio of 196.5%, compared to $38.23, $19.21, and 199.0%, respectively, at the end of 2010. The dividend for the first quarter 2011 was $0.4550 per share compared to $0.4375 per share in the first quarter 2010. In April 2011, the quarterly dividend payable in June 2011 was increased to $0.4725 per share.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Southern Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for the construction programs of its subsidiaries and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits

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

and interest, and derivative obligations. Approximately $1.4 billion will be required through March 31, 2012 for maturities and announced repurchases of long-term debt.

The construction programs of Southern Company’s subsidiaries are currently estimated to include a base level investment of $4.9 billion, $5.1 billion, and $4.5 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $341 million, $427 million, and $452 million for 2011, 2012, and 2013, respectively. In addition, Southern Company currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $74 million to $289 million for 2011, $191 million to $670 million for 2012, and $476 million to $1.9 billion for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Southern Company estimates the potential investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. 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, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of Southern Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2011, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities.

Except as described below with respect to potential DOE loan guarantees, the traditional operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances, term loans, short-term borrowings, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Sources of Capital” of Southern Company in Item 7 of the Form 10-K for additional information.

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

In addition, Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees for 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.

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

At March 31, 2011, Southern Company and its subsidiaries had approximately $410 million of cash and cash equivalents and approximately $4.8 billion of unused committed credit arrangements with banks, of which $1.6 billion expire in 2011 and $3.3 billion expire in 2012. Of the credit arrangements expiring in 2011 and 2012, $81 million contain provisions allowing two-year term loans executable at expiration and $952 million contain provisions allowing one-year term loans executable at expiration. At March 31, 2011, approximately $1.4 billion of the credit facilities were dedicated to providing liquidity support to the traditional operating companies’ variable rate pollution control revenue bonds. 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 March 31, 2011, the Southern Company system had approximately $1.2 billion of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During the first quarter 2011, Southern Company had an average of $1.2 billion of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $1.6 billion. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Off-Balance Sheet Financing Arrangements

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” of Southern Company in Item 7 and Note 7 to the financial statements of Southern Company under “Operating Leases” in Item 8 of the Form 10-K for information related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel. In April 2010, Mississippi Power was required to notify the lessor, Juniper Capital L.P., if it intended to terminate the lease at the end of the initial term expiring in October 2011. Mississippi Power chose not to give notice to terminate the lease. Mississippi Power has the option to purchase the units or renew the lease. Mississippi Power is required 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 March 31, 2011, 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 $495 million. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $2.5 billion. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Southern Company’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

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

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

Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional operating companies continue to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional operating companies enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into financial hedge contracts for natural gas purchases. The traditional operating companies continue to manage fuel-hedging programs implemented per the guidelines of their respective state PSCs. Southern Company had no material change in market risk exposure for the first quarter 2011 when compared with the December 31, 2010 reporting period.

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:


	First Quarter
	2011
	Changes
	Fair Value
	(in millions)

Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(196	)
Contracts realized or settled		38
Current period changes^(a)		—

Contracts outstanding at the end of the period, assets (liabilities), net	$	(158	)


(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 ended March 31, 2011 was an increase of $38 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At March 31, 2011, Southern Company had a net hedge volume of 154.2 million mmBtu with a weighted average contract cost approximately $1.09 per mmBtu above market prices, compared to 149.3 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.35 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	March 31, 2011			December 31, 2010
	(in millions)
Regulatory hedges	$	(156	)	$	(193	)
Cash flow hedges		—			(1	)
Not designated		(2	)		(2	)

Total fair value	$	(158	)	$	(196	)

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

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

Total net unrealized pre-tax gains (losses) recognized in income for the three months ended March 31, 2011 and 2010 were not material.

Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:


	March 31, 2011
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(158	)		(125	)		(33	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(158	)	$	(125	)	$	(33	)	$	—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Company. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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

Financing Activities

During the first quarter 2011, Southern Company issued approximately 5.8 million shares of common stock for $193 million through the Southern Investment Plan and employee and director stock plans. The proceeds were primarily used for general corporate purposes, including the investment by Southern Company in its subsidiaries, and to repay short-term indebtedness.

In January 2011, Georgia Power’s $100 million aggregate principal amount of Series S 4.0% Senior Notes due January 15, 2011 matured.

In January 2011, Georgia Power issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used for general corporate purposes, including Georgia Power’s continuous construction program.

In March 2011, Georgia Power’s $300 million variable rate bank term loan due on March 4, 2011 matured and was partially replaced by two one-year $125 million aggregate principal amount variable rate bank loans that bear interest based on one-month LIBOR.

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

Subsequent to March 31, 2011, Georgia Power issued $250 million aggregate principal amount of Series 2011B 3.0% Senior Notes due April 15, 2016. The proceeds were used to repay short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.

Also subsequent to March 31, 2011, Georgia Power purchased and is holding $113.5 million of pollution control revenue bonds. The bonds are expected to be re-marketed to investors at a future date.

Subsequent to March 31, 2011, Gulf Power extended the maturity date of a $110 million bank note until June 30, 2011.

Subsequent to March 31, 2011, Mississippi Power entered into a one-year $75 million aggregate principal amount long-term floating rate bank loan that bears interest based on one-month LIBOR. The proceeds were used to repay short-term debt and for general corporate purposes, including Mississippi Power’s continuous construction program.

In addition to any financings that may be necessary to meet capital requirements 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, Note 10 to the financial statements of Gulf Power and Mississippi Power, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures.

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

(b) Changes in internal controls.

There have been no changes in Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the first quarter 2011 that have materially affected or are reasonably likely to materially affect Southern Company’s, Alabama Power’s, Georgia Power’s, Gulf Power’s, Mississippi Power’s, or Southern Power’s internal control over financial reporting.

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months
	Ended March 31,
	2011			2010
	(in millions)
Operating Revenues:
Retail revenues	$	1,126		$	1,176
Wholesale revenues, non-affiliates		68			172
Wholesale revenues, affiliates		75			98
Other revenues		51			49

Total operating revenues		1,320			1,495

Operating Expenses:
Fuel		395			489
Purchased power, non-affiliates		11			18
Purchased power, affiliates		46			52
Other operations and maintenance		297			310
Depreciation and amortization		157			145
Taxes other than income taxes		85			82

Total operating expenses		991			1,096

Operating Income		329			399
Other Income and (Expense):
Allowance for equity funds used during construction		5			13
Interest income		4			4
Interest expense, net of amounts capitalized		(74	)		(75	)
Other income (expense), net		(6	)		(6	)

Total other income and (expense)		(71	)		(64	)

Earnings Before Income Taxes		258			335
Income taxes		96			122

Net Income		162			213
Dividends on Preferred and Preference Stock		10			10

Net Income After Dividends on Preferred and Preference Stock	$	152		$	203

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months
	Ended March 31,
	2011		2010
	(in millions)
Net Income After Dividends on Preferred and Preference Stock	$	152	$	203
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $2 and $-, respectively		2		—
Reclassification adjustment for amounts included in net income, net of tax of $- and $1, respectively		—		1

Total other comprehensive income (loss)		2		1

Comprehensive Income	$	154	$	204

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 Three Months
	Ended March 31,
	2011			2010
	(in millions)
Operating Activities:
Net income	$	162		$	213
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		185			168
Deferred income taxes		59			47
Allowance for equity funds used during construction		(5	)		(13	)
Pension, postretirement, and other employee benefits		(11	)		(8	)
Stock based compensation expense		3			3
Hedge settlements		4			—
Storm damage accruals		1			2
Other, net		(4	)		4
Changes in certain current assets and liabilities —
-Receivables		51			11
-Fossil fuel stock		3			13
-Materials and supplies		10			(3	)
-Other current assets		(69	)		(78	)
-Accounts payable		(153	)		(75	)
-Accrued taxes		160			69
-Accrued compensation		(67	)		(41	)
-Other current liabilities		(2	)		(38	)

Net cash provided from operating activities		327			274

Investing Activities:
Property additions		(213	)		(255	)
Distribution of restricted cash from pollution control revenue bonds		11			5
Nuclear decommissioning trust fund purchases		(97	)		(39	)
Nuclear decommissioning trust fund sales		97			39
Cost of removal, net of salvage		(8	)		(5	)
Change in construction payables		(2	)		(26	)
Other investing activities		(12	)		(17	)

Net cash used for investing activities		(224	)		(298	)

Financing Activities:
Proceeds —
Capital contributions from parent company		5			6
Senior notes issuances		250			—
Redemptions —
Senior notes		(200	)		—
Payment of preferred and preference stock dividends		(10	)		(10	)
Payment of common stock dividends		(138	)		(136	)
Other financing activities		(5	)		(1	)

Net cash used for financing activities		(98	)		(141	)

Net Change in Cash and Cash Equivalents		5			(165	)
Cash and Cash Equivalents at Beginning of Period		154			368

Cash and Cash Equivalents at End of Period	$	159		$	203

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $2 and $5 capitalized for 2011 and 2010, respectively)	$	72		$	59
Income taxes (net of refunds)		(110	)		19
Noncash transactions — accrued property additions at end of period		26			48

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 March 31,			At December 31,
Assets	2011			2010
	(in millions)
Current Assets:
Cash and cash equivalents	$	159		$	154
Restricted cash and cash equivalents		7			18
Receivables —
Customer accounts receivable		321			362
Unbilled revenues		110			153
Under recovered regulatory clause revenues		10			5
Other accounts and notes receivable		33			35
Affiliated companies		89			57
Accumulated provision for uncollectible accounts		(10	)		(10	)
Fossil fuel stock, at average cost		388			391
Materials and supplies, at average cost		336			346
Vacation pay		56			55
Prepaid expenses		140			208
Other regulatory assets, current		32			38
Other current assets		7			10

Total current assets		1,678			1,822

Property, Plant, and Equipment:
In service		20,218			19,966
Less accumulated provision for depreciation		7,038			6,931

Plant in service, net of depreciation		13,180			13,035
Nuclear fuel, at amortized cost		317			283
Construction work in progress		428			547

Total property, plant, and equipment		13,925			13,865

Other Property and Investments:
Equity investments in unconsolidated subsidiaries		63			64
Nuclear decommissioning trusts, at fair value		578			552
Miscellaneous property and investments		71			71

Total other property and investments		712			687

Deferred Charges and Other Assets:
Deferred charges related to income taxes		456			488
Prepaid pension costs		267			257
Deferred under recovered regulatory clause revenues		5			4
Other regulatory assets, deferred		673			675
Other deferred charges and assets		209			196

Total deferred charges and other assets		1,610			1,620

Total Assets	$	17,925		$	17,994

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 March 31,			At December 31,
Liabilities and Stockholder’s Equity	2011			2010
	(in millions)
Current Liabilities:
Securities due within one year	$	—		$	200
Accounts payable —
Affiliated		158			210
Other		170			273
Customer deposits		86			86
Accrued taxes —
Accrued income taxes		4			2
Other accrued taxes		51			32
Accrued interest		62			63
Accrued vacation pay		45			45
Accrued compensation		34			99
Liabilities from risk management activities		24			31
Over recovered regulatory clause revenues		23			22
Other current liabilities		39			41

Total current liabilities		696			1,104

Long-term Debt		6,235			5,987

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,774			2,747
Deferred credits related to income taxes		86			85
Accumulated deferred investment tax credits		155			157
Employee benefit obligations		309			311
Asset retirement obligations		528			520
Other cost of removal obligations		712			701
Other regulatory liabilities, deferred		236			217
Other deferred credits and liabilities		90			87

Total deferred credits and other liabilities		4,890			4,825

Total Liabilities		11,821			11,916

Redeemable Preferred Stock		342			342

Preference Stock		343			343

Common Stockholder’s Equity:
Common stock, par value $40 per share —
Authorized - 40,000,000 shares
Outstanding - 30,537,500 shares		1,222			1,222
Paid-in capital		2,166			2,156
Retained earnings		2,036			2,022
Accumulated other comprehensive loss		(5	)		(7	)

Total common stockholder’s equity		5,419			5,393

Total Liabilities and Stockholder’s Equity	$	17,925		$	17,994

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

FIRST QUARTER 2011 vs. FIRST QUARTER 2010

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale 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 and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.

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

RESULTS OF OPERATIONS

Net Income


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(51)		(25.1)

Alabama Power’s net income after dividends on preferred and preference stock for the first quarter 2011 was $152 million compared to $203 million for the corresponding period in 2010. The decrease was primarily due to reductions in wholesale revenues from sales to non-affiliates in the first quarter 2011 and significantly colder weather in the first quarter 2010. The decrease in revenue was partially offset by decreases in operations and maintenance expenses and an increase in revenues under Rate CNP Environmental associated with the completion of construction projects related to environmental mandates.

Retail Revenues


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(50)		(4.3)

In the first quarter 2011, retail revenues were $1.13 billion compared to $1.18 billion for the corresponding period in 2010.

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

Details of the change to retail revenues are as follows:


	First Quarter
	2011
	(in millions)			(% change)

Retail – prior year	$	1,176
Estimated change in —
Rates and pricing		26			2.2
Sales growth (decline)		(3	)		(0.2	)
Weather		(45	)		(3.9	)
Fuel and other cost recovery		(28	)		(2.4	)

Retail – current year	$	1,126			(4.3	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2011 when compared to the corresponding period in 2010 primarily due to increased revenues associated with Rate CNP Environmental. The increase was due to the completion of construction projects related to environmental mandates, although there was no increase in the Rate CNP Environmental billing factors in 2011.

Revenues attributable to changes in sales decreased slightly in the first quarter 2011 from the corresponding period in 2010. Weather-adjusted residential KWH energy sales decreased 2.7% due to a decrease in customer demand. Weather-adjusted commercial KWH energy sales decreased 1.0% due to decreases in the number of customers and demand. Industrial KWH energy sales increased 9.5% due to an increase in demand resulting from changes in production levels primarily in the chemical and primary metals sectors.

Revenues resulting from changes in weather decreased in the first quarter 2011 when compared to the corresponding period in 2010. Residential and commercial sales revenues decreased 7.1% and 1.5%, respectively, as a result of significantly colder weather in the corresponding period in 2010.

Fuel and other cost recovery revenues decreased in the first quarter 2011 when compared to the corresponding period in 2010 primarily due to a decrease in fuel costs associated with decreased KWH generation and a decrease in costs associated with PPAs certificated by the Alabama PSC. 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.

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


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(104)		(60.5)

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 first quarter 2011, wholesale revenues from non-affiliates were $68 million compared to $172 million for the corresponding period in 2010, reflecting a $55 million decrease in revenue from energy sales and a $49 million decrease in capacity revenue. This decrease was primarily due to a 66.3% decrease in KWH sales, partially offset by a

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

16.8% increase in the price. In May 2010, the long-term unit power sales contracts expired and the unit power sales capacity revenues ceased, resulting in a $102 million revenue reduction as compared to the first quarter 2010. 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.

Wholesale Revenues – Affiliates


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(23)		(23.5)

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 first quarter 2011, wholesale revenues from affiliates were $75 million compared to $98 million for the corresponding period in 2010. This decrease was due to a 19.0% decrease in price and a 5.3% decrease in KWH sales.

Fuel and Purchased Power Expenses


First Quarter 2011 vs. First Quarter 2010
	(change in millions)			(% change)
Fuel*	$	(94	)		(19.2	)
Purchased power – non-affiliates		(7	)		(38.9	)
Purchased power – affiliates		(6	)		(11.5	)

Total fuel and purchased power expenses	$	(107	)

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 first quarter 2011, total fuel and purchased power expenses were $452 million compared to $559 million for the corresponding period in 2010. This decrease was primarily due to a $49 million decrease in total KWHs generated, a $28 million decrease in the cost of fuel, and a $20 million decrease in the average cost of 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 Rate ECR. See FUTURE EARNINGS POTENTIAL – “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:


	First Quarter		First Quarter		Percent
Average Cost	2011		2010		Change
	(cents per net KWH)
Fuel*		2.62		2.80		(6.4	)
Purchased power		5.26		7.08		(25.7	)

KWHs generated by hydro are excluded from the average cost of fuel.

In the first quarter 2011, fuel expense was $395 million compared to $489 million for the corresponding period in 2010. The $94 million decrease was due to a 14.6% decrease in KWHs generated by coal, an 8.0% decrease in KWHs generated by natural gas, and a 17.8% decrease in the average cost of KWHs generated by natural gas, which excludes fuel associated with tolling agreements.

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

Non-Affiliates

In the first quarter 2011, purchased power expense from non-affiliates was $11 million compared to $18 million for the corresponding period in 2010. This decrease was related to a 75.6% decrease in the amount of energy purchased, partially offset by a 140.3% 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 first quarter 2011, purchased power expense from affiliates was $46 million compared to $52 million for the corresponding period in 2010. This decrease was related to a 39.9% decrease in the average cost per KWH, partially offset by a 14.0% increase in the amount of energy purchased.

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

Other Operations and Maintenance Expenses


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(13)		(4.2)

In the first quarter 2011, other operations and maintenance expenses were $297 million compared to $310 million for the corresponding period in 2010. Administration and general expenses decreased $9 million related to decreases in affiliated service companies’ expenses, property insurance expense, employee medical and other benefit-related expenses, and injuries and damages expenses. Nuclear production expenses decreased $8 million primarily due to a change to the nuclear maintenance outage accounting process associated with the routine refueling activities, as approved by the Alabama PSC in August 2010. As a result, no nuclear maintenance outage expenses will be recognized in 2011, reducing nuclear production expense by approximately $50 million as compared to 2010. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Nuclear Outage Accounting Order” of Alabama Power in Item 7 of the Form 10-K for additional information. In addition, the decrease in nuclear production expenses was partially offset by an increase in maintenance costs related to increases in labor. Transmission and distribution expenses increased $4 million primarily due to overhead line clearing costs.

Depreciation and Amortization


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$12		8.3

In the first quarter 2011, depreciation and amortization was $157 million compared to $145 million for the corresponding period in 2010. The 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.

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

Allowance for Equity Funds Used During Construction


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(8)		(61.5)

In the first quarter 2011, AFUDC equity was $5 million compared to $13 million for the corresponding period in 2010. This decrease was due to the completion of environmental construction projects at Plants Barry, Gaston, and Miller.

Income Taxes


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(26)		(21.3)

For the first quarter 2011, income taxes were $96 million compared to $122 million for the corresponding period in 2010. This decrease was primarily due to lower pre-tax earnings.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related

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

state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has the right to appeal within 60 days of the order. The ultimate outcome of this matter cannot be determined at this time.

Carbon Dioxide Litigation

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. 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 additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Alabama Power’s facilities which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.

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

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Alabama Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Alabama Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Alabama Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.

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 under recovered fuel costs as of March 31, 2011 totaled $15 million as compared to $4 million at December 31, 2010. These under recovered fuel costs at March 31, 2011 are included in under recovered regulatory clause revenues and deferred under recovered regulatory clause revenues on Alabama Power’s Condensed Balance Sheets herein. This classification is based on an estimate which includes such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery of the under recovered fuel costs.

Natural Disaster Reserve

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 under “Retail Regulatory Matters – Natural Disaster Reserve” 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

Income Tax Matters

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Alabama Power. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Alabama Power estimates the potential increased cash flow for 2011 to be between approximately $100 million and $150 million. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power’s business activities are subject to extensive governmental regulation related to public health and the environment, 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 U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported 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 events in Japan have created uncertainties that may affect transportation of materials, price of fuels, availability of equipment from Japanese manufacturers, and future costs for operating nuclear plants. Specifically, the NRC plans to perform additional operational and safety reviews of existing nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. The ultimate outcome of these events cannot be determined at this time. See RISK FACTORS of Alabama Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Alabama Power’s financial condition remained stable at March 31, 2011. 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 $327 million for the first three months of 2011, an increase of $53 million as compared to the first three months of 2010. The increase in cash provided from operating activities was primarily due to accrued taxes related to refunds received from bonus depreciation and receivables. This is partially offset by a decrease in accounts payable associated with payables to affiliates, a decrease in net income, and the under collection of regulatory clause revenues. Net cash used for investing activities totaled $224 million for the first three months of 2011 primarily due to gross property additions related to steam generation equipment, nuclear fuel, and transmission and distribution expenditures. Net cash used for financing activities totaled $98 million for the first three months of 2011 primarily due to payment of common stock dividends and the issuance and maturity of senior notes. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2011 include decreases of $103 million in other accounts payable related to the timing of outstanding checks associated with property tax payments, $68 million in prepaid expenses related to income taxes, $43 million in unbilled revenues, and $41 million in customer accounts receivable; and increases of $60 million in property, plant, and equipment associated with nuclear fuel and routine property additions and $48 million in debt resulting from greater issuances than maturities.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power’s capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. There are no requirements through March 31, 2012 for maturities of long-term debt.

The approved construction program of Alabama Power includes a base level investment of $0.9 billion for 2011, $0.9 billion for 2012, and $1.1 billion for 2013. Included in Alabama Power’s approved construction program are estimated environmental expenditures to comply with existing statutes and regulations of $47 million, $26 million, and $53 million for 2011, 2012, and 2013, respectively. Alabama Power currently anticipates that additional expenditures may be required to comply with anticipated statutes and regulations. Such additional expenditures are estimated to be in amounts up to $48 million, $108 million, and $354 million for 2011, 2012, and 2013,

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

respectively. If the EPA’s proposed Utility MACT rule is finalized as proposed, Alabama Power estimates that the potential incremental investments in 2011 through 2013 for new environmental regulations will be close to the upper end of the estimates set forth above. 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, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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

Alabama Power’s current liabilities sometimes exceed current assets because of Alabama Power’s debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Alabama Power had at March 31, 2011 cash and cash equivalents of approximately $159 million and unused committed credit arrangements with banks of approximately $1.3 billion. Of the unused credit arrangements, $506 million expire in 2011 and $765 million expire in 2012. Of the credit arrangements that expire in 2011, $372 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 $798 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Alabama Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and other Southern Company subsidiaries. At March 31, 2011, Alabama Power had no commercial paper borrowings outstanding. During the first quarter 2011, Alabama Power had an average of $88 million of commercial paper outstanding at a weighted average interest rate of 0.2% per annum and the maximum amount outstanding was $255 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $303 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.

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

Market Price Risk

During the first quarter 2011, Alabama Power had interest rate swaps totaling $200 million expire, which did not materially increase market risk exposure relative to interest rate changes. Since a significant portion of outstanding indebtedness remains at fixed rates, Alabama Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. 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 first quarter 2011 when compared with the December 31, 2010 reporting period.

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:


	First Quarter
	2011
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(38	)
Contracts realized or settled		11
Current period changes^(a)		—

Contracts outstanding at the end of the period, assets (liabilities), net	$	(27	)

(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 ended March 31, 2011 was an increase of $11 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At March 31, 2011, Alabama Power had a net hedge volume of 31.1 million mmBtu with a weighted average contract cost approximately $0.90 per mmBtu above market prices, compared to 33.9 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.14 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 months ended March 31, 2011 and 2010 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

Alabama Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:


	March 31, 2011
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(27	)		(23	)		(4	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(27	)	$	(23	)	$	(4	)	$	—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Alabama Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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

Financing Activities

In February 2011, Alabama Power’s $200 million Series HH 5.10% Senior Notes due February 1, 2011 matured.

In March 2011, Alabama Power issued $250 million aggregate principal amount of Series 2011A 5.50% Senior Notes due March 15, 2041. The proceeds were used for general corporate purposes, including Alabama Power’s continuous construction program. Alabama Power settled $200 million of interest rate hedges related to the Series 2011A 5.50% Senior Note issuance at a gain of approximately $4 million. The gain will be amortized to interest expense, in earnings, over 10 years.

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
	Ended March 31,
	2011			2010
	(in millions)
Operating Revenues:
Retail revenues	$	1,815		$	1,792
Wholesale revenues, non-affiliates		83			110
Wholesale revenues, affiliates		11			14
Other revenues		80			68

Total operating revenues		1,989			1,984

Operating Expenses:
Fuel		677			758
Purchased power, non-affiliates		74			82
Purchased power, affiliates		163			162
Other operations and maintenance		422			389
Depreciation and amortization		173			114
Taxes other than income taxes		87			80

Total operating expenses		1,596			1,585

Operating Income		393			399
Other Income and (Expense):
Allowance for equity funds used during construction		25			35
Interest expense, net of amounts capitalized		(96	)		(93	)
Other income (expense), net		(1	)		(6	)

Total other income and (expense)		(72	)		(64	)

Earnings Before Income Taxes		321			335
Income taxes		111			93

Net Income		210			242
Dividends on Preferred and Preference Stock		4			4

Net Income After Dividends on Preferred and Preference Stock	$	206		$	238

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months
	Ended March 31,
	2011		2010
	(in millions)
Net Income After Dividends on Preferred and Preference Stock	$	206	$	238
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $— and $2, respectively		1		3

Comprehensive Income	$	207	$	241

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 Three Months
	Ended March 31,
	2011			2010
	(in millions)
Operating Activities:
Net income	$	210		$	242
Adjustments to reconcile net income to net cash provided from operating activities –
Depreciation and amortization, total		210			154
Deferred income taxes		56			59
Deferred revenues		2			(18	)
Deferred expenses		33			25
Allowance for equity funds used during construction		(25	)		(35	)
Pension, postretirement, and other employee benefits		(7	)		(4	)
Stock based compensation expense		4			3
Storm damage accruals		5			5
Other, net		(52	)		(26	)
Changes in certain current assets and liabilities —
-Receivables		122			(9	)
-Fossil fuel stock		(30	)		81
-Materials and supplies		(9	)		1
-Prepaid income taxes		80			23
-Other current assets		(4	)		(8	)
-Accounts payable		(50	)		(17	)
-Accrued taxes		(194	)		(185	)
-Accrued compensation		(65	)		(7	)
-Other current liabilities		64			43

Net cash provided from operating activities		350			327

Investing Activities:
Property additions		(513	)		(625	)
Nuclear decommissioning trust fund purchases		(830	)		(199	)
Nuclear decommissioning trust fund sales		827			150
Cost of removal, net of salvage		1			(14	)
Change in construction payables, net of joint owner portion		93			41
Other investing activities		(6	)		51

Net cash used for investing activities		(428	)		(596	)

Financing Activities:
Decrease in notes payable, net		(62	)		(81	)
Proceeds —
Capital contributions from parent company		171			460
Pollution control revenue bonds issuances		137			—
Senior notes issuances		300			350
Other long-term debt issuances		250			—
Redemptions —
Pollution control revenue bonds		(84	)		—
Senior notes		(101	)		(250	)
Other long-term debt		(300	)		—
Payment of preferred and preference stock dividends		(4	)		(4	)
Payment of common stock dividends		(224	)		(205	)
Other financing activities		(2	)		(2	)

Net cash provided from financing activities		81			268

Net Change in Cash and Cash Equivalents		3			(1	)
Cash and Cash Equivalents at Beginning of Period		8			14

Cash and Cash Equivalents at End of Period	$	11		$	13

Cash paid during the period for —
Interest (net of $9 and $13 capitalized for 2011 and 2010, respectively)		$65		$	62
Income taxes (net of refunds)		(77	)		(6	)
Noncash transactions — accrued property additions at end of period		350			275

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 March 31,			At December 31,
Assets	2011			2010
	(in millions)
Current Assets:
Cash and cash equivalents	$	11		$	8
Receivables —
Customer accounts receivable		540			580
Unbilled revenues		160			172
Under recovered regulatory clause revenues		188			184
Joint owner accounts receivable		54			60
Other accounts and notes receivable		52			67
Affiliated companies		21			21
Accumulated provision for uncollectible accounts		(13	)		(11	)
Fossil fuel stock, at average cost		654			624
Materials and supplies, at average cost		380			371
Vacation pay		77			78
Prepaid income taxes		6			99
Other regulatory assets, current		107			105
Other current assets		66			80

Total current assets		2,303			2,438

Property, Plant, and Equipment:
In service		26,681			26,397
Less accumulated provision for depreciation		10,008			9,966

Plant in service, net of depreciation		16,673			16,431
Other utility plant, net		67			—
Nuclear fuel, at amortized cost		421			386
Construction work in progress		3,304			3,287

Total property, plant, and equipment		20,465			20,104

Other Property and Investments:
Equity investments in unconsolidated subsidiaries		69			70
Nuclear decommissioning trusts, at fair value		791			818
Miscellaneous property and investments		40			42

Total other property and investments		900			930

Deferred Charges and Other Assets:
Deferred charges related to income taxes		731			723
Prepaid pension costs		101			91
Deferred under recovered regulatory clause revenues		128			214
Other regulatory assets, deferred		1,224			1,207
Other deferred charges and assets		191			207

Total deferred charges and other assets		2,375			2,442

Total Assets	$	26,043		$	25,914

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 March 31,			At December 31,
Liabilities and Stockholder’s Equity	2011			2010
	(in millions)
Current Liabilities:
Securities due within one year	$	379		$	415
Notes payable		514			576
Accounts payable —
Affiliated		200			243
Other		644			574
Customer deposits		198			198
Accrued taxes —
Accrued income taxes		34			1
Unrecognized tax benefits		180			187
Other accrued taxes		95			328
Accrued interest		142			94
Accrued vacation pay		56			58
Accrued compensation		46			109
Liabilities from risk management activities		70			77
Other cost of removal obligations, current		31			31
Nuclear decommissioning trust securities lending collateral		100			144
Other current liabilities		162			134

Total current liabilities		2,851			3,169

Long-term Debt		8,169			7,931

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,773			3,718
Deferred credits related to income taxes		127			129
Accumulated deferred investment tax credits		227			229
Employee benefit obligations		685			684
Asset retirement obligations		721			705
Other cost of removal obligations		128			131
Other deferred credits and liabilities		196			211

Total deferred credits and other liabilities		5,857			5,807

Total Liabilities		16,877			16,907

Preferred Stock		45			45

Preference Stock		221			221

Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - 9,261,500 shares		398			398
Paid-in capital		5,467			5,291
Retained earnings		3,045			3,063
Accumulated other comprehensive loss		(10	)		(11	)

Total common stockholder’s equity		8,900			8,741

Total Liabilities and Stockholder’s Equity	$	26,043		$	25,914

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

FIRST QUARTER 2011 vs. FIRST QUARTER 2010

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

In December 2010, the Georgia PSC approved the 2010 ARP including a base rate increase of approximately $562 million effective January 1, 2011. On March 1, 2011, Georgia Power filed a request with the Georgia PSC to adjust its fuel cost recovery rates. The Georgia PSC will conduct public hearings on the fuel cost recovery filing in early May 2011, with a final decision expected on May 24, 2011. If approved, the new fuel cost recovery rates will go into effect June 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


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(32)		(13.4)

Georgia Power’s net income after dividends on preferred and preference stock for the first quarter 2011 was $206 million compared to $238 million for the corresponding period in 2010. The decrease was primarily due to a decrease in the amortization of the regulatory liability related to other cost of removal obligations, an increase in operating and maintenance expenses, a decrease in revenue due to significantly colder weather in the first quarter 2010, and higher income taxes. This decrease was partially offset by an increase in retail base revenues effective January 1, 2011 as authorized by the Georgia PSC in the 2010 ARP.

Retail Revenues


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$23		1.3

Retail revenues for the first quarters 2011 and 2010 were $1.8 billion.

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:


	First Quarter
	2011
	(in millions)			(% change)
Retail — prior year	$	1,792
Estimated change in —
Rates and pricing		141			7.9
Sales growth (decline)		(7	)		(0.4	)
Weather		(31	)		(1.8	)
Fuel cost recovery		(80	)		(4.4	)

Retail — current year	$	1,815			1.3	%

Revenues associated with changes in rates and pricing increased in the first quarter 2011 when compared to the corresponding period in 2010 due to the retail base rate increase and NCCR revenues.

Revenues attributable to changes in sales decreased in the first quarter 2011 when compared to the corresponding period in 2010. Weather-adjusted residential KWH sales decreased 0.2%, weather-adjusted commercial KWH sales decreased 1.8%, and weather-adjusted industrial KWH sales increased 3.5% in the first quarter 2011 when compared to the corresponding period in 2010.

Revenues resulting from changes in weather decreased in the first quarter 2011 when compared to the corresponding period in 2010 as a result of significantly colder weather in the first quarter 2010.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased by $80 million in the first quarter of 2011 when compared to the corresponding period in 2010 due to decreased KWH sales and lower fuel costs.

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


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(27)		(24.5)

Wholesale revenues from non-affiliates will vary depending on fuel prices, 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 first quarter 2011, wholesale revenues from non-affiliates were $83 million compared to $110 million in the corresponding period in 2010, reflecting a $21 million decrease in energy revenues and a $6 million decrease in capacity revenues. The decrease in the first quarter 2011 was primarily due to a 27.4% decrease in KWH sales from lower demand resulting from significantly colder weather in the first quarter 2010 and the expiration of the long-term unit power sales contract in May 2010.

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

Other Revenues


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$12		17.6

In the first quarter 2011, other revenues were $80 million compared to $68 million in the corresponding period in 2010. This increase was primarily due to an $11 million increase in transmission revenues due to the increased usage of Georgia Power’s transmission system by non-affiliated companies.

Fuel and Purchased Power Expenses


First Quarter 2011 vs. First Quarter 2010
	(change in millions)			(% change)
Fuel*	$	(81	)		(10.7	)
Purchased power — non-affiliates		(8	)		(9.8	)
Purchased power — affiliates		1			0.6

Total fuel and purchased power expenses	$	(88	)


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

In the first quarter 2011, total fuel and purchased power expenses were $914 million compared to $1.0 billion in the corresponding period in 2010. The decrease was primarily due to a $34 million net decrease related to lower KWHs generated and purchased primarily due to lower customer demand as a result of significantly colder weather in 2010 and a $54 million decrease in the average cost of fuel and average price of 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 Georgia Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – “Georgia PSC Matters – Fuel Cost Recovery” herein for additional information.

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


	First Quarter		First Quarter		Percent
Average Cost	2011		2010		Change
	(cents per net KWH)
Fuel		3.73		3.78		(1.3	)
Purchased power		5.57		6.36		(12.4	)

In the first quarter 2011, fuel expense was $677 million compared to $758 million in the corresponding period in 2010. This decrease was due to an 11.1% decrease of KWHs generated as a result of lower KWH demand and a 1.3% decrease in the average cost of fuel per KWH generated.

Non-Affiliates

In the first quarter 2011, purchased power expense from non-affiliates was $74 million compared to $82 million in the corresponding period in 2010. This decrease was due to a 29.9% decrease in the volume of KWHs purchased due to lower demand as a result of the significantly colder weather in first quarter 2010, partially offset by a 29.6% increase in the average cost per KWH purchased.

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

Other Operations and Maintenance Expenses


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$33		8.5

In the first quarter 2011, other operations and maintenance expenses were $422 million compared to $389 million in the corresponding period in 2010. This increase was primarily due to increases of $18 million in scheduled outages and maintenance at fossil generating plants, $7 million in transmission and distribution primarily due to maintenance of overhead lines, and $4 million in uncollectible account expense.

Depreciation and Amortization


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$59		51.8

In the first quarter 2011, depreciation and amortization was $173 million compared to $114 million in the corresponding period in 2010. This increase was primarily due to amortization of $10 million compared to $60 million in the first quarter 2011 and 2010, respectively, of the regulatory liability related to other cost of removal obligations as authorized by the Georgia PSC and depreciation on additional plant in service related to transmission, distribution, and environmental projects. See Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” in Item 8 of the Form 10-K for additional information on the other cost of removal regulatory liability.

Taxes Other Than Income Taxes


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$7		8.8

In the first quarter 2011, taxes other than income taxes were $87 million compared to $80 million in the corresponding period in 2010. This increase was primarily due to a $5 million increase in property tax in the first quarter 2011 compared to the corresponding period in 2010.

Allowance for Equity Funds Used During Construction


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(10)		(28.6)

In the first quarter 2011, AFUDC equity was $25 million compared to $35 million in the corresponding period in 2010. This decrease was due to the inclusion of Plant Vogtle Units 3 and 4 construction work in progress in rate base effective January 1, 2011, which reduced the amount of AFUDC capitalized. See Note 3 to the financial statements of Georgia Power under “Construction – Nuclear” in Item 8 of the Form 10-K, Note (B) to the Condensed Financial Statements herein under “State PSC Matters – Georgia Power – Nuclear Construction,” and FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” herein for additional information.

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

Income Taxes


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$18		19.4

In the first quarter 2011, income taxes were $111 million compared to $93 million in the corresponding period in 2010. The increase in income taxes was primarily due to the recognition in the first quarter 2010 of certain state income tax credits that remain subject to litigation and a decrease in non-taxable AFUDC equity in the first quarter 2011, partially offset by lower pre-tax earnings. See 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 Notes (B) and (G) to the Condensed Financial Statements herein under “Income Tax Matters – Georgia State Income Tax Credits” and “Unrecognized Tax Benefits,” respectively, for additional information.

FUTURE EARNINGS POTENTIAL

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

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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. 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

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.

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

Air Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Georgia Power’s facilities which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.

In April 2010, the EPA proposed an Industrial Boiler MACT rule that would establish emissions limits for various hazardous air pollutants typically emitted from industrial boilers, including biomass boilers and start-up boilers. The EPA issued the final rules on February 23, 2011 and, at the same time, issued a notice of intent to reconsider the final rules to allow for additional public review and comment. Georgia Power has delayed the decision to convert Plant Mitchell Unit 3 to biomass until there is greater clarity regarding these regulations. The impact of these regulations will depend on their final form and the outcome of any legal challenges and cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Georgia Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Georgia Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Georgia Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.

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

Georgia PSC Matters

Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information. As of March 31, 2011, Georgia Power had a total under recovered fuel cost balance of approximately $313 million compared to $398 million at December 31, 2010. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor will not have a significant effect on Georgia Power’s revenues or net income, but will affect cash flow.

On March 1, 2011, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 0.61%. The decrease would reduce Georgia Power’s annual billings by approximately $43 million. The decrease in fuel costs is driven primarily by lower natural gas prices than those included in current rates as a result of increases in natural gas supplies from the production of shale gas and lower industrial demand. If approved, the new rates will go into effect June 1, 2011. The ultimate outcome of this matter cannot be determined at this time.

Plant Branch Units 1 and 2 De-certification

See “Environmental Matters – Air Quality” and “– Water Quality” herein and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Air Quality,” “– Water Quality,” and “– Coal Combustion Byproducts” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Regulatory Matters – Rate Plans” in Item 8 of the Form 10-K for additional information regarding potential rules and regulations being developed by the EPA, including the Utility MACT rule for coal- and oil-fired EGUs, revisions to effluent guidelines for steam electric power plants, and additional regulation of coal combustion byproducts; the State of Georgia’s Multi-Pollutant Rule; Georgia Power’s analysis of the potential costs and benefits of installing the required controls on its coal-fired generating units in light of these regulations; and the 2010 ARP.


Scherer 3		July 1, 2011
Branch 1		December 31, 2013
Branch 2		October 1, 2013
Branch 3		October 1, 2015
Branch 4		December 31, 2015

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

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

Storm Damage Reserve

During April 2011, severe storms in Georgia caused significant damage to Georgia Power’s distribution and transmission facilities. Georgia Power maintains a reserve for property damage to cover the operating and maintenance cost of damages from major storms to its transmission and distribution lines as mandated by the Georgia PSC. As a result of this regulatory treatment, the storms are not expected to have a material impact on Georgia Power’s financial statements. See Note 1 to the financial statements of Georgia Power under “Storm Damage Reserve” in Item 8 of the Form 10-K for additional information.

Income Tax Matters

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Georgia Power. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Georgia Power estimates the potential increased cash flow for 2011 to be between approximately $200 million and $275 million. The ultimate outcome of this matter cannot be determined at this time.

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 the construction of Plant Vogtle Units 3 and 4.

In December 2010, Westinghouse submitted an AP1000 Design Certification Amendment (DCA) to the NRC. On February 10, 2011, the NRC announced that it was seeking public comment on a proposed rule to approve the DCA and amend the certified AP1000 reactor design for use in the U.S. The Advisory Committee on Reactor Safeguards also issued a letter on January 24, 2011 endorsing the issuance of the Construction and Operating License (COL) for Plant Vogtle Units 3 and 4. In addition, on March 25, 2011, the NRC submitted to the EPA the final environmental impact statement for Plant Vogtle Units 3 and 4. Georgia Power currently expects to receive the COL for Plant Vogtle Units 3 and 4 from the NRC in late 2011 based on the NRC’s February 16, 2011 release of its COL schedule framework.

On February 21, 2011, the Georgia PSC voted to approve Georgia Power’s third semi-annual construction monitoring report including total costs of $1.048 billion for Plant Vogtle Units 3 and 4 incurred through June 30, 2010. In connection with its certification of Plant Vogtle Units 3 and 4, the Georgia PSC ordered Georgia Power and the PSC

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

Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize Georgia Power’s earnings if and when overruns are due to mandates from governing agencies. Such discussions have continued through the third semi-annual construction monitoring proceedings; however, the Georgia PSC has deferred a decision with respect to any related risk-sharing or incentive mechanism. A Georgia PSC hearing on this matter is scheduled on July 6, 2011 and a decision is expected on August 2, 2011. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

In December 2010, the Georgia PSC approved the NCCR tariff, which became effective January 1, 2011. The NCCR tariff was established to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period in accordance with the Georgia Nuclear Energy Financing Act. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs capitalized in 2009 and 2010 over the five-year period ending December 31, 2015 in addition to the ongoing financing costs. At March 31, 2011, approximately $87 million of these 2009 and 2010 costs are included in construction work in progress.

Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), and a consortium consisting of Westinghouse and Stone & Webster, Inc. have established both informal and formal dispute resolution procedures in order to resolve issues that commonly arise during the course of constructing a project of this magnitude. Southern Nuclear, on behalf of the Owners, has initiated both formal and informal claims through these procedures, including ongoing claims, and anticipates that further issues are likely to arise in the future. The Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. According to published reports, the owner of these units is continuing work to stabilize these units following a loss of operation of the cooling systems for the units. While Georgia Power will continue to monitor this developing situation, it has not identified any immediate impact to the licensing and construction of Plant Vogtle Units 3 and 4 or the operation of its existing nuclear generating units.

See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including petitions filed at the NRC in response to the events in Japan. 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 May 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. As a result, the units are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. The Georgia PSC has approved Georgia Power’s quarterly construction monitoring reports, including actual project expenditures incurred, through June 30, 2010. Georgia Power will continue to file quarterly construction monitoring reports throughout the construction period.

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 U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported 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 GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Unbilled Revenues, and Pension and Other Postretirement Benefits.

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 March 31, 2011. 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 $350 million for the first three months of 2011, compared to $327 million for the corresponding period in 2010. The $23 million increase is primarily due to higher recovery of fuel costs. Net cash used for investing activities totaled $428 million primarily due to gross property additions to utility plant in the first three months of 2011. Net cash provided from financing activities totaled $81 million for the first three months of 2011, compared to $268 million for the corresponding period in 2010. The $187 million decrease is primarily due to higher capital contributions from Southern Company in the first quarter 2010, partially offset by long-term debt issuances in the first quarter 2011.

Significant balance sheet changes for the first three months of 2011 include an increase of $361 million in total property, plant, and equipment, an increase of $238 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 $176 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, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $379 million will be required through March 31, 2012 to fund maturities and announced repurchases of long-term debt.

The construction program of Georgia Power is currently estimated to include a base level investment of $2.1 billion, $2.2 billion, and $2.0 billion for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $73 million, $79 million, and $58 million for 2011, 2012, and 2013, respectively. In addition, Georgia Power currently estimates that potential incremental investments to comply with anticipated new environmental regulations could range from $69 million to $289 million for 2011, $191 million to $651 million for 2012, and $476 million to $1.4 billion for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Georgia Power estimates that the potential incremental investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. 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, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Except as described below with respect to potential DOE loan guarantees, Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, security issuances, term loans, and equity contributions from Southern Company.

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

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

In June 2010, Georgia Power reached an agreement with the DOE to accept terms for a conditional commitment for federal loan guarantees that would apply to future borrowings by Georgia Power related to the construction of Plant Vogtle Units 3 and 4. Any borrowings guaranteed by the DOE would be full recourse to Georgia Power and secured by a first priority lien on Georgia Power’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4. Total guaranteed borrowings would not exceed the lesser of 70% of eligible project costs or approximately $3.4 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 COL 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. See FUTURE EARNINGS POTENTIAL – “Construction – Nuclear” herein for more information on Plant Vogtle Units 3 and 4.

Georgia Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at March 31, 2011 approximately $11 million of cash and cash equivalents and approximately $1.7 billion of unused committed credit arrangements with banks. As of March 31, 2011, of the unused credit arrangements, $595 million expire in 2011 and $1.1 billion expire in 2012. Of the credit arrangements that expire in 2011 and 2012, $40 million contain provisions allowing for two-year term loans executable at expiration and $220 million contain provisions allowing for one-year term loans executable at expiration. Georgia Power expects to renew its credit arrangements, as needed, prior to expiration. At March 31, 2011, the credit arrangements were dedicated to providing liquidity support to Georgia Power’s commercial paper program and approximately $522 million of purchase obligations related to variable rate pollution control revenue bonds. 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 March 31, 2011, Georgia Power had approximately $513 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During the first quarter 2011, the maximum amount of commercial paper outstanding was $681 million and the average amount outstanding was $330 million. The weighted average annual interest rate on commercial paper in the first quarter 2011 was 0.3%. 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, energy price risk management, and construction of new generation. At March 31, 2011, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $27 million. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.4 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Georgia Power’s ability to access capital markets, particularly the short-term debt market.

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

Market Price Risk

Georgia Power’s market risk exposure relative to interest rate changes for the first quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Georgia Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. 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 first quarter 2011 relative to fuel and electricity prices when compared with the December 31, 2010 reporting period.

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:


	First Quarter
	2011
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(100	)
Contracts realized or settled		17
Current period changes^(a)		(1	)

Contracts outstanding at the end of the period, assets (liabilities), net	$	(84	)


(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 ended March 31, 2011 was an increase of $16 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At March 31, 2011, Georgia Power had a net hedge volume of 65.0 million mmBtu with a weighted average contract cost approximately $1.38 per mmBtu above market prices, compared to 58.7 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.74 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 months ended March 31, 2011 and 2010 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

Georgia Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:


	March 31, 2011
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)

Level 1	$	—		$	—		$	—		$	—
Level 2		(84	)		(70	)		(14	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(84	)	$	(70	)	$	(14	)	$	—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Georgia Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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

Financing Activities

In January 2011, Georgia Power’s $100 million aggregate principal amount of Series S 4.0% Senior Notes due January 15, 2011 matured.

In January 2011, Georgia Power issued $300 million aggregate principal amount of Series 2011A Floating Rate Senior Notes due January 15, 2013. The proceeds were used to repay short-term debt and for general corporate purposes, including Georgia Power’s continuous construction program.

Also subsequent to March 31, 2011, Georgia Power purchased and is holding $113.5 million of pollution control revenue bonds. The bonds are expected to be remarketed to investors at a future date.

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
	Ended March 31,
	2011			2010
	(in thousands)
Operating Revenues:
Retail revenues	$	274,826		$	304,750
Wholesale revenues, non-affiliates		31,019			27,914
Wholesale revenues, affiliates		4,135			9,518
Other revenues		14,628			14,530

Total operating revenues		324,608			356,712

Operating Expenses:
Fuel		131,782			152,712
Purchased power, non-affiliates		7,003			7,435
Purchased power, affiliates		16,618			20,413
Other operations and maintenance		80,509			70,418
Depreciation and amortization		31,756			28,071
Taxes other than income taxes		24,896			25,233

Total operating expenses		292,564			304,282

Operating Income		32,044			52,430
Other Income and (Expense):
Allowance for equity funds used during construction		2,135			1,385
Interest income		14			17
Interest expense, net of amounts capitalized		(13,629	)		(11,385	)
Other income (expense), net		(563	)		(533	)

Total other income and (expense)		(12,043	)		(10,516	)

Earnings Before Income Taxes		20,001			41,914
Income taxes		6,759			15,063

Net Income		13,242			26,851
Dividends on Preference Stock		1,551			1,551

Net Income After Dividends on Preference Stock	$	11,691		$	25,300

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months
	Ended March 31,
	2011		2010
	(in thousands)
Net Income After Dividends on Preference Stock	$	11,691	$	25,300
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $(953), respectively		—		(1,518	)
Reclassification adjustment for amounts included in net income, net of tax of $90 and $105, respectively		143		166

Total other comprehensive income (loss)		143		(1,352	)

Comprehensive Income	$	11,834	$	23,948

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 Three Months
	Ended March 31,
	2011			2010
	(in thousands)
Operating Activities:
Net income	$	13,242		$	26,851
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		33,294			29,659
Deferred income taxes		6,249			2,917
Allowance for equity funds used during construction		(2,135	)		(1,385	)
Pension, postretirement, and other employee benefits		(1,256	)		550
Stock based compensation expense		518			623
Other, net		(3,793	)		(520	)
Changes in certain current assets and liabilities —
-Receivables		35,336			6,150
-Prepayments		1,156			983
-Fossil fuel stock		(14,941	)		17,419
-Materials and supplies		(726	)		(1,170	)
-Prepaid income taxes		28,889			4,530
-Property damage cost recovery		—			11
-Other current assets		7			12
-Accounts payable		(8,863	)		(4,443	)
-Accrued taxes		4,053			15,539
-Accrued compensation		(10,000	)		(3,462	)
-Other current liabilities		6,127			6,304

Net cash provided from operating activities		87,157			100,568

Investing Activities:
Property additions		(94,239	)		(81,225	)
Distribution of restricted cash from pollution control revenue bonds		—			2,340
Cost of removal, net of salvage		(5,314	)		(5,759	)
Change in construction payables		3,171			(11,846	)
Payments pursuant to long-term service agreements		(2,198	)		(699	)
Other investing activities		68			(190	)

Net cash used for investing activities		(98,512	)		(97,379	)

Financing Activities:
Decrease in notes payable, net		(6,620	)		(6,599	)
Proceeds —
Common stock issued to parent		50,000			50,000
Capital contributions from parent company		809			1,128
Redemptions —
Senior notes		(125	)		(85	)
Payment of preference stock dividends		(1,551	)		(1,551	)
Payment of common stock dividends		(27,500	)		(26,075	)
Other financing activities		110			605

Net cash provided from financing activities		15,123			17,423

Net Change in Cash and Cash Equivalents		3,768			20,612
Cash and Cash Equivalents at Beginning of Period		16,434			8,677

Cash and Cash Equivalents at End of Period	$	20,202		$	29,289

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $851 and $552 capitalized for 2011 and 2010, respectively)	$	8,284		$	9,461
Income taxes (net of refunds)		(29,557	)		(4,383	)
Noncash transactions — accrued property additions at end of period		17,882			32,308

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 March 31,			At December 31,
Assets	2011			2010
	(in thousands)
Current Assets:
Cash and cash equivalents	$	20,202		$	16,434
Receivables —
Customer accounts receivable		58,954			74,377
Unbilled revenues		44,970			64,697
Under recovered regulatory clause revenues		22,077			19,690
Other accounts and notes receivable		10,253			9,867
Affiliated companies		4,923			7,859
Accumulated provision for uncollectible accounts		(1,518	)		(2,014	)
Fossil fuel stock, at average cost		182,096			167,155
Materials and supplies, at average cost		45,455			44,729
Other regulatory assets, current		16,849			20,278
Prepaid expenses		25,937			58,412
Other current assets		3,259			3,585

Total current assets		433,457			485,069

Property, Plant, and Equipment:
In service		3,738,908			3,634,255
Less accumulated provision for depreciation		1,087,442			1,069,006

Plant in service, net of depreciation		2,651,466			2,565,249
Construction work in progress		200,079			209,808

Total property, plant, and equipment		2,851,545			2,775,057

Other Property and Investments		16,284			16,352

Deferred Charges and Other Assets:
Deferred charges related to income taxes		49,920			46,357
Prepaid pension costs		7,998			7,291
Other regulatory assets, deferred		237,448			219,877
Other deferred charges and assets		29,288			34,936

Total deferred charges and other assets		324,654			308,461

Total Assets	$	3,625,940		$	3,584,939

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 March 31,			At December 31,
Liabilities and Stockholder's Equity	2011			2010
	(in thousands)
Current Liabilities:
Securities due within one year	$	110,000		$	110,000
Notes payable		86,563			93,183
Accounts payable —
Affiliated		39,567			46,342
Other		67,856			68,840
Customer deposits		35,914			35,600
Accrued taxes —
Accrued income taxes		4,613			3,835
Other accrued taxes		11,754			7,944
Accrued interest		18,530			13,393
Accrued compensation		6,234			14,459
Other regulatory liabilities, current		22,860			27,060
Liabilities from risk management activities		7,167			9,415
Other current liabilities		18,863			19,766

Total current liabilities		429,921			449,837

Long-term Debt		1,114,406			1,114,398

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		396,377			382,876
Accumulated deferred investment tax credits		7,771			8,109
Employee benefit obligations		75,472			76,654
Other cost of removal obligations		205,373			204,408
Other regulatory liabilities, deferred		42,378			42,915
Other deferred credits and liabilities		145,382			132,708

Total deferred credits and other liabilities		872,753			847,670

Total Liabilities		2,417,080			2,411,905

Preference Stock		97,998			97,998

Common Stockholder’s Equity:
Common stock, without par value—
Authorized - 20,000,000 shares
Outstanding - March 31, 2011: 4,142,717 shares
- December 31, 2010: 3,642,717 shares		353,060			303,060
Paid-in capital		539,867			538,375
Retained earnings		220,519			236,328
Accumulated other comprehensive loss		(2,584	)		(2,727	)

Total common stockholder’s equity		1,110,862			1,075,036

Total Liabilities and Stockholder’s Equity	$	3,625,940		$	3,584,939

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

FIRST QUARTER 2011 vs. FIRST QUARTER 2010

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 and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of rising costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, fuel prices, and storm restoration costs. Appropriately balancing required costs and capital expenditures 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


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(13.6)		(53.8)

Gulf Power’s net income after dividends on preference stock for the first quarter 2011 was $11.7 million compared to $25.3 million for the corresponding period in 2010. The decrease was primarily due to increases in other operations and maintenance expenses in the first quarter 2011 and significantly colder weather in the first quarter 2010.

Retail Revenues


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(29.9)		(9.8)

In the first quarter 2011, retail revenues were $274.8 million compared to $304.7 million for the corresponding period in 2010.

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:


	First Quarter
	2011
	(in millions)			(% change)
Retail — prior year	$	304.7
Estimated change in —
Rates and pricing		(2.0	)		(0.7	)
Sales growth (decline)		1.2			0.4
Weather		(9.5	)		(3.1	)
Fuel and other cost recovery.		(19.6	)		(6.4	)

Retail — current year	$	274.8			(9.8	)%

Revenues associated with changes in rates and pricing decreased in the first quarter 2011 when compared to the corresponding period in 2010 primarily due to lower recoverable costs under Gulf Power’s environmental cost recovery clause due to lower KWH energy sales.

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

Revenues attributable to changes in sales increased in the first quarter 2011 when compared to the corresponding period in 2010. Weather-adjusted KWH energy sales to residential and commercial customers increased 2.0% and 2.2%, respectively, due to higher use per customer. KWH energy sales to industrial customers increased 7.9% primarily due to the addition of a new large customer and several customers buying more energy during maintenance outages of the customers’ onsite generation facilities.

Revenues attributable to changes in weather decreased in the first quarter 2011 when compared to the corresponding period for 2010 due to significantly colder weather in the first quarter 2010.

Fuel and other cost recovery revenues decreased in the first quarter 2011 when compared to the corresponding period for 2010 primarily due to lower fuel cost for generation and lower purchased power energy cost required to meet a lower level of KWH energy sales. Fuel and other cost recovery revenues include fuel expenses, the energy component of purchased power costs, and purchased power capacity 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 – 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 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


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$3.1		11.1

Wholesale revenues from non-affiliates will vary depending on fuel prices, 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 first quarter 2011, wholesale revenues from non-affiliates were $31.0 million compared to $27.9 million for the corresponding period in 2010. The increase was primarily due to increased capacity revenues as a result of contracts effective in the second quarter 2010.

Wholesale Revenues – Affiliates


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(5.4)		(56.6)

In the first quarter 2011, wholesale revenues from affiliates were $4.1 million compared to $9.5 million for the corresponding period in 2010. The decrease was primarily due to a 43.7% decrease in price related to lower energy rates in the first quarter 2011 and decreased energy revenues related to a 22.9% decrease in KWH energy sales due to decreases in customer demand.

Fuel and Purchased Power Expenses


First Quarter 2011 vs. First Quarter 2010
	(change in millions)			(% change)
Fuel*	$	(21.0	)		(13.7	)
Purchased power — non-affiliates		(0.4	)		(5.8	)
Purchased power — affiliates		(3.8	)		(18.6	)

Total fuel and purchased power expenses	$	(25.2	)


*		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 first quarter 2011, total fuel and purchased power expenses were $155.4 million compared to $180.6 million for the corresponding period in 2010. The decrease in fuel and purchased power expenses was due to a $12.7 million decrease in the average cost of fuel and purchased power and a $12.5 million decrease related to total KWHs generated and purchased.

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

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 – Fuel Cost Recovery” herein for additional information.

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


	First Quarter		First Quarter		Percent
Average Cost	2011		2010		Change
	(cents per net KWH)
Fuel		4.69		5.11		(8.22	)
Purchased power		5.37		5.56		(3.42	)

In the first quarter 2011, fuel expense was $131.8 million compared to $152.7 million for the corresponding period in 2010. The decrease was primarily due to a 45.3% decrease in the average cost of natural gas and a 1.7% decrease in KWHs generated as a result of decreased demand, partially offset by a 2.4% increase in the average cost of coal.

Non-Affiliates

In the first quarter 2011, purchased power expense from non-affiliates was $7.0 million compared to $7.4 million for the corresponding period in 2010. The decrease was primarily due to a 56.3% decrease in the volume of KWHs purchased, partially offset by an 18.3% increase in 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 first quarter 2011, purchased power expense from affiliates was $16.6 million compared to $20.4 million for the corresponding period in 2010. The decrease was primarily due to a 3.4% decrease in average cost per KWH purchased and a 16.5% decrease in the volume of KWHs purchased related to decreases in customer demand.

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


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$10.1		14.3

In the first quarter 2011, other operations and maintenance expenses were $80.5 million compared to $70.4 million for the corresponding period in 2010. The increase was primarily due to planned outage maintenance expenses at Plant Crist.

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

Depreciation and Amortization


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$3.7		13.1

In the first quarter 2011, depreciation and amortization was $31.8 million compared to $28.1 million for the corresponding period in 2010. The increase was primarily due to the addition of environmental control projects and other net additions to transmission and distribution facilities.

Allowance for Equity Funds Used During Construction


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$0.7		54.2

In the first quarter 2011, AFUDC equity was $2.1 million compared to $1.4 million for the corresponding period in 2010. The increase was primarily due to construction of environmental control projects.

Interest Expense, Net of Amounts Capitalized


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$2.2		19.7

In the first quarter 2011, interest expense, net of amounts capitalized was $13.6 million compared to $11.4 million for the corresponding period in 2010. The increase was primarily due to an increase in long-term debt resulting from the issuance of additional senior notes.

Income Taxes


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(8.3)		(55.1)

In the first quarter 2011, income taxes were $6.8 million compared to $15.1 million for the corresponding period in 2010. The decrease was primarily due to lower pre-tax earnings.

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

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. 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

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters — Carbon Dioxide Litigation – Kivalina Case” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. 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 additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Gulf Power’s facilities which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered

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

through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters — Environmental Statutes and Regulations – Water Quality” of Gulf Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Gulf Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Gulf Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.

Florida PSC Matters

Fuel Cost Recovery

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In previous 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 March 31, 2011 totaled $19.8 million, compared to $17.4 million at December 31, 2010. This amount is included in under recovered regulatory clause revenues on Gulf Power’s Condensed Balance Sheets herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any change in the billing factor would have no significant effect on Gulf Power’s revenues or net income, but would affect cash flow. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Gulf Power in Item 7 and Notes 1 and 3 to the financial statements of Gulf Power under “Revenues” and “Retail Regulatory Matters – Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information.

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

Environmental Cost Recovery

In July 2010, Mississippi Power filed a request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $625 million and is scheduled for completion in early 2015. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011, but a final order has not yet been issued. On May 5, 2011, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in November 2011. The ultimate outcome of this matter cannot be determined at this time. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL – “PSC Matters – Environmental Cost Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters — Environmental Cost Recovery” in Item 8 of the Form 10-K for additional information.

Energy Conservation Cost Recovery

Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the Energy Conservation Cost Recovery clause.

The most recent goal setting process established new DSM goals for the period 2010-2019. The new goals are significantly larger than the goals established in the previous five-year cycle due to a change in the cost-effectiveness test on which the Florida PSC relies to set the goals. Throughout 2010, Gulf Power engaged in a process at the Florida PSC to develop plans and programs to meet the new DSM goals. The DSM program standards were approved in April 2011, which allow Gulf Power to implement its DSM programs designed to meet the new goals. Higher cost recovery rates and achievement of the new DSM goals may result in reduced sales of electricity which could negatively impact results of operations, cash flows, and financial condition if base rates cannot be adjusted on a timely basis.

See BUSINESS under “Rate Matters – Integrated Resource Planning – Gulf Power” in Item 1 of the Form 10-K for a discussion of Gulf Power’s 10-year site plan filed on an annual basis with the Florida PSC.

Income Tax Matters

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Gulf Power. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Gulf Power estimates the potential increased cash flow for 2011 to be between approximately $30 million and $40 million. The ultimate outcome of this matter cannot be determined at this time.

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 U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against 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.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Gulf Power’s financial condition remained stable at March 31, 2011. 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 $87.2 million for the first three months of 2011 compared to $100.6 million for the corresponding period in 2010. The $13.4 million decrease was primarily due to a $32.4 million use of cash related to fuel inventory increases in 2011 compared to reductions in 2010, a $13.6 million decrease in net income, and an $8.4 million decrease due to payments to non-affiliates, partially offset by a $27.9 million increase related to the declining balance of customer receivables in 2011 compared to its increasing balance in 2010, which was driven by weather-related demands, and a $13.7 million increase from taxes primarily related to refunds received. Net cash used for investing activities totaled $98.5 million in the first three months of 2011 compared to $97.4 million for the corresponding period in 2010. The $1.1 million increase in cash used was primarily due to gross property additions. Net cash provided from financing activities totaled $15.1 million for the first three months of 2011, compared to $17.4 million for the corresponding period in 2010. The $2.3 million decrease was primarily due to higher common stock dividends in 2011.

Significant balance sheet changes for the first quarter 2011 include a net increase of $76.5 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 $32.5 million in prepaid expenses, primarily related to prepaid income taxes; and a $14.9 million increase in fossil fuel stock.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power’s capital requirements for its construction program, maturities of long-term debt, as well as the related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $110 million will be required through March 31, 2012 for maturities of long-term debt.

The construction program of Gulf Power is currently estimated to include a base level investment of $381.5 million, $395.5 million, and $384.1 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $175.9 million, $227.8 million, and $214.0 million for 2011, 2012, and 2013, respectively. In addition, Gulf Power currently estimates that potential incremental investments to comply with anticipated new environmental regulations are up to $17.1 million for 2011, up to $55.6 million for 2012, and up to $107.3 million for 2013. If the EPA’s proposed Utility MACT rule is finalized as

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

proposed, Gulf Power estimates the potential investments in 2011 through 2013 for new environmental regulations will be closer to the upper end of the ranges set forth above. 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, including unit retirements and replacements, to meet new regulatory requirements; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

Gulf Power’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet 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 March 31, 2011 approximately $20.2 million of cash and cash equivalents and $240 million of unused committed credit arrangements with banks that will expire in 2011. During the first quarter of 2011, one line of credit for $30 million was extended until July 2011. Subsequent to March 31, 2011, Gulf Power extended the maturity on two other lines of credit totaling $75 million until July 2011. Gulf Power expects to renew these lines of credit in July for at least a 364-day period. Of the credit arrangements, $210 million contain provisions allowing one-year term loans executable at expiration. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration. These credit arrangements provide liquidity support to Gulf Power’s commercial paper borrowings and $69 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Gulf Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At March 31, 2011, Gulf Power had $83.0 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.3% per annum. During the first quarter 2011, Gulf Power had an average of $55 million of commercial paper outstanding at a weighted average interest rate of 0.3% per annum and the maximum amount outstanding was $103 million. Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, and cash.

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At March 31, 2011, the maximum potential collateral requirements under these contracts at a BBB- and/or Baa3 rating were approximately $125 million. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $530 million. Included in these amounts are certain agreements

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

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.

Market Price Risk

Gulf Power’s market risk exposure relative to interest rate changes for the first quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Gulf Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Gulf Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. 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 and, to a lesser extent, into financial hedge contracts for natural gas purchases. Gulf Power continues to manage a financial hedging program for fuel purchased to operate its electric generating fleet implemented per the guidelines of the Florida PSC. As such, Gulf Power had no material change in market risk exposure for the first quarter 2011 when compared with the December 31, 2010 reporting period.

The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:


	First Quarter
	2011
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(11	)
Contracts realized or settled		2
Current period changes^(a)		1

Contracts outstanding at the end of the period, assets (liabilities), net	$	(8	)


(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 ended March 31, 2011 was an increase of $3 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and prices of natural gas. At March 31, 2011, Gulf Power had a net hedge volume of 20.3 million mmBtu with a weighted average contract cost approximately $0.46 per mmBtu above market prices, compared to 19.6 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $0.67 per mmBtu above market prices. Natural gas settlements 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 months ended March 31, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.

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 market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:


	March 31, 2011
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(8	)		(5	)		(3	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(8	)	$	(5	)	$	(3	)	$	—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Gulf Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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

On January 20, 2011, 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 indebtedness and for other general corporate purposes, including Gulf Power’s continuous construction program.

Subsequent to March 31, 2011, Gulf Power extended the maturity date of a $110 million variable rate bank note until June 30, 2011.

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
	Ended March 31,
	2011			2010
	(in thousands)
Operating Revenues:
Retail revenues	$	180,474		$	186,587
Wholesale revenues, non-affiliates		69,851			78,889
Wholesale revenues, affiliates		9,300			14,675
Other revenues		3,651			3,487

Total operating revenues		263,276			283,638

Operating Expenses:
Fuel		121,054			130,797
Purchased power, non-affiliates		1,010			3,621
Purchased power, affiliates		8,350			14,721
Other operations and maintenance		70,367			67,338
Depreciation and amortization		19,863			18,675
Taxes other than income taxes		17,481			18,460

Total operating expenses		238,125			253,612

Operating Income		25,151			30,026
Other Income and (Expense):
Allowance for equity funds used during construction		3,131			18
Interest income		342			33
Interest expense, net of amounts capitalized		(6,013	)		(6,179	)
Other income (expense), net		(403	)		1,531

Total other income and (expense)		(2,943	)		(4,597	)

Earnings Before Income Taxes		22,208			25,429
Income taxes		7,158			9,743

Net Income		15,050			15,686
Dividends on Preferred Stock		433			433

Net Income After Dividends on Preferred Stock	$	14,617		$	15,253

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months
	Ended March 31,
	2011			2010
	(in thousands)
Net Income After Dividends on Preferred Stock	$	14,617		$	15,253
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1) and $12, respectively		(2	)		20

Comprehensive Income	$	14,615		$	15,273

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 Three Months
	Ended March 31,
	2011			2010
	(in thousands)
Operating Activities:
Net income	$	15,050		$	15,686
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		21,442			20,118
Deferred income taxes		10,015			(8,080	)
Investment tax credits received		9,750			—
Allowance for equity funds used during construction		(3,131	)		(18	)
Pension, postretirement, and other employee benefits		1,037			1,822
Stock based compensation expense		813			757
Tax benefit of stock options		73			24
Generation construction screening costs		—			(18,832	)
Other, net		(1,436	)		1,138
Changes in certain current assets and liabilities —
-Receivables		11,592			7,715
-Fossil fuel stock		(538	)		17,761
-Materials and supplies		(317	)		(885	)
-Prepaid income taxes		15,976			—
-Other current assets		1,649			(8,262	)
-Accounts payable		17,538			970
-Accrued taxes		(31,213	)		(12,109	)
-Accrued compensation		(9,556	)		(7,719	)
-Over recovered regulatory clause revenues		7,756			7,596
-Other current liabilities		(149	)		(708	)

Net cash provided from operating activities		66,351			16,974

Investing Activities:
Property additions		(148,917	)		(19,054	)
Cost of removal, net of salvage		(2,830	)		(3,375	)
Construction payables		33,291			2,812
Capital grant proceeds		16,912			—
Distribution of restricted cash		50,000			—
Other investing activities		(834	)		(5,316	)

Net cash used for investing activities		(52,378	)		(24,933	)

Financing Activities:
Proceeds —
Capital contributions from parent company		50,610			752
Gross excess tax benefit of stock options		106			75
Redemptions —
Capital leases		(349	)		(323	)
Other long-term debt		(130,000	)		—
Payment of preferred stock dividends		(433	)		(433	)
Payment of common stock dividends		(18,875	)		(17,150	)
Other financing activities		(418	)		(1	)

Net cash used for financing activities		(99,359	)		(17,080	)

Net Change in Cash and Cash Equivalents		(85,386	)		(25,039	)
Cash and Cash Equivalents at Beginning of Period		160,779			65,025

Cash and Cash Equivalents at End of Period	$	75,393		$	39,986

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $994 and $9 capitalized for 2011 and 2010, respectively)	$	6,135		$	7,028
Income taxes (net of refunds)		(32,294	)		(3,821	)
Noncash transactions – accrued property additions at end of period		72,114			6,501

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 March 31,			At December 31,
Assets	2011			2010
	(in thousands)
Current Assets:
Cash and cash equivalents	$	75,393		$	160,779
Restricted cash and cash equivalents		—			50,000
Receivables —
Customer accounts receivable		31,355			37,532
Unbilled revenues		25,992			31,010
Other accounts and notes receivable		9,345			11,220
Affiliated companies		30,905			17,837
Accumulated provision for uncollectible accounts		(467	)		(638	)
Fossil fuel stock, at average cost		112,777			112,240
Materials and supplies, at average cost		28,988			28,671
Other regulatory assets, current		60,440			63,896
Prepaid income taxes		46,458			59,596
Other current assets		21,482			19,057

Total current assets		442,668			591,200

Property, Plant, and Equipment:
In service		2,416,242			2,392,477
Less accumulated provision for depreciation		980,896			971,559

Plant in service, net of depreciation		1,435,346			1,420,918
Construction work in progress		383,619			274,585

Total property, plant, and equipment		1,818,965			1,695,503

Other Property and Investments		6,111			5,900

Deferred Charges and Other Assets:
Deferred charges related to income taxes		21,521			18,065
Other regulatory assets, deferred		128,379			132,420
Other deferred charges and assets		20,357			33,233

Total deferred charges and other assets		170,257			183,718

Total Assets	$	2,438,001		$	2,476,321

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 March 31,		At December 31,
Liabilities and Stockholder’s Equity	2011		2010
	(in thousands)
Current Liabilities:
Securities due within one year	$	126,465	$	256,437
Accounts payable —
Affiliated		48,146		51,887
Other		116,911		59,295
Customer deposits		13,181		12,543
Accrued taxes —
Accrued income taxes		8,753		4,356
Other accrued taxes		16,147		51,709
Accrued interest		5,132		5,933
Accrued compensation		6,521		16,076
Other regulatory liabilities, current		5,730		6,177
Over recovered regulatory clause liabilities		84,802		77,046
Liabilities from risk management activities		24,825		27,525
Other current liabilities		20,454		20,115

Total current liabilities		477,067		589,099

Long-term Debt		461,696		462,032

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		298,724		281,967
Deferred credits related to income taxes		12,096		11,792
Accumulated deferred investment tax credits		43,098		33,678
Employee benefit obligations		114,369		113,964
Other cost of removal obligations		115,192		111,614
Other regulatory liabilities, deferred		60,452		58,814
Other deferred credits and liabilities		37,865		43,213

Total deferred credits and other liabilities		681,796		655,042

Total Liabilities		1,620,559		1,706,173

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		444,344		392,790
Retained earnings		302,627		306,885
Accumulated other comprehensive income (loss)		—		2

Total common stockholder’s equity		784,662		737,368

Total Liabilities and Stockholder’s Equity	$	2,438,001	$	2,476,321

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

MISSISSIPPI POWER COMPANY

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

FIRST QUARTER 2011 vs. FIRST QUARTER 2010

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

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


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(0.7)		(4.2)

Mississippi Power’s net income after dividends on preferred stock for the first quarter 2011 was $14.6 million compared to $15.3 million for the corresponding period in 2010. The decrease in net income after dividends on preferred stock for the first quarter 2011 was primarily due to an increase in other operations and maintenance expenses, a decrease in other income (expense), net primarily resulting from a decrease in amounts collected from customers for contributions in aid of construction, a decrease in capacity revenues from customers served outside Mississippi Power’s service territory, and a decrease in territorial base revenues due to significantly colder weather in the first quarter 2010. The decrease in net income after dividends on preferred stock for the first quarter 2011 was partially offset by an increase in AFUDC equity resulting from construction of the Kemper IGCC.

Retail Revenues


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(6.1)		(3.3)

In the first quarter 2011, retail revenues were $180.5 million compared to $186.6 million for the corresponding period in 2010.

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

Details of the change to retail revenues are as follows:


	First Quarter
	2011
	(in millions)			(% change)
Retail – prior year	$	186.6
Estimated change in —
Rates and pricing		1.0			0.5
Sales growth (decline)		3.5			1.9
Weather		(4.0	)		(2.2	)
Fuel and other cost recovery		(6.6	)		(3.5	)

Retail – current year	$	180.5			(3.3	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2011 when compared to the corresponding period in 2010 due to an increase of $1.0 million related to the ECO Plan rate. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Environmental Compliance Overview Plan” of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Mississippi PSC Matters – Retail Regulatory Matters – Environmental Compliance Overview Plan” herein for additional information.

Revenues attributable to changes in sales increased in the first quarter 2011 when compared to the corresponding period in 2010, primarily resulting from the continued recovery of some larger industrial customers. KWH energy sales to industrial customers increased 6.5% due to increased production for several large industrial customers resulting from improving economic conditions. Weather-adjusted KWH energy sales to the residential and commercial customers remained relatively flat when compared to the corresponding period in 2010.

Revenues attributable to changes in weather decreased in the first quarter 2011 when compared to the corresponding period for 2010 primarily due to significantly colder weather in the first quarter 2010.

Fuel and other cost recovery revenues decreased in the first quarter 2011 when compared to the corresponding period in 2010 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power’s service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(9.0)		(11.5)

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

In the first quarter 2011, wholesale revenues from non-affiliates were $69.9 million compared to $78.9 million for the corresponding period in 2010. The decrease was due to $6.6 million in decreased revenues from customers inside Mississippi Power’s service territory and $2.4 million in decreased revenues from customers outside Mississippi Power’s

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

service territory. The $6.6 million decrease in revenues from customers inside Mississippi Power’s service territory was primarily due to a $6.1 million decrease in fuel revenues and a $0.5 million decrease in wholesale base revenues due to significantly colder weather in the first quarter 2010, partially offset by a wholesale base rate increase effective January 2011. The $2.4 million decrease in revenues from customers outside Mississippi Power’s service territory was primarily due to a $1.1 million decrease in sales, a $0.5 million decrease associated with lower prices resulting from lower marginal cost of fuel, and a $0.8 million decrease in capacity revenues.

Wholesale Revenues – Affiliates


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(5.4)		(36.6)

In the first quarter 2011, wholesale revenues from affiliates were $9.3 million compared to $14.7 million for the corresponding period in 2010. The decrease was primarily due to a $4.4 million decrease in energy revenues, of which $2.9 million was associated with decreased sales and $1.5 million was associated with lower prices. Capacity revenues decreased by $1.0 million.

Fuel and Purchased Power Expenses


First Quarter 2011 vs. First Quarter 2010
	(change in millions)			(% change)
Fuel	$	(9.7	)		(7.4	)
Purchased power – non-affiliates		(2.6	)		(72.1	)
Purchased power – affiliates		(6.4	)		(43.3	)

Total fuel and purchased power expenses	$	(18.7	)

In the first quarter 2011, total fuel and purchased power expenses were $130.4 million compared to $149.1 million for the corresponding period in 2010. The decrease was primarily due to an $11.7 million decrease in cost of fuel and purchased power and a $7.0 million decrease in total KWHs generated and purchased.

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

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


	First Quarter		First Quarter		Percent
Average Cost	2011		2010		Change
	(cents per net KWH)
Fuel		3.92		4.23		(7.3	)
Purchased power		3.08		3.76		(18.1	)

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

In the first quarter 2011, fuel expense was $121.1 million compared to $130.8 million for the corresponding period in 2010. The decrease was primarily due to a 7.3% decrease in the price of fuel primarily resulting from lower gas prices and a 0.1% decrease in generation from Mississippi Power facilities resulting from lower energy demand in the first quarter 2011 compared to the corresponding period in 2010.

Non-Affiliates

In the first quarter 2011, purchased power expense from non-affiliates was $1.0 million compared to $3.6 million for the corresponding period in 2010. The decrease was primarily the result of a 54.2% decrease in the average cost of purchased power per KWH and a 39.1% decrease in KWH volume purchased. The decrease in prices was due to a lower marginal cost of fuel while the decrease in volume was a result of higher cost opportunity purchases.

Affiliates

In the first quarter 2011, purchased power expense from affiliates was $8.3 million compared to $14.7 million for the corresponding period in 2010. The decrease was primarily due to a 37.3% decrease in KWH volume purchased and a 9.5% decrease in the average cost of purchased power per KWH.

Other Operations and Maintenance Expenses


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$3.1		4.5

In the first quarter 2011, other operations and maintenance expenses were $70.4 million compared to $67.3 million for the corresponding period in 2010. The increase was primarily due to a $2.9 million increase in generation maintenance expenses for several major scheduled outages and a $1.0 million increase in expense for a combined cycle long-term service agreement due to a 29% increase in operating hours as a result of lower gas prices. These expenses were partially offset by a $0.7 million decrease in administrative and general expenses primarily due to pension costs and other employee benefits.

Depreciation and Amortization


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$1.2		6.4

In the first quarter 2011, depreciation and amortization was $19.9 million compared to $18.7 million for the corresponding period in 2010. The increase was primarily due to a $1.0 million increase in depreciation resulting from an increase in plant in service.

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

Taxes Other Than Income Taxes


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(1.0)		(5.3)

In the first quarter 2011, taxes other than income taxes were $17.5 million compared to $18.5 million for the corresponding period in 2010. The decrease was primarily due to a $1.3 million decrease in ad valorem taxes and a $0.2 million decrease in franchise taxes, partially offset by a $0.4 million increase in corporate franchise taxes and a $0.1 million increase in payroll taxes.

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

Allowance for Equity Funds Used During Construction


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$3.1		N/M

N/M – Not meaningful

In the first quarter 2011, AFUDC equity increased $3.1 million as compared to the corresponding period in 2010 primarily due to increases in construction of the Kemper IGCC which began in June 2010 with the approval of the certificate order by the Mississippi PSC. See Note 3 to the financial statements of Mississippi Power under “Integrated Coal Gasification Combined Cycle” in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – “Integrated Coal Gasification Combined Cycle” herein for additional information regarding the Kemper IGCC.

Interest Expense, Net of Amounts Capitalized


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(0.2)		(2.7)

In the first quarter 2011, interest expense, net of amounts capitalized was $6.0 million compared to $6.2 million for the corresponding period in 2010. The decrease was primarily due to a $1.0 million increase in AFUDC debt expense primarily associated with the Kemper IGCC, partially offset by a $0.7 million increase in interest expense associated with the issuance of new long-term debt in September and December 2010.

Other Income (Expense), Net


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
($1.9)		N/M

N/M – Not meaningful

In the first quarter 2011, other income (expense), net was ($0.4) million compared to $1.5 million for the corresponding period in 2010. The decrease was primarily due to a $1.5 million decrease in amounts collected from customers for contributions in aid of construction and a $0.5 million decrease in customer projects.

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

Income Taxes


First Quarter 2011 vs. First Quarter 2010

(change in millions)		(% change)
$(2.5)		(26.5)

In the first quarter 2011, income taxes were $7.2 million compared to $9.7 million for the corresponding period in 2010. The decrease was primarily due to a $1.3 million decrease resulting from the decrease in pre-tax earnings and a $1.2 million decrease due to an increase in AFUDC equity which is non-taxable.

FUTURE EARNINGS POTENTIAL

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

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters” in Item 8 of the Form 10-K for additional information.

New Source Review Actions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – New Source Review Actions” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – New Source Review Actions” in Item 8 of the Form 10-K for additional information regarding civil actions brought by the EPA against certain Southern Company subsidiaries. The EPA’s action against Alabama Power alleged that Alabama Power violated the NSR provisions of the Clean Air Act and related state laws with respect to certain of its coal-fired generating facilities. On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has the right to appeal within 60 days of the order. The ultimate outcome of this matter cannot be determined at this time.

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

Carbon Dioxide Litigation

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Environmental Matters – Carbon Dioxide Litigation — Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. 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 additional information regarding regulation of air quality. On May 3, 2011, the EPA published a proposed rule, called Utility MACT (Maximum Achievable Control Technology), which would impose stringent emission limits on coal- and oil-fired electric utility steam generating units (EGUs). The proposed rule establishes numeric emission limits for acid gases, mercury, and total particulate matter. Meeting the proposed limits would likely require additional emission control equipment such as scrubbers, SCRs, baghouses, and other control measures at many coal-fired EGUs. Pursuant to a court-approved consent decree, the EPA must issue a final rule by November 16, 2011. Compliance for existing sources would be required three years after the effective date of the final rule. In the proposed rule, the EPA discussed the possibility of a one-year compliance extension which could be granted by the EPA or the states on a case-by-case basis if necessary. If finalized as proposed, compliance with this rule would require significant capital expenditures and compliance costs at many of Mississippi Power’s facilities which could impact unit retirement and replacement decisions. In addition, results of operations, cash flows, and financial condition could be impacted if the costs are not recovered through regulated rates. Further, there is uncertainty regarding the ability of the electric utility industry to achieve compliance with the requirements of the proposed rule within the proposed compliance period, and the limited compliance period could negatively impact electric system reliability. The outcome of this rulemaking cannot be determined at this time.

In October 2008, the EPA approved a revision to Alabama’s State Implementation Plan (SIP) requirements related to opacity which granted some flexibility to affected sources while requiring compliance with Alabama’s very strict opacity limits through use of continuous opacity monitoring system data. In a decision published on April 6, 2011, the EPA responded to an environmental group’s request for reconsideration by attempting to rescind its previous approval of the Alabama SIP revision. Mississippi Power’s jointly-owned facility with Alabama Power in Greene County, Alabama is impacted by this decision. On April 8, 2011, Alabama Power filed an appeal of that decision with the U.S. Court of Appeals for the Eleventh Circuit and requested the court to stay the effectiveness of the EPA’s attempted rescission pending judicial review. Absent a stay, the EPA’s decision will become effective May 6, 2011 and the rule under which Alabama Power has been operating since January 2009 may not be available unless Alabama Power’s appeal is resolved in its favor by the court. If the EPA’s decision is allowed to take effect, it will likely impact unit availability and result in increased maintenance and compliance costs. The final outcome of this matter cannot be determined at this time.

Water Quality

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Environmental Statutes and Regulations – Water Quality” of Mississippi Power in Item 7 of the Form 10-K for additional information regarding regulation of water quality. On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing

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

facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at many of Mississippi Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Mississippi Power’s facilities may be subject to significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate outcome of this rulemaking cannot be determined at this time.

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 2010, Mississippi Power filed its annual PEP filing for 2011, which indicated a rate increase of 1.936%, or $16.1 million, annually. On January 10, 2011, the Mississippi Public Utilities Staff (MPUS) contested the filing. The ultimate outcome of this matter cannot be determined at this time.

On March 15, 2011, Mississippi Power submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. On May 2, 2011, Mississippi Power received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. The ultimate outcome of this matter cannot be determined at this time.

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.

On January 31, 2011, Mississippi Power submitted its 2011 SRR rate filing with the Mississippi PSC, which proposed that Mississippi Power be allowed to accrue approximately $3.6 million to the property damage reserve in 2011. On May 5, 2011, the filing was approved by the Mississippi PSC.

Environmental Compliance Overview Plan

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

On February 14, 2011, Mississippi Power submitted its ECO Plan notice which proposed an immaterial decrease in annual revenues. In addition, Mississippi Power proposed to change the ECO Plan collection period to more appropriately match ECO revenues with ECO expenditures. On April 7, 2011, due to changes in ECO Plan cost projections, Mississippi Power submitted a revised 2011 ECO Plan which changed the requested annual revenues to a $0.9 million decrease. On May 5, 2011, hearings on the revised ECO Plan were held and the filing was approved by the Mississippi PSC with the new rates effective in May 2011.

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

Plan. Hearings on the certificate request were held by the Mississippi PSC on January 25, 2011, but a final order has not yet been issued. On May 5, 2011, in conjunction with the ECO Plan hearings, the Mississippi PSC approved up to $19.5 million (with respect to Mississippi Power’s ownership portion) in spending for 2011 for the scrubber project. A decision on a final order is not anticipated prior to issuance of the final Utility MACT rule in November 2011. The ultimate outcome of this matter cannot be determined at this time.

Certificated New Plant

On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-A (CNP-A), a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. Annual CNP-A rate filings would be made with the first filing occurring in November 2011. If approved by the Mississippi PSC, recovery through CNP-A will remain in place thereafter until the end of the calendar year that the Kemper IGCC is placed into commercial service, which is projected to be 2014. Certificated New Plant-B, which will be filed at a later date, would propose to govern rates effective from the first calendar year after the Kemper IGCC is placed into commercial service through the first seven full calendar years of its operation. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “PSC Matters – Fuel Cost Recovery” of Mississippi Power in Item 7 of the Form 10-K for information regarding Mississippi Power’s fuel cost recovery. Mississippi Power establishes, annually, a 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 2010. The Mississippi PSC approved the retail fuel cost recovery factor in December 2010, with the new rates effective in January 2011. The retail fuel cost recovery factor will result in an annual decrease in an amount equal to 5.0% of total 2010 retail revenue. At March 31, 2011, the amount of over recovered retail fuel costs included in the balance sheets was $57.7 million compared to $55.2 million at December 31, 2010. Mississippi Power also has a wholesale Municipal and Rural Associations (MRA) and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2011, the wholesale MRA fuel rate decreased, resulting in an annual decrease in an amount equal to 3.5% of total 2010 MRA revenue. Effective February 1, 2011, the wholesale MB fuel rate decreased, resulting in an annual decrease in an amount equal to 7.0% of total 2010 MB revenue. At March 31, 2011, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $21.6 million and $5.2 million compared to $17.5 million and $4.4 million, respectively, at December 31, 2010. In addition, at March 31, 2011, the amount of over recovered MRA emissions allowance cost included in the balance sheet was $0.4 million. See Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K for additional information. 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 factors will have no significant effect on Mississippi Power’s revenues or net income, but will decrease annual cash flow.

In October 2010, the Mississippi PSC engaged an independent professional audit firm to conduct an audit of Mississippi Power’s fuel-related expenditures included in the retail fuel adjustment clause and energy cost management clause (ECM) for 2010. The audit was completed in the first quarter 2011 with no audit findings.

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.

In June 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant the Certificate of Public Convenience and Necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, in July 2010, the Sierra Club also filed an

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

appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Club’s direct appeal. On February 28, 2011, the Chancery Court issued a judgment affirming the Mississippi PSC’s order authorizing the construction of the Kemper IGCC. On March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court.

In May 2009, Mississippi Power received notification from the IRS formally certifying the IRS allocated Internal Revenue Code Section 48A tax credits (Phase I) of $133 million to Mississippi Power. On April 19, 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II tax credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the carbon dioxide (CO₂) produced by the plant during operations in accordance with the recapture rules for Section 48A investment tax credits. Through March 31, 2011, Mississippi Power received and accrued tax benefits totaling $31.9 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC.

In February 2008, Mississippi Power requested that the DOE transfer the remaining funds previously granted under the Clean Coal Power Initiative Round 2 (CCPI2) from a cancelled IGCC project of one of Southern Company’s subsidiaries that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. Mississippi Power will receive grant funds of $245 million during the construction of the plant and $25 million during the initial operation of the plant. Through March 31, 2011, Mississippi Power has received $40 million and requested an additional $20.1 million associated with this grant.

On March 10, 2011, the Sierra Club filed a lawsuit in the U.S. District Court for the District of Columbia against the DOE regarding the National Environmental Policy Act review process asking for a stay on the issuance of CCPI2 funds and a stay to any related construction activities. On May 5, 2011, Mississippi Power filed a motion to intervene in this lawsuit.

In March 2010, the Mississippi Department of Environmental Quality (MDEQ) issued the Prevention of Significant Deterioration (PSD) air permit modification for the plant, which modifies the original PSD air permit issued in October 2008. The Sierra Club requested a formal evidentiary hearing regarding the issuance of the modified permit. On April 4, 2011, the MDEQ Permit Board held an evidentiary hearing wherein the permit board unanimously affirmed the PSD air permit.

On March 4, 2011, Mississippi Power and Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., entered into a contract in which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC.

On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing CNP-A, a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. See “Mississippi PSC Matters – Retail Regulatory Matters – Certificated New Plant” herein for additional information.

Events in Japan resulting from the earthquake and tsunami created uncertainties that may affect transportation and availability of equipment or supplies from Japanese manufacturers in connection with the construction of the Kemper IGCC.

As of March 31, 2011, Mississippi Power had spent a total of $352.8 million on the Kemper IGCC, including regulatory filing costs. Of this total, $277 million was included in CWIP (net of $60.1 million of CCPI2 grant funds), $13.2 million was recorded in other regulatory assets, $1.5 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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Income Tax Matters

Bonus Depreciation

In September 2010, the Small Business Jobs and Credit Act of 2010 (SBJCA) was signed into law. The SBJCA includes an extension of the 50% bonus depreciation for certain property acquired and placed in service in 2010 (and for certain long-term construction projects to be placed in service in 2011). Additionally, in December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term construction projects to be placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term construction projects to be placed in service in 2013), which will have a positive impact on the future cash flows of Mississippi Power. On March 29, 2011, the IRS issued additional guidance and safe harbors relating to the 50% and 100% bonus depreciation rules. Based on this guidance, Mississippi Power estimates the potential increased cash flow for 2011 to be between approximately $15 million and $20 million. The ultimate outcome of this matter cannot be determined at this time.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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FINANCIAL CONDITION AND LIQUIDITY

Overview

Mississippi Power’s financial condition remained stable at March 31, 2011. 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 provided from operating activities totaled $66.4 million for the first three months of 2011 compared to $17.0 million for the corresponding period in 2010. The $49.4 million increase in cash provided from operating activities is primarily due to an $18.1 million increase in deferred income taxes primarily related to bonus depreciation, an increase in accounts payable of $16.6 million primarily due to timing of cash payments, an increase in investment tax credits of $9.7 million related to the Kemper IGCC, and an increase in cash of $18.8 million related to the Kemper IGCC generation construction screening costs incurred during the first quarter 2010. The Mississippi PSC issued an order in June 2010 approving the Kemper IGCC. These increases in cash are partially offset by a decrease of $18.3 million in fossil fuel stock resulting from an increase in Mississippi Power generation and a decrease in cash payments related to fuel inventory in the first quarter 2010.

Net cash used for investing activities totaled $52.4 million for the first three months of 2011 compared to $24.9 million for the corresponding period in 2010. The $27.4 million increase in net cash used for investing activities is primarily due to an increase in property additions of $129.9 million primarily related to the Kemper IGCC, partially offset by a $50.0 million decrease in restricted cash, a construction payables increase of $30.5 million, and the receipt of $16.9 million capital grant proceeds related to CCPI2.

Net cash used for financing activities totaled $99.4 million for the first three months of 2011, compared to net cash provided from financing activities of $17.1 million for the corresponding period in 2010. The $82.3 million increase in net cash used for financing activities was primarily due to the redemption of $50.0 million in revenue bonds and an $80.0 million maturity of long-term debt, partially offset by a $49.9 million increase in capital contributions from Southern Company.

Significant balance sheet changes for the first three months of 2011 include a decrease in cash and cash equivalents of $85.4 million primarily due to an $80.0 million long-term debt maturity and increased capital spending. Restricted cash and cash equivalents decreased $50.0 million due to the redemption of revenue bonds in February 2011. Total property, plant, and equipment increased $123.5 million primarily due to the increase in construction work in progress (CWIP) related to the Kemper IGCC. Other deferred charges and assets decreased $12.9 million primarily due to the reclassification of the Plant Daniel scrubber project and materials and supplies to CWIP. Securities due within one year decreased $130.0 million primarily due to a long-term bank loan of $80.0 million that matured in March 2011 and the redemption of revenue bonds of $50.0 million in February 2011. Other accounts payable increased $57.6 million primarily due to increases in construction projects. Other accrued taxes decreased $35.6 million primarily due to property tax payments of $44.1 million in the first quarter 2011. Paid-in capital increased $51.6 million primarily due to the $50.0 million capital contribution from Southern Company.

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, lease obligations, purchase commitments, derivative obligations, preferred stock dividends, and trust funding requirements. Approximately $126.5 million will be required through March 31, 2012 for maturities of long-term debt.

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The construction program of Mississippi Power is currently estimated to include a base level investment of $818 million, $1.0 billion, and $878 million for 2011, 2012, and 2013, respectively. Included in these estimated amounts are expenditures related to the Kemper IGCC of $685 million, $813 million, and $616 million in 2011, 2012, and 2013, respectively. Also included in these estimated amounts are environmental expenditures to comply with existing statutes and regulations of $20 million, $93 million, and $127 million for 2011, 2012, and 2013, respectively. In addition, Mississippi Power currently estimates that potential incremental investments to comply with anticipated new environmental regulations are $0 for 2011, up to $18 million for 2012, and up to $55 million for 2013. If the EPA’s proposed Utility MACT rule is finalized as proposed, Mississippi Power estimates that the potential incremental investments in 2012 and 2013 for new environmental regulations will be closer to the upper end of the estimates set forth above. 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, including unit retirement and replacement decisions, to meet new regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Except as described below with respect to potential DOE loan guarantees, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those utilized in the past. Mississippi Power has primarily utilized funds from operating cash flows, short-term borrowings, external security offerings, and capital contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. In March 2011, Mississippi Power received a $50 million capital contribution from Southern Company. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Mississippi Power in Item 7 of the Form 10-K for additional information.

Mississippi Power has applied to the DOE for federal loan guarantees to finance a portion of the eligible construction costs of the Kemper IGCC. Mississippi Power is in advanced due diligence with the DOE. There can be no assurance that the DOE will issue federal loan guarantees to Mississippi Power. In addition, Mississippi Power has been awarded DOE CCPI2 grant funds of $245 million to be used for the construction of the Kemper IGCC and $25 million to be used for the initial operation of the Kemper IGCC. As of March 31, 2011, Mississippi Power had received $40.0 million and requested an additional $20.1 million associated with this grant.

Mississippi Power’s current liabilities sometimes exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Mississippi Power had at March 31, 2011 approximately $75.4 million of cash and cash equivalents and $186 million of unused committed credit arrangements with banks. Of the unused credit arrangements, $161 million expire in 2011 and $25 million expire in 2012. Of these credit arrangements, $41 million contain provisions allowing for two-year term loans executable at expiration and $90 million contain provisions allowing for one-year term loans executable at expiration. Mississippi Power expects to renew its credit arrangements, as needed, prior to expiration. The credit arrangements provide liquidity support to Mississippi Power’s commercial paper program and $40 million are dedicated to funding purchase obligations related to variable rate pollution control revenue bonds. See Note 6 to the financial statements of Mississippi Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under “Bank Credit Arrangements” herein for additional information. Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and other Southern Company subsidiaries. During the three months ended March 31, 2011,

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

Mississippi Power had no 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 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 is required 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 below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel purchases, fuel transportation and storage, emissions allowances, and energy price risk management. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $335 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Mississippi Power’s ability to access capital markets, particularly the short-term debt market.

Market Price Risk

Mississippi Power’s market risk exposure relative to interest rate changes for the first quarter 2011 has not changed materially compared with the December 31, 2010 reporting period. Since a significant portion of outstanding indebtedness is at fixed rates, Mississippi Power is not aware of any facts or circumstances that would significantly affect exposures on existing indebtedness in the near term. However, the impact on future financing costs cannot now be determined.

Due to cost-based rate regulation and other various cost recovery mechanisms, Mississippi Power continues to have limited exposure to market volatility in interest rates, foreign currency, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. As such, Mississippi Power had no material change in market risk exposure for the first quarter 2011 when compared with the December 31, 2010 reporting period.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
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The changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, for the three months ended March 31, 2011 were as follows:


	First Quarter
	2011
	Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(44	)
Contracts realized or settled		7
Current period changes^(a)		—

Contracts outstanding at the end of the period, assets (liabilities), net	$	(37	)


(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 ended March 31, 2011 was an increase of $7 million, substantially all of which is due to natural gas positions. The change is attributable to both the volume of mmBtu and the price of natural gas. At March 31, 2011, Mississippi Power had a net hedge volume of 24.3 million mmBtu with a weighted average contract cost approximately $1.79 per mmBtu above market prices, compared to 24.0 million mmBtu at December 31, 2010 with a weighted average contract cost approximately $1.92 per mmBtu above market prices. The majority of the natural gas hedges are recovered through the ECM.

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

Unrealized pre-tax gains and losses recognized in income for the three months ended March 31, 2011 and 2010 for energy-related derivative contracts that are not hedges were not material.

Mississippi Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:


	March 31, 2011
	Fair Value Measurements
	Total			Maturity
	Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	—		$	—		$	—		$	—
Level 2		(37	)		(24	)		(13	)		—
Level 3		—			—			—			—

Fair value of contracts outstanding at end of period	$	(37	)	$	(24	)	$	(13	)	$	—

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Mississippi Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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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 Mississippi Power in Item 7 and Note 1 under “Financial Instruments” and Note 10 to the financial statements of Mississippi Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein.

Financing Activities

On February 8, 2011, Mississippi Power redeemed a $50 million series of revenue bonds issued in December 2010.

On March 4, 2011, an $80 million long term bank note with a variable interest rate based on one-month LIBOR matured.

In addition, subsequent to March 31, 2011, Mississippi Power entered into a one-year $75 million aggregate principal amount long-term floating rate bank loan with a variable interest rate based on one-month LIBOR. The proceeds of this loan were used to repay maturing long-term and short-term indebtedness and for other general corporate purposes, including Mississippi Power’s continuous construction program.

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

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


	For the Three Months
	Ended March 31,
	2011			2010
	(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	197,166		$	153,337
Wholesale revenues, affiliates		83,274			101,757
Other revenues		1,347			1,394

Total operating revenues		281,787			256,488

Operating Expenses:
Fuel		102,715			97,514
Purchased power, non-affiliates		8,942			18,542
Purchased power, affiliates		15,099			23,411
Other operations and maintenance		42,754			39,010
Depreciation and amortization		30,167			29,109
Taxes other than income taxes		4,763			5,106

Total operating expenses		204,440			212,692

Operating Income		77,347			43,796
Other Income and (Expense):
Interest expense, net of amounts capitalized		(18,829	)		(20,054	)
Other income (expense), net		59			418

Total other income and (expense)		(18,770	)		(19,636	)

Earnings Before Income Taxes		58,577			24,160
Income taxes		20,834			9,436

Net Income	$	37,743		$	14,724

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months
	Ended March 31,
	2011		2010
	(in thousands)
Net Income	$	37,743	$	14,724
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $423 and $1,714, respectively		643		2,677
Reclassification adjustment for amounts included in net income, net of tax of $1,071 and $1,003, respectively		1,630		1,567

Total other comprehensive income (loss)		2,273		4,244

Comprehensive Income	$	40,016	$	18,968

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

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


	For the Three Months
	Ended March 31,
	2011			2010
	(in thousands)
Operating Activities:
Net income	$	37,743		$	14,724
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		33,580			32,355
Deferred income taxes		8,601			13,388
Convertible investment tax credits received		38,068			—
Deferred revenues		(21,476	)		(20,993	)
Mark-to-market adjustments		(63	)		762
Other, net		1,752			930
Changes in certain current assets and liabilities —
-Receivables		20,759			16,566
-Fossil fuel stock		625			3,815
-Materials and supplies		253			4,721
-Prepaid income taxes		15,744			(9,248	)
-Other current assets		(137	)		1,020
-Accounts payable		(21,645	)		(15,111	)
-Accrued taxes		4,888			3,433
-Accrued interest		(12,281	)		(12,028	)
-Other current liabilities		(519	)		297

Net cash provided from operating activities		105,892			34,631

Investing Activities:
Property additions		(113,518	)		(68,179	)
Change in construction payables		43,259			15,489
Payments pursuant to long-term service agreements		(11,320	)		(8,145	)
Other investing activities		(3,165	)		(245	)

Net cash used for investing activities		(84,744	)		(61,080	)

Financing Activities:
Increase (decrease) in notes payable, net		(20,360	)		48,006
Proceeds — Capital contributions		17,179			1,632
Repayments — Other long-term debt		(3,066	)		—
Payment of common stock dividends		(22,800	)		(26,775	)
Other financing activities		38			95

Net cash provided from (used for) financing activities		(29,009	)		22,958

Net Change in Cash and Cash Equivalents		(7,861	)		(3,491	)
Cash and Cash Equivalents at Beginning of Period		14,204			7,152

Cash and Cash Equivalents at End of Period	$	6,343		$	3,661

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $4,240 and $1,926 capitalized for 2011 and 2010, respectively)	$	26,993		$	28,900
Income taxes (net of refunds)		(44,721	)		1,532
Noncash transactions — accrued property additions at end of period		78,567			30,963

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

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


	At March 31,		At December 31,
Assets	2011		2010
	(in thousands)
Current Assets:
Cash and cash equivalents	$	6,343	$	14,204
Receivables —
Customer accounts receivable		65,359		77,033
Other accounts receivable		2,388		1,979
Affiliated companies		10,473		19,673
Fossil fuel stock, at average cost		13,209		13,663
Materials and supplies, at average cost		34,356		33,934
Prepaid service agreements — current		33,272		41,627
Prepaid income taxes		10,343		53,860
Other prepaid expenses		4,297		4,161
Assets from risk management activities		2,811		2,160
Other current assets		—		19

Total current assets		182,851		262,313

Property, Plant, and Equipment:
In service		3,149,499		3,143,919
Less accumulated provision for depreciation		562,973		536,107

Plant in service, net of depreciation		2,586,526		2,607,812
Construction work in progress		538,067		427,788

Total property, plant, and equipment		3,124,593		3,035,600

Other Property and Investments:
Goodwill		1,839		1,839
Other intangible assets, net of amortization of $889 and $693 at March 31, 2011 and December 31, 2010, respectively		48,231		48,426

Total other property and investments		50,070		50,265

Deferred Charges and Other Assets:
Prepaid long-term service agreements		80,134		69,740
Other deferred charges and assets — affiliated		3,213		3,275
Other deferred charges and assets — non-affiliated		20,214		16,541

Total deferred charges and other assets		103,561		89,556

Total Assets	$	3,461,075	$	3,437,734

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

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


	At March 31,			At December 31,
Liabilities and Stockholder’s Equity	2011			2010
	(in thousands)
Current Liabilities:
Securities due within one year	$	253		$	—
Notes payable — affiliated		—			65,883
Notes payable — non-affiliated		249,427			203,904
Accounts payable —
Affiliated		46,536			69,783
Other		89,075			45,985
Accrued taxes —
Accrued income taxes		2,390			812
Other accrued taxes		6,005			2,775
Accrued interest		17,696			29,977
Liabilities from risk management activities		5,553			5,773
Other current liabilities		3,512			3,923

Total current liabilities		420,447			428,815

Long-term Debt		1,299,364			1,302,619

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		317,738			307,989
Deferred convertible investment tax credits		90,965			80,401
Deferred capacity revenues — affiliated		9,763			30,533
Other deferred credits and liabilities — affiliated		4,376			4,635
Other deferred credits and liabilities — non-affiliated		17,450			16,203

Total deferred credits and other liabilities		440,292			439,761

Total Liabilities		2,160,103			2,171,195

Redeemable Noncontrolling Interest		3,357			3,319

Common Stockholder’s Equity:
Common stock, par value $.01 per share —
Authorized - 1,000,000 shares
Outstanding - 1,000 shares		—			—
Paid-in capital		918,148			900,969
Retained earnings		391,213			376,270
Accumulated other comprehensive loss		(11,746	)		(14,019	)

Total common stockholder’s equity		1,297,615			1,263,220

Total Liabilities and Stockholder’s Equity	$	3,461,075		$	3,437,734

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

FIRST QUARTER 2011 vs. FIRST QUARTER 2010

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.

Effective March 15, 2011, Southern Company transferred its ownership in its wholly-owned subsidiary, Southern Renewable Energy, Inc. (SRE) to Southern Power. SRE was formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. As a transfer of net assets among entities under common control, the assets and liabilities of SRE were transferred at historical cost. The consolidated financial statements of Southern Power have been revised to include the financial condition and the results of operations of SRE since its inception in January 2010.

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) 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). Net income is the primary measure of Southern Power’s financial performance. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS – OVERVIEW – “Key Performance Indicators” of Southern Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$23.0		156.3

Southern Power’s net income for the first quarter 2011 was $37.7 million compared to $14.7 million for the corresponding period in 2010. The increase was primarily due to higher energy and capacity revenues under new PPAs that began in June, July, and December 2010 and January 2011. The increase was partially offset by lower energy and capacity revenues under existing PPAs and the expiration of PPAs in May and December 2010, lower revenues from energy sales that were not covered by PPAs, higher other operations and maintenance expenses, and higher income taxes.

Wholesale Revenues – Non-Affiliates


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$43.9		28.6

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

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Wholesale revenues from non-affiliates for the first quarter 2011 were $197.2 million compared to $153.3 million for the corresponding period in 2010. The increase was mainly due to $88.1 million of energy and capacity revenues under new non-affiliate PPAs that began in June, July, and December 2010 and January 2011. These increases were partially offset by $31.0 million of lower revenues from energy sales that were not covered by PPAs as a result of significantly more favorable weather in the first quarter 2010 compared to 2011, and $13.3 million of lower energy and capacity revenues under existing non-affiliate PPAs and the expiration of a non-affiliate PPA in December 2010.

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


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(18.5)		(18.2)

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 first quarter 2011 were $83.3 million compared to $101.8 million for the corresponding period in 2010. The decrease was primarily the result of $27.4 million of lower energy and capacity revenues associated with the expiration of affiliate PPAs in May 2010 and $9.2 million related to lower revenues from power sales to affiliates under the IIC. These decreases were partially offset by $18.5 million of increased energy and capacity revenues associated with new affiliate PPAs that began in June 2010.

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

Fuel and Purchased Power Expenses


First Quarter 2011 vs. First Quarter 2010
	(change in millions)			(% change)
Fuel	$	5.2			5.3
Purchased power – non-affiliates		(9.6	)		(51.8	)
Purchased power – affiliates		(8.3	)		(35.5	)

Total fuel and purchased power expenses	$	(12.7	)

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

In the first quarter 2011, total fuel and purchased power expenses were $126.8 million compared to $139.5 million for the corresponding period in 2010. Fuel and purchased power expenses decreased $42.9 million due to a 19.3% decrease in the average cost of natural gas and a 43.3% decrease in the average cost of purchased power. This decrease was partially offset by a $30.2 million increase in volume of KWHs generated and purchased.

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In the first quarter 2011, fuel expense was $102.7 million compared to $97.5 million for the corresponding period in 2010. Fuel expense increased $29.7 million due to an increase in the volume of KWHs generated. This increase was partially offset by $24.5 million associated with a 19.3% decrease in the average cost of natural gas.

In the first quarter 2011, purchased power expense was $24.0 million compared to $41.9 million for the corresponding period in 2010. Purchased power expenses decreased $18.4 million due to a 43.3% decrease in the average cost of purchased power partially offset by $0.5 million associated with an increase in the volume of KWHs purchased.

Other Operations and Maintenance Expenses


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$3.7		9.6

In the first quarter 2011, other operations and maintenance expenses were $42.7 million compared to $39.0 million for the corresponding period in 2010. This increase was primarily due to a $4.8 million increase related to more generating plant scheduled outages in the first quarter 2011 compared to the corresponding period in 2010 and an unplanned outage at a combined cycle generating plant. These increases were partially offset by a $1.1 million decrease in salaries and wages relating mainly to higher payroll taxes in the first quarter of 2010.

Interest Expense, Net of Amounts Capitalized


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$(1.2)		(6.1)

In the first quarter 2011, interest expense, net of amounts capitalized was $18.8 million compared to $20.0 million for the corresponding period in 2010. The decrease was primarily due to an increase in capitalized interest associated with the construction of the Cleveland County combustion turbine units and the Nacogdoches biomass plant. See FUTURE EARNINGS POTENTIAL – “Construction Projects” herein for additional information.

Income Taxes


First Quarter 2011 vs. First Quarter 2010
(change in millions)		(% change)
$11.4		120.8

In the first quarter 2011, income taxes were $20.8 million compared to $9.4 million for the corresponding period in 2010 primarily due to higher pre-tax earnings.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power’s future earnings potential. The level of Southern Power’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power’s competitive wholesale business. These factors include Southern Power’s ability to achieve sales growth while containing costs, regulatory matters, creditworthiness of customers, total generating capacity available in the Southeast, the successful remarketing of capacity as current contracts expire, and Southern Power’s ability to execute its acquisition strategy and to construct generating facilities. Other factors that could influence future earnings include weather, demand, generation patterns, and operational limitations. Recessionary conditions have lowered demand and have negatively impacted capacity revenues under Southern Power’s PPAs where the amounts purchased are based on demand. Southern Power is unable to predict whether demand under these PPAs will return to pre-recession

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

levels. The timing and extent of the economic recovery is uncertain and will impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Environmental Matters

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

Carbon Dioxide Litigation

Kivalina Case

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “Environmental Matters – Carbon Dioxide Litigation – Kivalina Case” in Item 8 of the Form 10-K for additional information regarding carbon dioxide litigation. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. The ultimate outcome of this matter cannot be determined at this time.

Water Quality

On April 20, 2011, the EPA proposed a rule that establishes standards for reducing impacts to fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. The rule also addresses cooling water intake structures for new units at existing facilities. The rule focuses on reducing adverse impacts to fish and other aquatic life due to impingement (when fish and other aquatic life are trapped by water flow velocity against a facility’s cooling water intake structure screens) and entrainment (when aquatic organisms are drawn through a facility’s cooling water system after entering through the cooling water intake structure). Affected cooling water intake structures would have to comply with national impingement standards (for intake velocity or alternatively numeric impingement reduction standards) and entrainment reduction requirements (determined on a case-by-case basis). The rule’s proposed impingement standards could require technological improvements to cooling water intake structures at some of Southern Power’s existing generating facilities, including facilities with closed-cycle re-circulating cooling systems (cooling towers). To address the rule’s entrainment standards, facilities with once-through cooling systems may have to install cooling towers. New units constructed at existing plants would have to meet the national impingement standards and install closed-cycle cooling or the equivalent to meet the entrainment mandate. The EPA has agreed in a settlement agreement to issue a final rule by July 27, 2012. If finalized as proposed, some of Southern Power’s facilities may be subject to varying degrees of additional capital expenditures and compliance costs. While Southern Power’s PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

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

Construction Projects

Cleveland County Units 1-4

In December 2008, Southern Power announced that it will build an electric generating plant in Cleveland County, North Carolina. The plant will consist of four combustion turbine natural gas generating units with a total generating capacity of 720 MWs. The units are expected to begin commercial operation in 2012. Costs incurred through March 31, 2011 were $239.2 million. The total estimated construction cost is expected to be between $350 million and $400 million.

Nacogdoches Biomass Plant

In October 2009, Southern Power acquired all of the outstanding membership interests of Nacogdoches Power LLC (Nacogdoches) from American Renewables LLC, the original developer of the project. Nacogdoches 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 March 31, 2011 were $296.1 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 U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern 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 such current proceedings would have a material adverse effect on Southern Power’s financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power’s financial condition remained stable at March 31, 2011. 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 $105.9 million for the first three months of 2011, compared to $34.6 million for the corresponding period in 2010. This increase was mainly due to an increase in cash received for convertible ITCs and bonus depreciation. Net cash used for investing activities totaled $84.7 million for the first three months of 2011, compared to $61.1 million for the corresponding period in 2010. This increase was primarily due to an increase in construction work in progress related to construction activities at Cleveland County and Nacogdoches. Net cash used for financing activities totaled $29.0 million for the first three months of 2011, compared to $23.0 million cash provided from financing activities for the corresponding period in 2010 primarily due to repayment of an affiliate loan related to SRE.

Significant asset changes in the balance sheet for the first quarter 2011 include an increase in construction work in progress due to Cleveland County and Nacogdoches construction activities and a decrease in prepaid income taxes mainly due to the receipt of an income tax refund from the IRS related to convertible ITCs and bonus depreciation.

Significant liability and stockholder’s equity changes in the balance sheet for the first quarter 2011 include an increase in accounts payable – other primarily related to Cleveland County and Nacogdoches construction activities, a decrease in accounts payable – affiliated primarily due to the expiration of affiliate PPAs in May 2010, a decrease in notes payable primarily due to repayment of an affiliate loan related to SRE, and a decrease in deferred capacity revenues – affiliated primarily due to seasonality.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Power in Item 7 of the Form 10-K for a description of Southern Power’s capital requirements for its construction program, scheduled maturities of long-term debt, interest, leases, derivative obligations, purchase commitments, and long-term service agreements. The construction program is subject to periodic review and revision; these amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements. Planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power’s ability to execute its growth strategy. Actual construction costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; 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.

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

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 March 31, 2011 cash and cash equivalents of approximately $6 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 March 31, 2011, Southern Power had $249 million of commercial paper borrowings outstanding with a weighted average interest rate of 0.4% per annum. During the first quarter 2011, Southern Power had an average of $231 million of commercial paper outstanding at a weighted average interest rate of 0.4% per annum and the maximum amount outstanding was $272 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and cash.

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. At March 31, 2011, 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 $367 million. At March 31, 2011, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $1.0 billion. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system 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.

Market Price Risk

Southern Power is exposed to market risks, including changes in interest rates, certain energy-related commodity prices, and, occasionally, currency exchange rates. To manage the volatility attributable to these exposures, Southern Power takes advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power’s policies in areas such as counterparty exposure and risk management practices. Southern Power’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress tests, and sensitivity analysis.

Southern Power’s market risk exposure relative to interest rate changes for the first quarter 2011 has not changed materially compared with the December 31, 2010 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

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

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 months ended March 31, 2011 were as follows:


	First Quarter
	2011
	Changes

	Fair Value

	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(3.5	)
Contracts realized or settled		0.7
Current period changes^(a)		0.5

Contracts outstanding at the end of the period, assets (liabilities), net	$	(2.3	)


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

The increase in the fair value positions of the energy-related derivative contracts for the three months ended March 31, 2011 was $1.2 million, 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:


	March 31, 2011			December 31, 2010

Power (net sold)

MWHs (in millions)		0.8			0.9
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	(3.20	)	$	(2.33	)

Natural gas (net purchase)

Commodity — million mmBtu		13.5			13.0
Commodity — Weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	0.01		$	0.11

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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	March 31, 2011			December 31, 2010

	(in millions)
Cash flow hedges	$	0.1		$	(1.0	)
Not designated		(2.4	)		(2.5	)

Total fair value	$	(2.3	)	$	(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 or fail to qualify as hedges are recognized in the statements of income as incurred.

Total net unrealized pre-tax gains (losses) recognized in the statements of income for the three months ended March 31, 2011 for energy-related derivative contracts that were not hedges were not material and will continue to be marked to market until the settlement date. For the three months ended March 31, 2010, the total net unrealized pre-tax losses recognized in the statements of income were $0.7 million.

Southern Power uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2. See Note (C) to the Condensed Financial Statements herein for further discussion on fair value measurements. The maturities of the energy-related derivative contracts and the level of the fair value hierarchy in which they fall at March 31, 2011 were as follows:


	March 31, 2011
	Fair Value Measurements

	Total			Maturity
	Fair Value			Year 1			Years 2&3		Years 4&5

	(in millions)
Level 1	$	—		$	—		$	—	$	—
Level 2		(2.3	)		(2.7	)		—		0.4
Level 3		—			—			—		—

Fair value of contracts outstanding at end of period	$	(2.3	)	$	(2.7	)	$	—	$	0.4

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in July 2010 could impact the use of over-the-counter derivatives by Southern Power. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

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

During the three months ended March 31, 2011, Southern Power paid $3.1 million on a long-term loan related to SRE. Southern Power did not issue or redeem any long-term securities during the first quarter 2011.

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(A)

INTRODUCTION

			The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2010 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 March 31, 2011 and 2010. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

			Effective March 15, 2011, Southern Company transferred its ownership in its wholly-owned subsidiary, Southern Renewable Energy, Inc. (SRE), to Southern Power. SRE was formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. As a transfer of net assets among entities under common control, the assets and liabilities of SRE were transferred at historical cost. The consolidated financial statements of Southern Power have been revised to include the financial condition and the results of operations of SRE since its inception in January 2010.

			Southern Company has made separate guarantees to two counterparties regarding performance of contractual commitments by SRE. The total original notional amount of the guarantees was $120 million, approximately $12 million of which was outstanding at March 31, 2011. Of this amount, approximately $3 million is expected to expire in August 2011, and approximately $9 million is expected to expire in 2037.

			Certain prior years’ data presented in the financial statements have been reclassified to conform to the current year presentation.

(B)

CONTINGENCIES AND REGULATORY MATTERS

			See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

			General Litigation Matters

			Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, each registrant’s business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as opacity and air and water quality standards, has increased generally throughout the U.S. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief and property damage allegedly caused by greenhouse gas and other emissions, have become more frequent. The ultimate outcome of such pending or potential litigation against each registrant and any of its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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.

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

			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.

			In September 2010, the EPA dismissed five of its eight remaining claims against Alabama Power, leaving only three claims for summary disposition or trial, including the claim relating to a facility co-owned by Mississippi Power. The parties each filed motions for summary judgment in September 2010.

			On March 14, 2011, the U.S. District Court for the Northern District of Alabama granted Alabama Power’s motion for summary judgment on all remaining claims and dismissed the case with prejudice. The EPA has the right to appeal within 60 days of the order.

			Southern Company believes that the traditional operating companies 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. The ultimate outcome of these matters cannot be determined at this time.

			*Carbon Dioxide Litigation*

			New York Case

			In July 2004, three environmental groups and attorneys general from several 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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			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 December 2010, the U.S. Supreme Court granted the defendants’ petition for writ of certiorari. On April 19, 2011, the U.S. Supreme Court heard oral argument in this case, and a decision is expected before year-end. The ultimate outcome of these matters cannot be determined at this time.

			Kivalina Case

			In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the U.S. District Court for the Northern District of California against several electric utilities (including Southern Company), several oil companies, and a coal company. The plaintiffs are the governing bodies of an Inupiat village in Alaska. The plaintiffs contend that the village is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for public and private nuisance and contend that some of the defendants have acted in concert and are therefore jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which is alleged to be $95 million to $400 million. Southern Company believes that these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2009, the U.S. District Court for the Northern District of California granted the defendants’ motions to dismiss the case based on lack of jurisdiction and ruled the claims were barred by the political question doctrine and by the plaintiffs’ failure to establish the standard for determining that the defendants’ conduct caused the injury alleged. In November 2009, the plaintiffs filed an appeal with the U.S. Court of Appeals for the Ninth Circuit challenging the district court’s order dismissing the case. On January 24, 2011, the defendants filed a motion with the U.S. Court of Appeals for the Ninth Circuit to defer scheduling the case pending the decision of the U.S. Supreme Court in the New York case discussed above. On February 23, 2011, the U.S. Court of Appeals for the Ninth Circuit issued an order staying the case until June 15, 2011. 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 March 31, 2011 was $13.2 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 or Southern Company’s financial statements.

			In September 2008, the EPA advised Georgia Power that it has been designated as a PRP at the Ward Transformer Superfund site located in Raleigh, North Carolina. Numerous other entities have also received notices regarding this site from the EPA. 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

122

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			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 Southern Company’s and Georgia Power’s financial statements.

			Gulf Power’s environmental remediation liability includes estimated costs of environmental remediation projects of approximately $63.5 million as of March 31, 2011. 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 during the first quarters of 2010 and 2011 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 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.

			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 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 Inc. a subsidiary of telecommunications company ITC DeltaCom, Inc. that uses certain of the defendants’ 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. In August 2010, the defendants filed a motion to dismiss the suit for lack of prosecution. The court denied the defendants’ motion to dismiss the claim. On March 25, 2011, the plaintiffs filed an amended complaint asserting claims for breach of contract for failing to make the defendants’ facilities fully available to the plaintiffs and for failing to

123

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			indemnify the plaintiffs in defending the underlying landowner litigation. 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. In May 2010, the U.S. Court of Appeals for the Federal Circuit lifted the stay.

			On March 11, 2011, the U.S. Court of Appeals for the Federal Circuit issued an order in which it affirmed the damage award to Alabama Power, but remanded the Georgia Power portion of the proceeding back to the U.S. Court of Federal Claims for reconsideration of the damages amount in light of the spent nuclear fuel acceptance rates adopted in a separate proceeding by the U.S. Court of Appeals for the Federal Circuit.

			In 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. 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 March 31, 2011 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.

			Sufficient pool storage capacity for spent fuel is available at Plant Vogtle to maintain full-core discharge capability for both units into 2014. Construction of an on-site dry storage facility at Plant Vogtle is expected to begin in sufficient time to maintain pool full-core discharge capability. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of each plant.

			Income Tax Matters

			*Georgia State Income Tax Credits*

			Georgia Power’s 2005 through 2009 income tax filings for the State of Georgia include state income tax credits for increased activity through Georgia ports. Georgia Power also filed similar claims for the years 2002 through 2004. The Georgia Department of Revenue (DOR) 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. In March 2010, the Superior Court of Fulton County ruled in favor of Georgia Power’s motion for summary judgment. The Georgia DOR has appealed to the Georgia Court of Appeals and a decision is expected later this year. Any decision may be subject to further appeal to the Georgia Supreme Court. An unrecognized tax benefit has been recorded related to these credits. If Georgia Power prevails, no material impact on Southern Company’s or Georgia Power’s net income is expected as a significant portion of any tax benefit is expected to be returned to retail customers in accordance with the 2010 ARP. If Georgia Power is not successful, payment of the related state tax for previously utilized credits would have a negative effect on Southern Company’s and Georgia Power’s cash flow. See Note 5 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K under “Unrecognized Tax Benefits” and Note (G) herein for additional information. The ultimate outcome of this matter cannot now be determined.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			State PSC Matters

			*Alabama Power*

			Natural Disaster Reserve

			See Note 3 to the financial statements of Southern Company under “PSC Matters – Alabama Power – Natural Disaster Reserve” and Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters – Natural Disaster Reserve” in Item 8 of the Form 10-K for additional information. At March 31, 2011, the NDR had an accumulated balance of $127 million, which is included in the Condensed Balance Sheets herein under other regulatory liabilities, deferred. The accruals are reflected as operations and maintenance expenses in the Condensed Statements of Income herein.

			On April 27, 2011, devastating storms swept through the central part of Alabama causing significant damage in parts of Alabama Power’s service territory. Over 400,000 of Alabama Power’s 1.4 million customers were without electrical service immediately after the storms, resulting from significant damage to Alabama Power’s transmission and distribution facilities. The preliminary estimated cost associated with repairing the damage to facilities and restoring electrical service to customers is between $40 million and $55 million for operations and maintenance expenses and between $180 million and $225 million for capital expenditures. Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to Alabama Power’s transmission and distribution facilities.

			*Georgia Power*

			Fuel Cost Recovery

			See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery” and “Retail Regulatory Matters – Fuel Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information. On March 1, 2011, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 0.61%. The decrease would reduce Georgia Power’s annual billings by approximately $43 million. The decrease in fuel costs is driven primarily by lower natural gas prices than those included in current rates as a result of increases in natural gas supplies from the production of shale gas and lower industrial demand. If approved, the new rates will go into effect June 1, 2011. The ultimate outcome of this matter cannot be determined at this time.

			Nuclear Construction

			See Note 3 to the financial statements of Southern Company and Georgia Power under “Retail Regulatory Matters – Georgia Power – Nuclear Construction” and “Construction – Nuclear,” respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power’s construction of Plant Vogtle Units 3 and 4.

			In December 2010, Westinghouse submitted an AP1000 Design Certification Amendment (DCA) to the NRC. On February 10, 2011, the NRC announced that it was seeking public comment on a proposed rule to approve the DCA and amend the certified AP1000 reactor design for use in the U.S. The Advisory Committee on Reactor Safeguards also issued a letter on January 24, 2011 endorsing the issuance of the Construction and Operating License (COL) for Plant Vogtle Units 3 and 4. In addition, on March 25, 2011, the NRC submitted to the EPA the final environmental impact statement for Plant Vogtle Units 3 and 4. Georgia Power currently expects to receive the COL for Plant Vogtle Units 3 and 4 from the NRC in late 2011 based on the NRC’s February 16, 2011 release of its COL schedule framework.

			On February 21, 2011, the Georgia PSC voted to approve Georgia Power’s third semi-annual construction monitoring report including total costs of $1.048 billion for Plant Vogtle Units 3 and 4 incurred through June 30, 2010. In connection with its certification of Plant Vogtle Units 3 and 4, the Georgia PSC ordered Georgia Power and the PSC Staff to work together to develop a risk sharing or incentive mechanism that would provide some level of protection to ratepayers in the event of significant cost overruns, but also not penalize Georgia Power’s earnings if and when overruns are due to mandates from governing agencies. Such discussions have continued through the third semi-annual construction monitoring proceedings; however, the Georgia PSC has deferred a decision with respect to any related risk-sharing or incentive mechanism. A Georgia PSC hearing on this matter is scheduled on July 6, 2011 and a decision is expected on August 2, 2011. Georgia Power will continue to file construction monitoring reports by February 28 and August 31 of each year during the construction period.

			In December 2010, the Georgia PSC approved Georgia Power’s NCCR tariff, which became effective January 1, 2011. The NCCR tariff was established to recover financing costs for nuclear construction projects by including the related construction work in progress accounts in rate base during the construction period in accordance with the Georgia Nuclear Energy Financing Act. With respect to Plant Vogtle Units 3 and 4, this legislation allows Georgia Power to recover

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			projected financing costs of approximately $1.7 billion during the construction period beginning in 2011, which reduces the projected in-service cost to approximately $4.4 billion. Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs capitalized in 2009 and 2010 over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At March 31, 2011, approximately $87 million of these 2009 and 2010 costs are included in construction work in progress.

			Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), and a consortium consisting of Westinghouse and Stone & Webster, Inc. have established both informal and formal dispute resolution procedures in order to resolve issues that commonly arise during the course of constructing a project of this magnitude. Southern Nuclear, on behalf of the Owners, has initiated both formal and informal claims through these procedures, including ongoing claims, and anticipates that further issues are likely to arise in the future. The Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

			There are other pending technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, including petitions filed at the NRC in response to the events in Japan. 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 May 2010, the Georgia PSC approved Georgia Power’s request to extend the construction schedule for Plant McDonough Units 4, 5, and 6 as a result of the short-term reduction in forecasted demand, as well as the requested increase in the certified amount. As a result, the units are expected to be placed into service in January 2012, May 2012, and January 2013, respectively. The Georgia PSC has approved Georgia Power’s quarterly construction monitoring reports, including actual project expenditures incurred, through June 30, 2010. Georgia Power will continue to file quarterly construction monitoring reports throughout the construction period

			Plant Branch Units 1 and 2 De-certification

			On March 22, 2011, the board of the Georgia Department of Natural Resources began consideration of modifications to the Georgia Multi-Pollutant Rule. The proposed modifications would change the compliance dates for certain of Georgia Power’s coal-fired generating units as follows:


		Scherer 3		July 1, 2011
		Branch 1		December 31, 2013
		Branch 2		October 1, 2013
		Branch 3		October 1, 2015
		Branch 4		December 31, 2015

The Multi-Pollutant Rule is designed to reduce emissions of mercury, sulfur dioxide, and nitrogen oxides statewide. The Utility Maximum Achievable Control Technology rule will also regulate emissions of mercury, in addition to other air pollutants. All required controls, including SCR, scrubber, and baghouse, are expected to be operational at Plant Scherer Unit 3 by the required compliance date. As a result of these proposed rules, Georgia Power’s management expects to request that the Georgia PSC approve de-certification of its Plant Branch Units 1 and 2, totaling 569 MWs of capacity, as of the effective dates for controls under the Multi-Pollutant Rule as revised. Georgia Power continues to analyze the potential costs and benefits of installing the required controls on its remaining coal-fired units, including Plant Branch Units 3 and 4, in light of the proposed air quality rules, as well as additional potential federal regulations related to water quality and coal combustion byproducts. Georgia Power may determine that retiring and replacing certain of its existing units with new generating resources or purchased power is more economically efficient than installing the required controls.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			See Note 3 under “Retail Regulatory Matters – Rate Plans” to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for information regarding the 2010 ARP. Under the terms of the 2010 ARP, any costs associated with changes to Georgia Power’s approved environmental operating or capital budgets resulting from new or revised environmental regulations through 2013 that are approved by the Georgia PSC in connection with an updated integrated resource plan will be deferred as a regulatory asset to be recovered over a time period deemed appropriate by the Georgia PSC. Georgia Power currently expects to file an update to its integrated resource plan in late summer 2011, which would include the Plant Branch Units 1 and 2 de-certification request. In connection with this filing, Georgia Power expects to request the Georgia PSC to approve the deferral and related amortization of the retail portion of the related costs associated with the de-certification request. Georgia Power moved the retail portion of the net carrying value of Plant Branch Units 1 and 2 from plant in service, net of depreciation, to other utility plant, net of depreciation. Consistent with current ratemaking treatment, Georgia Power will continue to depreciate these units using the composite straight-line rates approved by the Georgia PSC, and upon actual retirement, expects to include the units’ remaining net carrying value in rate base. However, the recovery periods for these units may change in connection with Georgia Power’s updated integrated resource plan. As a result of this regulatory treatment, the de-certification of Plant Branch Units 1 and 2 is not expected to have a significant impact on Southern Company’s or Georgia Power’s financial statements.

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

			*Gulf Power*

			Energy Conservation Cost Recovery

			Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the Energy Conservation Cost Recovery clause.

			The most recent goal setting process established new DSM goals for the period 2010-2019. The new goals are significantly larger than the goals established in the previous five-year cycle due to a change in the cost-effectiveness test on which the Florida PSC relies to set the goals. Throughout 2010, Gulf Power engaged in a process at the Florida PSC to develop plans and programs to meet the new DSM goals. The DSM program standards were approved in April 2011, which allow Gulf Power to implement its DSM programs designed to meet the new goals. Higher cost recovery rates and achievement of the new DSM goals may result in reduced sales of electricity which could negatively impact results of operations, cash flows, and financial condition if base rates cannot be adjusted on a timely basis.

			*Mississippi Power*

			Certificated New Plant

			On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing Certificated New Plant-A (CNP-A), a new proposed cost recovery mechanism designed specifically to recover financing costs during the construction phase of the Kemper IGCC. Annual CNP-A rate filings would be made with the first filing occurring in November 2011. If approved by the Mississippi PSC, recovery through CNP-A will remain in place thereafter until the end of the calendar year that the Kemper IGCC is placed into commercial service, which is projected to be 2014. Certificated New Plant-B, which will be filed at a later date, would propose to govern rates effective from the first calendar year after the Kemper IGCC is placed into commercial service through the first seven full calendar years of its operation. The ultimate outcome of this matter cannot be determined at this time.

			Integrated Coal Gasification Combined Cycle

			See Note 3 to the financial statements of Southern Company under “Retail Regulatory Matters – Mississippi Power Integrated Coal Gasification Combined Cycle” 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.

			In June 2010, the Mississippi Chapter of the Sierra Club (Sierra Club) filed an appeal of the Mississippi PSC’s June 3, 2010 decision to grant the Certificate of Public Convenience and Necessity for the Kemper IGCC with the Chancery Court of Harrison County, Mississippi (Chancery Court). Subsequently, in July 2010, the Sierra Club also filed an appeal directly with the Mississippi Supreme Court. In October 2010, the Mississippi Supreme Court dismissed the Sierra Club’s direct appeal. On February 28, 2011, the Chancery Court issued a judgment affirming the Mississippi PSC’s order authorizing the construction of the Kemper IGCC. On March 1, 2011, the Sierra Club appealed the Chancery Court’s decision to the Mississippi Supreme Court.

			In May 2009, Mississippi Power received notification from the IRS formally certifying the IRS allocated Internal Revenue Code Section 48A tax credits (Phase I) of $133 million to Mississippi Power. On April 19, 2011, Mississippi Power received notification from the IRS formally certifying that the IRS allocated $279 million of Internal Revenue Code Section 48A tax credits (Phase II) to Mississippi Power. The utilization of Phase I and Phase II credits is dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In order to remain eligible for the Phase II tax credits, Mississippi Power plans to capture and sequester (via enhanced oil recovery) at least 65% of the carbon dioxide (CO₂) produced by the plant

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			during operations in accordance with the recapture rules for Section 48A investment tax credits. Through March 31, 2011, Mississippi Power received and accrued tax benefits totaling $31.9 million for these tax credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC.

			In February 2008, Mississippi Power requested that the DOE transfer the remaining funds previously granted under the Clean Coal Power Initiative Round 2 (CCPI2) from a cancelled IGCC project of one of Southern Company’s subsidiaries that would have been located in Orlando, Florida. In December 2008, an agreement was reached to assign the remaining funds ($270 million) to the Kemper IGCC. Mississippi Power will receive grant funds of $245 million during the construction of the plant and $25 million during the initial operation of the plant. Through March 31, 2011, Mississippi Power has received $40 million and requested an additional $20.1 million associated with this grant.

			On March 10, 2011, the Sierra Club filed a lawsuit in the U.S. District Court for the District of Columbia against the DOE regarding the National Environmental Policy Act review process asking for a stay on the issuance of CCPI2 funds and a stay to any related construction activities. On May 5, 2011, Mississippi Power filed a motion to intervene in this lawsuit.

			In March 2010, the Mississippi Department of Environmental Quality (MDEQ) issued the Prevention of Significant Deterioration (PSD) air permit modification for the plant, which modifies the original PSD air permit issued in October 2008. The Sierra Club requested a formal evidentiary hearing regarding the issuance of the modified permit. On April 4, 2011, the MDEQ Permit Board held an evidentiary hearing wherein the permit board unanimously affirmed the PSD air permit.

			On March 4, 2011, Mississippi Power and Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., entered into a contract in which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC.

			On April 27, 2011, Mississippi Power submitted to the Mississippi PSC a proposed rate schedule detailing CNP-A, a new proposed cost recovery mechanism designed specifically to recover financing cost during the construction phase of the Kemper IGCC. See “Certificated New Plant” herein for additional information.

			As of March 31, 2011, Mississippi Power had spent a total of $352.8 million on the Kemper IGCC, including regulatory filing costs. Of this total, $277 million was included in CWIP (net of $60.1 million of CCPI2 grant funds), $13.2 million was recorded in other regulatory assets, $1.5 million was recorded in other deferred charges and assets, and $1.0 million was previously expensed.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(C)

FAIR VALUE MEASUREMENTS

As of March 31, 2011, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:


	Fair Value Measurements Using
	Quoted Prices
	in Active		Significant
	Markets for		Other		Significant
	Identical		Observable		Unobservable
	Assets		Inputs		Inputs
As of March 31, 2011:	(Level 1)		(Level 2)		(Level 3)		Total

	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	14
Interest rate derivatives		—		9		—		9
Foreign currency derivatives		—		6		—		6
Nuclear decommissioning trusts^(a)		631		738		—		1,369
Cash equivalents and restricted cash		262		—		—		262
Other investments		12		49		12		73

Total	$	905	$	816	$	12	$	1,733

Liabilities:
Energy-related derivatives	$	—	$	172	$	—	$	172
Interest rate derivatives		—		1		—		1

Total	$	—	$	173	$	—	$	173


Alabama Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts:^(b)
Domestic equity		328		61		—		389
Foreign equity		7		7		—		14
U.S. Treasury and government agency securities		19		8		—		27
Corporate bonds		—		83		—		83
Mortgage and asset backed securities		—		29		—		29
Other		28		8		—		36
Cash equivalents and restricted cash		71		—		—		71

Total	$	453	$	198	$	—	$	651

Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	29

129

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 March 31, 2011:	(Level 1)		(Level 2)		(Level 3)		Total

	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Nuclear decommissioning trusts:^(c)
Domestic equity		249		1		—		250
U.S. Treasury and government agency securities		—		87		—		87
Municipal bonds		—		60		—		60
Corporate bonds		—		211		—		211
Mortgage and asset backed securities		—		115		—		115
Other		—		68		—		68

Total	$	249	$	544	$	—	$	793

Liabilities:
Energy-related derivatives	$	—	$	86	$	—	$	86


Gulf Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Cash equivalents		14		—		—		14

Total	$	14	$	3	$	—	$	17

Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	11


Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Foreign currency derivatives		—		6		—		6
Cash equivalents		68		—		—		68

Total	$	68	$	9	$	—	$	77

Liabilities:
Energy-related derivatives	$	—	$	40	$	—	$	40


Southern Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	4

Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	6


(a)		For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.
(b)		Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
(c)		Includes the investment securities pledged to creditors and cash collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the securities lending program. As of March 31, 2011, approximately $99 million of the fair market value of Georgia Power’s nuclear decommissioning trust funds’ securities were on loan and pledged to creditors under the funds’ managers’ securities lending program.

130

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			*Valuation Methodologies*

			The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and LIBOR interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.

			“Other investments” include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.

			For fair value measurements of investments within the nuclear decommissioning trusts and rabbi trust funds, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts and rabbi trust funds with each security discriminately assigned a primary pricing source, based on similar characteristics.

			A market price secured from the primary source vendor is then used in the valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts’ judgment are also obtained when available.

131

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

As of March 31, 2011, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

Fair

Unfunded

Redemption

As of March 31, 2011:

Value

Commitments

Frequency

Notice Period

(in millions)

Southern Company

Nuclear decommissioning trusts:

Corporate bonds – commingled funds

100

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

262

None

Daily

Not applicable

Other:

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

100

None

Daily

1 to 3 days

Other – commingled funds

None

Daily

Not applicable

Gulf Power

Cash equivalents:

Money market funds

None

Daily

Not applicable

Mississippi Power

Cash equivalents:

Money market funds

None

Daily

Not applicable

132

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC’s regulations. The commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations having a maximum five-year final maturity with put features or floating rates with a reset 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. The corporate bonds – commingled funds represent the investment of cash collateral received under the Funds’ managers’ securities lending program that can only be sold upon the return of the loaned securities. See Note 1 to the financial statements of Southern Company and Georgia Power under “Nuclear Decommissioning” in Item 8 of the Form 10-K for additional information.

			Alabama Power’s nuclear decommissioning trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.

			Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months ended March 31, 2011, the increase in fair value of the funds, which includes reinvested interest and dividends, is recorded in the regulatory liability and was $27.3 million for Alabama Power, $14.6 million for Georgia Power, and $41.9 million 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 investment in the money market funds.

			Changes in the fair value measurement of the Level 3 items using significant unobservable inputs for Southern Company at March 31, 2011 were as follows:


	Level 3
	Other

	(in millions)
Beginning balance at December 31, 2010	$	19
Purchases		1
Total gains (losses) — realized/unrealized:
Included in earnings		(5	)
Included in OCI		(3	)

Ending balance at March 31, 2011	$	12

133

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At March 31, 2011, 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	$	19,418	$	20,100
Alabama Power	$	6,235	$	6,538
Georgia Power	$	8,437	$	8,641
Gulf Power	$	1,224	$	1,259
Mississippi Power	$	586	$	608
Southern Power	$	1,299	$	1,382

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

(D)

STOCKHOLDERS’ EQUITY

			Earnings per Share

			For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for further information on the stock option and performance share plans. The effects of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:


	Three Months		Three Months
	Ended		Ended
	March 31, 2011		March 31, 2010

	(in thousands)
As reported shares		847,510		822,526
Effect of options		6,429		2,261

Diluted shares		853,939		824,787

Stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive were 7 million and 25 million for the three months ended March 31, 2011 and March 31, 2010, respectively. Assuming an average stock price of $38.01 (the highest exercise price of the anti-dilutive options outstanding), the effect of options would have been immaterial for the three months ended March 31, 2011 and would have increased by 2 million shares for the three months ended March 31, 2010.

134

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			Changes in Stockholders’ Equity

			The following table presents year-to-date changes in stockholders’ equity of Southern Company:


									Preferred and
	Number of					Common			Preference		Total
	Common Shares					Stockholders’			Stock of		Stockholders’
	Issued		Treasury			Equity			Subsidiaries		Equity

	(in thousands)					(in millions)
Balance at December 31, 2010		843,814		(474	)	$	16,202		$	707	$	16,909
Net income after dividends on preferred and preference stock		—		—			422			—		422
Other comprehensive income (loss)		—		—			4			—		4
Stock issued		5,784		—			222			—		222
Cash dividends on common stock		—		—			(385	)		—		(385	)
Other		—		(1	)		—			—		—

Balance at March 31, 2011		849,598		(475	)	$	16,465		$	707	$	17,172


Balance at December 31, 2009		820,152		(505	)	$	14,878		$	707	$	15,585
Net income after dividends on preferred and preference stock		—		—			495			—		495
Other comprehensive income (loss)		—		—			9			—		9
Stock issued		4,872		—			171			—		171
Cash dividends on common stock		—		—			(359	)		—		(359	)
Other		—		17			1			—		1

Balance at March 31, 2010		825,024		(488	)	$	15,195		$	707	$	15,902

(E)

FINANCING

			Bank Credit Arrangements

			Bank credit arrangements provide liquidity support to the registrants’ commercial paper borrowings and the traditional operating companies’ variable rate pollution control revenue bonds. See Note 6 to the financial statements of each registrant under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information.

			The following table outlines the credit arrangements by company as of March 31, 2011:


					Executable										Expires Within One
					Term-Loans				Expires						Year^(a)
																	No
					One		Two								Term		Term
Company	Total		Unused		Year		Years		2011		2012		2013		Out		Out

									(in millions)
Southern Company	$	950	$	950	$	—	$	—	$	—	$	950	$	—	$	—	$	—
Alabama Power		1,271		1,271		372		—		506		765		—		372		134
Georgia Power		1,715		1,703		220		40		595		1,120		—		260		335
Gulf Power		240		240		210		—		240		—		—		210		30
Mississippi Power		186		186		90		41		161		25		—		131		55
Southern Power		400		400		—		—		—		400		—		—		—
Other		60		60		60		—		60		—		—		60		—

Total	$	4,822	$	4,810	$	952	$	81	$	1,562	$	3,260	$	—	$	1,033	$	554


(a)		Reflects facilities expiring on or before March 31, 2012.

135

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(F)

RETIREMENT BENEFITS

			Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan are expected for the year ending December 31, 2011. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

			See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

			Components of the net periodic benefit costs for the three months ended March 31, 2011 and 2010 were as follows:


	Southern			Alabama			Georgia			Gulf			Mississippi
PENSION PLANS	Company			Power			Power			Power			Power

	(in millions)
Three Months Ended March 31, 2011
Service cost	$	46		$	11		$	14		$	2		$	2
Interest cost		98			24			36			4			4
Expected return on plan assets		(152	)		(43	)		(59	)		(7	)		(6	)
Net amortization		13			3			5			1			1

Net cost (income)	$	5		$	(5	)	$	(4	)	$	—		$	1


Three Months Ended March 31, 2010
Service cost	$	43		$	10		$	14		$	2		$	2
Interest cost		98			24			36			4			4
Expected return on plan assets		(138	)		(42	)		(55	)		(6	)		(5	)
Net amortization		11			3			4			1			1

Net cost (income)	$	14		$	(5	)	$	(1	)	$	1		$	2


	Southern			Alabama			Georgia			Gulf		Mississippi
POSTRETIREMENT BENEFITS	Company			Power			Power			Power		Power

	(in millions)
Three Months Ended March 31, 2011
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost		23			6			10			1		1
Expected return on plan assets		(16	)		(6	)		(8	)		—		—
Net amortization		5			2			3			—		—

Net cost (income)	$	17		$	3		$	7		$	1	$	1


Three Months Ended March 31, 2010
Service cost	$	6		$	2		$	2		$	—	$	—
Interest cost		25			6			11			1		1
Expected return on plan assets		(16	)		(6	)		(8	)		—		—
Net amortization		5			2			3			—		—

Net cost (income)	$	20		$	4		$	8		$	1	$	1

136

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(G)

EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

			Effective Tax Rate

			Southern Company’s effective tax rate was 34.6% for the three months ended March 31, 2011, as compared to 31.6% for the corresponding period in 2010. Southern Company’s effective tax rate is lower than the statutory rate primarily due to its employee stock 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 increased primarily due to no production activities deduction and no Georgia state income tax credits for activity through Georgia ports available to Southern Company for the three months ended March 31, 2011, as compared to the production activities deduction and additional Georgia state income tax credits recognized as of March 31, 2010. Additionally, Georgia Power’s effective tax rate increased for the three months ended March 31, 2011 as compared to March 31, 2010 from 27.8% to 34.6% primarily due to the impact of Georgia state income tax credits discussed above and a decrease in AFUDC equity, which is not taxable, in the first quarter 2011.

			Unrecognized Tax Benefits

			Changes during 2011 for unrecognized tax benefits were as follows:


	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power

					(in millions)
Unrecognized tax benefits as of December 31, 2010	$	296	$	43	$	237	$	4	$	4	$	2
Tax positions from current periods		8		2		5		—		1		—
Tax positions from prior periods		—		—		—		—		—		—
Reductions due to expired		—		—		—		—		—		—
statute of limitations

Balance as of March 31, 2011	$	304	$	45	$	242	$	4	$	5	$	2

			The tax positions from current periods relate primarily to the tax accounting method change for repairs and other miscellaneous uncertain tax positions.

			The impact on the effective tax rate, if recognized, is as follows:


							As of
							December 31,
	As of March 31, 2011						2010
	Georgia		Other		Southern		Southern
	Power		Registrants		Company		Company

			(in millions)
Tax positions impacting the effective tax rate	$	205	$	11	$	221	$	217
Tax positions not impacting the effective tax rate		37		45		83		79

Balance of unrecognized tax benefits	$	242	$	56	$	304	$	296

The tax positions impacting the effective tax rate primarily relate to Georgia state tax credit litigation at Georgia Power and the production activities deduction tax position. However, if Georgia Power is successful in its claim against the Georgia DOR, a significant portion of the tax benefit is expected to be deferred and returned to retail customers and therefore no material impact to net income is expected. The tax positions not impacting the effective tax rate relate to the timing difference associated with the tax accounting method change for repairs. These amounts are presented on a gross basis without considering the related federal or state income tax impact. See Note (B) under “Income Tax Matters – Georgia State Income Tax Credits” herein for additional information.

137

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

Accrued interest for unrecognized tax benefits was as follows:


	Georgia		Other		Southern
	Power		Registrants		Company

	( in millions)
Interest accrued as of December 31, 2010	$	27	$	2	$	29
Interest reclassified due to settlements		—		—		—
Interest accrued during the period		2		1		3

Balance as of March 31, 2011	$	29	$	3	$	32

			All of the registrants classify interest on tax uncertainties as interest expense. The net amount of interest accrued during 2011 was primarily associated with the Georgia state tax credit litigation.

			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 credit 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.

			Tax Method of Accounting for Repairs

			Southern Company submitted a change in the tax accounting method for repair costs associated with its subsidiaries’ generation, transmission, and distribution systems with the filing of the 2009 federal income tax return in September 2010. The new tax method resulted in net positive cash flow in 2010 of approximately $141 million for Alabama Power, $133 million for Georgia Power, $8 million for Gulf Power, $5 million for Mississippi Power, $6 million for Southern Power, and $297 million for Southern Company on a consolidated basis. Although IRS approval of this change is considered automatic, the amount claimed is subject to review because the IRS will be issuing final guidance on this matter. Currently, the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities. Due to uncertainty concerning the ultimate resolution of this matter, an unrecognized tax benefit has been recorded for the change in the tax accounting method for repair costs. The ultimate outcome of this matter cannot be determined at this time.

(H)

DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company’s policies in areas such as counterparty exposure and risk management practices. Each company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities.

			Energy-Related Derivatives

			The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts which is expected to continue to mitigate price volatility. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift

138

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			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 electric utilities 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 electric utilities may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

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

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

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

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

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

			At March 31, 2011, 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
	MWHs		Date		Date		mmBtu		Date		Date

	(in millions)						(in millions)
Southern Company		0.8		2011		2011		154		2015		2015
Alabama Power		—		2011		2011		31		2015		—
Georgia Power		—		2011		2011		65		2015		—
Gulf Power		—		2011		2011		20		2015		—
Mississippi Power		—		2011		2011		24		2015		—
Southern Power		0.8		2011		2011		14		2012		2015

			In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 4 million mmbtu for Southern Company, 4 million mmbtu for Georgia Power, and was immaterial for the other registrants.

			For cash flow hedges, the amounts expected to be reclassified from OCI to revenue and fuel expense for the next 12-month period ending March 31, 2012 are immaterial for all registrants.

			*Interest Rate Derivatives*

			Southern Company and certain subsidiaries also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the

139

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

			effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives’ fair value gains or losses and hedged items’ fair value gains or losses are both recorded directly to earnings, providing an offset with any difference representing ineffectiveness.

			At March 31, 2011, the following interest rate derivatives were outstanding:

Fair Value

Hedge

Gain (Loss)

Notional

Interest Rate

Maturity

March 31,

Amount

Received

Paid

Date

2011

(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 March 31, 2012, 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	March 31, 2012			Amortized Through

	(in millions)
Southern Company	$	(16	)		2037
Alabama Power		1			2035
Georgia Power		(3	)		2037
Gulf Power		(1	)		2020
Southern Power		(12	)		2016

			*Foreign Currency Derivatives*

			Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives’ fair value gains or losses and the hedged items’ fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

140

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

At March 31, 2011, the following foreign currency derivatives were outstanding:

Fair Value

Gain (Loss)

Notional

Hedge

March 31,

Amount

Forward Rate

Maturity Date

2011

(in millions)

Cash flow hedges of forecasted transactions

Southern Company

YEN10

85.23 Yen per
Dollar*

May 2011

—

Fair value hedges of firm commitments

Mississippi Power

EUR38.9

1.253 Dollars
per Euro*

Various through July 2012

Total


*Weighted Average

			Derivative Financial Statement Presentation and Amounts

			At March 31, 2011, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:


Asset Derivatives at March 31, 2011
	Fair Value
Derivative Category and Balance Sheet	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
Location	Company		Power		Power		Power		Power		Power

	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	4	$	1	$	—	$	2	$	1
Other deferred charges and assets		6		1		2		1		2

Total derivatives designated as hedging instruments for regulatory purposes	$	10	$	2	$	2	$	3	$	3		N/A


Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	6	$	—	$	—	$	—	$	—	$	—
Other deferred charges and assets		3		—		—		—		—		—
Foreign currency derivatives:
Other current assets		5		—		—		—		5		—
Other deferred charges and assets		1		—		—		—		1		—

Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	15	$	—	$	—	$	—	$	6	$	—


Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets*	$	3	$	—	$	—	$	—	$	—	$	—
Assets from risk management activities		—		—		—		—		—		3
Other deferred charges and assets		1		—		—		—		—		1

Total derivatives not designated as hedging instruments	$	4	$	—	$	—	$	—	$	—	$	4


Total asset derivatives	$	29	$	2	$	2	$	3	$	9	$	4


*Southern Company includes “Assets from risk management activities” in “Other current assets” where applicable.

141

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


Liability Derivatives at March 31, 2011
	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	$	126	$	24	$	70	$	7	$	25
Other deferred credits and liabilities		40		5		16		4		15

Total derivatives designated as hedging instruments for regulatory purposes	$	166	$	29	$	86	$	11	$	40		N/A


Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Liabilities from risk management activities	$	1	$	—	$	—	$	—	$	—	$	—


Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	$	6	$	—	$	—	$	—	$	—	$	6


Total liability derivatives	$	173	$	29	$	86	$	11	$	40	$	6

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

			At March 31, 2011, 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 was 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	$	(126	)	$	(24	)	$	(70	)	$	(7	)	$	(25	)
Other regulatory assets, deferred		(40	)		(5	)		(16	)		(4	)		(15	)
Other regulatory liabilities, current		4			—			—			2			1
Other current liabilities*		—			1			—			—			—
Other regulatory liabilities, deferred		6			1			—			1			2
Other deferred credits and liabilities**		—			—			2			—			—

Total energy-related derivative gains (losses)	$	(156	)	$	(27	)	$	(84	)	$	(8	)	$	(37	)


*Alabama Power includes “Other regulatory liabilities, current” in “Other current liabilities.”

**Georgia Power includes “Other regulatory liabilities, deferred” in “Other deferred credits and liabilities.”

			For the three months ended March 31, 2011 and March 31, 2010, the pre-tax gains from interest rate derivatives designated as fair value hedging instruments on Southern Company’s statements of income were immaterial.

			For the three months ended March 31, 2011, the pre-tax gains from foreign currency derivatives designated as fair value hedging instruments on Southern Company’s and Mississippi Power’s statements of income were $3 million. This amount was offset with changes in the fair value of the purchase commitment related to equipment purchases; therefore, there is no impact on Southern Company’s or Mississippi Power’s statements of income.

142

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

For the three months ended March 31, 2011 and March 31, 2010, the pre-tax effect of 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
	2011		2010				2011			2010

	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	1	$	5		Fuel	$	—		$	—
Interest rate derivatives		4		(3	)	Interest expense, net of amounts capitalized		(5	)		(9	)

Total	$	5	$	2			$	(5	)	$	(9	)

Alabama Power
Interest rate derivatives	$	4	$	—		Interest expense, net of amounts capitalized	$	—		$	(2	)

Georgia Power
Interest rate derivatives	$	—	$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(5	)

Gulf Power
Interest rate derivatives	$	—	$	(2	)	Interest expense, net of amounts capitalized	$	—		$	—

Southern Power
Energy-related derivatives	$	1	$	4		Fuel	$	—		$	—
Interest rate derivatives		—		—		Interest expense, net of amounts capitalized		(3	)		(3	)

Total	$	1	$	4			$	(3	)	$	(3	)

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

			For the three months ended March 31, 2011 and March 31, 2010, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for Southern Company and Southern Power.

			Contingent Features

			The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At March 31, 2011, the fair value of derivative liabilities with contingent features, by registrant, was as follows:


	Southern		Alabama		Georgia		Gulf		Mississippi		Southern
	Company		Power		Power		Power		Power		Power

					(in millions)
Derivative liabilities	$	32	$	5	$	20	$	—	$	4	$	3

			At March 31, 2011, 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 $32 million for each registrant.

			Currently, each of the registrants has investment grade credit ratings from the major rating agencies with respect to debt, preferred securities, preferred stock, and/or preference stock. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. For the traditional operating companies and Southern Power, included in these amounts are certain agreements that could require collateral in the event that one or more Power Pool participants has a credit rating change to below investment grade.

143

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(I)

SEGMENT AND RELATED INFORMATION

Southern Company’s reportable business segments are the sale of electricity in the Southeast by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $83 million and $102 million for the three months ended March 31, 2011 and March 31, 2010, respectively. The “All Other” column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications, and leveraged lease projects. All other intersegment revenues are not material. Financial data for business segments and products and services was as follows:


	Electric Utilities
	Traditional
	Operating		Southern							All
	Companies		Power		Eliminations			Total		Other		Eliminations			Consolidated

	(in millions)
Three Months Ended March 31, 2011:
Operating revenues	$	3,810	$	282	$	(98	)	$	3,994	$	38	$	(20	)	$	4,012
Segment net income *		385		38		—			423		1		(2	)		422
Total assets at March 31, 2011	$	51,138	$	3,461	$	(74	)	$	54,525	$	1,059	$	(565	)	$	55,019


Three Months Ended March 31, 2010:
Operating revenues	$	4,005	$	256	$	(125	)	$	4,136	$	41	$	(20	)	$	4,157
Segment net income (loss)*		481		15		—			496		—		(1	)		495
Total assets at December 31, 2010	$	51,144	$	3,438	$	(128	)	$	54,454	$	1,178	$	(600	)	$	55,032


*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 March 31, 2011	$	3,396	$	449	$	149	$	3,994
Three Months Ended March 31, 2010	$	3,459	$	542	$	135	$	4,136

144


Item 6.		Exhibits.

(3) Articles of Incorporation and By-Laws

Alabama Power

(b)1

By-laws of Alabama Power as amended effective April 22, 2011 and presently in effect. (Designated in Form 8-K dated April 22, 2011, File No. 1-3164 as Exhibit 3.1.)

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

(b)1

Forty-Fifth Supplemental Indenture to Senior Note Indenture dated as of March 10, 2011, providing for the issuance of the Series 2011A 5.50% Senior Notes due March 15, 2041. (Designated in Form 8-K dated March 3, 2011, File No. 1-3164, as Exhibit 4.2.)

Georgia Power

Forty-Fifth Supplemental Indenture to Senior Note Indenture dated as of April 19, 2011, providing for the issuance of the Series 2011B 3.00% Senior Notes due April 15, 2016. (Designated in Form 8-K dated April 12, 2011, File No. 1-6468, as Exhibit 4.2.)

(10) Material Contracts

Southern Company

(a)1	-	Termination of Amended and Restated Change in Control Agreement effective February 22, 2011 between Southern Company, SCS and G. Edison Holland, Jr.

(a)2	-	Amended Deferred Compensation Agreement, effective December 31, 2008 between Southern Company, SCS, Georgia Power, Gulf Power and G. Edison Holland, Jr.

(a)3	-	Form of Stock Option Award Agreement for Executive Officers of Southern Company, under the Southern Company Omnibus Incentive Compensation Plan.

(a)4	-	Base Salaries of Named Executive Officers.

(a)5	-	Summary of Non-Employee Director Compensation Arrangements.

Georgia Power

Retention Agreement between Georgia Power and Michael A. Brown, effective January 1, 2011.

(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, 2010, 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, 2010, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)

146

Georgia Power

Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2010, 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, 2010, File No. 001-31737 as Exhibit 24(d)1 and incorporated herein by reference.)

(d)2	-	Power of Attorney Mark A. Crosswhite. (Designated in the Form 10-K for the year ended December 31, 2010, File No. 001-31737 as Exhibit 24(d)2 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, 2010, 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, 2010, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)

(31) Section 302 Certifications

Southern Company

(a)1	-	Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(a)2	-	Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Alabama Power

(b)1	-	Certificate of Alabama Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(b)2	-	Certificate of Alabama Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Georgia Power

(c)1	-	Certificate of Georgia Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(c)2	-	Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

147

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.

(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.

148


		Page
		Number
PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	145
Item 1A.	Risk Factors	145
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	146
	Signatures	150


		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		32
	Condensed Statements of Comprehensive Income		32
	Condensed Statements of Cash Flows		33
	Condensed Balance Sheets		34
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		36
	Georgia Power Company
	Condensed Statements of Income		49
	Condensed Statements of Comprehensive Income		49
	Condensed Statements of Cash Flows		50
	Condensed Balance Sheets		51
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		53
	Gulf Power Company
	Condensed Statements of Income		68
	Condensed Statements of Comprehensive Income		68
	Condensed Statements of Cash Flows		69
	Condensed Balance Sheets		70
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		72
	Mississippi Power Company
	Condensed Statements of Income		85
	Condensed Statements of Comprehensive Income		85
	Condensed Statements of Cash Flows		86
	Condensed Balance Sheets		87
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		89
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income		106
	Condensed Consolidated Statements of Comprehensive Income		106
	Condensed Consolidated Statements of Cash Flows		107
	Condensed Consolidated Balance Sheets		108
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		110
	Notes to the Condensed Financial Statements		119
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		30
Item 4.	Controls and Procedures		30


Term		Meaning
SCR		Selective catalytic reduction
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
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


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


	By		Thomas A. Fanning
			Chairman, President, and Chief Executive Officer
			(Principal Executive Officer)

	By		Art P. Beattie
			Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)

	By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


	By		Charles D. McCrary
			President and Chief Executive Officer
			(Principal Executive Officer)

	By		Philip C. Raymond
			Executive Vice President, Chief Financial Officer, and Treasurer
			(Principal Financial Officer)

	By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				GEORGIA POWER COMPANY

		By		W. Paul Bowers
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Ronnie R. Labrato
				Executive Vice President, Chief Financial Officer, and Treasurer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				GULF POWER COMPANY

		By		Mark A. Crosswhite
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Richard S. Teel
				Vice President and Chief Financial Officer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				MISSISSIPPI POWER COMPANY

		By		Edward Day, VI
				President and Chief Executive Officer
				(Principal Executive Officer)

		By		Moses H. Feagin
				Vice President, Chief Financial Officer, and Treasurer
				(Principal Financial Officer)

		By		/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)


				SOUTHERN POWER COMPANY

	By			Oscar C. Harper, IV
				President and Chief Executive Officer
				(Principal Executive Officer)

	By			Michael W. Southern
				Senior Vice President, Chief Financial Officer, and Treasurer
				(Principal Financial Officer)

	By			/s/ Melissa K. Caen (Melissa K. Caen, Attorney-in-fact)