e10vq

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 Southern Company’s wholesale business, retail sales growth, storm damage cost recovery and repairs, environmental regulations and expenditures, financing activities, completion of construction projects, impacts of adoption of new accounting rules, access to sources of capital, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include

•		the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, and also changes in environmental, tax, and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

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

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

•		variations in demand for electricity and gas, including those relating to weather, the general economy and population, and business growth (and declines);

•		available sources and costs of fuels;

•		ability to control costs;

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

•		advances in technology;

•		state and federal rate regulations and the impact of pending and future rate cases and negotiations;

•		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;

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

•		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, or other similar occurrences;

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

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

•		other factors discussed elsewhere herein and in other reports 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						For the Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	3,672,355		$	2,915,085		$	8,496,255		$	7,537,030
Sales for resale		505,764			343,255			1,237,738			1,037,785
Other electric revenues		110,630			99,678			321,072			287,469
Other revenues		88,895			82,787			331,474			319,731

Total operating revenues		4,377,644			3,440,805			10,386,539			9,182,015

Operating Expenses:
Fuel		1,432,376			982,786			3,366,234			2,691,536
Purchased power		347,330			187,753			569,223			525,577
Other operations		649,568			543,429			1,755,119			1,622,704
Maintenance		206,823			209,497			760,890			715,453
Depreciation and amortization		299,891			241,134			880,379			715,237
Taxes other than income taxes		179,103			161,165			504,964			474,232

Total operating expenses		3,115,091			2,325,764			7,836,809			6,744,739

Operating Income		1,262,553			1,115,041			2,549,730			2,437,276
Other Income and (Expense):
Allowance for equity funds used during construction		9,974			14,333			40,844			31,984
Interest income		9,104			6,174			20,599			20,283
Equity in losses of unconsolidated subsidiaries		(36,891	)		(23,904	)		(89,569	)		(74,656	)
Leveraged lease income		18,666			18,776			55,591			51,708
Interest expense, net of amounts capitalized		(162,175	)		(132,773	)		(455,377	)		(401,971	)
Interest expense to affiliate trusts		(31,930	)		(31,930	)		(95,791	)		(63,915	)
Distributions on mandatorily redeemable preferred securities		—			—			—			(31,168	)
Preferred dividends of subsidiaries		(7,425	)		(7,402	)		(22,229	)		(22,413	)
Other income (expense), net		6,190			(8,227	)		(1,441	)		(31,691	)

Total other income and (expense)		(194,487	)		(164,953	)		(547,373	)		(521,839	)

Earnings Before Income Taxes		1,068,066			950,088			2,002,357			1,915,437
Income taxes		345,862			305,615			570,372			587,690

Consolidated Net Income	$	722,204		$	644,473		$	1,431,985		$	1,327,747

Common Stock Data:
Consolidated basic earnings per share	$	0.97		$	0.87		$	1.92		$	1.80
Consolidated diluted earnings per share	$	0.97		$	0.87		$	1.91		$	1.79
Average number of basic shares of common stock outstanding (in thousands)		743,214			739,345			744,654			738,056
Average number of diluted shares of common stock outstanding (in thousands)		747,817			743,695			749,379			742,271
Cash dividends paid per share of common stock	$	0.3725		$	0.3575		$	1.1025		$	1.0575

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2005			2004
	(in thousands)
Operating Activities:
Consolidated net income	$	1,431,985		$	1,327,747
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization		1,050,873			866,839
Deferred income taxes and investment tax credits		376,474			484,282
Allowance for equity funds used during construction		(40,844	)		(31,984	)
Equity in losses of unconsolidated subsidiaries		89,569			74,656
Leveraged lease income		(55,591	)		(51,708	)
Pension, postretirement, and other employee benefits		31,584			4,978
Tax benefit of stock options		48,464			21,949
Hedge settlements		(19,860	)		(8,762	)
Storm damage accounting order		59,333			—
Other, net		(59,400	)		(66,218	)
Changes in certain current assets and liabilities —
Receivables, net		(968,895	)		(419,938	)
Fossil fuel stock		(41,240	)		31,814
Materials and supplies		(41,753	)		(22,680	)
Other current assets		10,482			(7,578	)
Accounts payable		24,023			(78,553	)
Accrued taxes		207,394			83,630
Accrued compensation		(107,313	)		(116,427	)
Other current liabilities		84,567			(11,369	)

Net cash provided from operating activities		2,079,852			2,080,678

Investing Activities:
Gross property additions		(1,706,045	)		(1,457,161	)
Investment in unconsolidated subsidiaries		(86,110	)		(73,810	)
Cost of removal net of salvage		(64,023	)		(47,420	)
Construction receivables/payables, net		(62,062	)		(30,638	)
Other		73,796			(17,706	)

Net cash used for investing activities		(1,844,444	)		(1,626,735	)

Financing Activities:
Increase (decrease) in notes payable, net		426,615			(210,457	)
Proceeds —
Long-term debt		930,695			1,426,125
Mandatorily redeemable preferred securities		—			200,000
Preferred stock		—			175,000
Common stock		208,722			89,678
Redemptions —
Long-term debt		(576,109	)		(1,081,639	)
Mandatorily redeemable preferred securities		—			(240,000	)
Preferred stock		—			(28,388	)
Common stock repurchased		(331,420	)		—
Payment of common stock dividends		(821,262	)		(779,875	)
Other		(29,509	)		(31,632	)

Net cash used for financing activities		(192,268	)		(481,188	)

Net Change in Cash and Cash Equivalents		43,140			(27,245	)
Cash and Cash Equivalents at Beginning of Period		373,199			311,274

Cash and Cash Equivalents at End of Period	$	416,339		$	284,029

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $16,139 and $29,785 capitalized for 2005 and 2004, respectively)	$	501,622		$	428,944
Income taxes (net of refunds)	$	35,014		$	35,973

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2005 vs. THIRD QUARTER 2004
AND
YEAR-TO-DATE 2005 vs. YEAR-TO-DATE 2004

OVERVIEW

Discussion of the results of operations is focused on Southern Company’s primary business of electricity sales in the Southeast by the retail operating companies – Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric – and Southern Power. Southern Power is an electric wholesale generation subsidiary with market-based rate authority. Southern Company’s other business activities include investments in synthetic fuels and leveraged lease projects, telecommunications, energy-related services, and natural gas marketing. For additional information on these businesses, see BUSINESS – The SOUTHERN System – “Retail Operating Companies,” “Southern Power,” and “Other Business” in Item 1 of the Form 10-K. Also see Note (P) to the Condensed Financial Statements herein for information on a letter of intent signed in July 2005 to sell the assets of Southern Company GAS, the natural gas marketing business.

Hurricanes Dennis and Katrina hit Southern Company’s service territory in July and August 2005, respectively. As a result of these storms, as well as Hurricane Ivan in September 2004, Southern Company has incurred significant restoration costs. In addition, fuel costs at each of the retail operating companies have risen significantly during 2005. Southern Company will continue to work with its regulators to develop methods to enable the timely recovery of these costs.

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate, return on equity, 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

Earnings

Southern Company’s third quarter and year-to-date 2005 earnings were $722 million ($0.97 per share) and $1.43 billion ($1.92 per share) compared with $644 million ($0.87 per share) and $1.33 billion ($1.80 per share), respectively, for the corresponding periods in 2004. Increases in earnings in the third quarter and year-to-date 2005 primarily resulted from warmer weather in September 2005, sustained economic strength, and customer growth in the Southern Company service area, as well as a base rate increase at Georgia Power. These increases were partially offset by the expiration of certain provisions of Georgia Power’s three-year retail rate plan that ended December 31, 2004 (2001 Retail Rate Plan), and higher other operations expenses as compared to the corresponding periods in 2004. See Note 3 to the financial statements of Southern Company under “Georgia Power Retail Rate Activity” in Item 8 of the Form 10-K for additional information on Georgia Power’s 2005 rate increase and 2001 Retail Rate Plan.

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant income statement items appropriate for discussion include the following:


	Increase (Decrease)
	Third Quarter						Year-To-Date
	(in thousands)			%			(in thousands)			%
Retail revenues	$	757,270			26.0		$	959,225			12.7
Sales for resale		162,509			47.3			199,953			19.3
Other electric revenues		10,952			11.0			33,603			11.7
Fuel expense		449,590			45.7			674,698			25.1
Purchased power expense		159,577			85.0			43,646			8.3
Other operations expense		106,139			19.5			132,415			8.2
Maintenance expense		(2,674	)		(1.3	)		45,437			6.4
Depreciation and amortization expense		58,757			24.4			165,142			23.1
Taxes other than income taxes		17,938			11.1			30,732			6.5
Allowance for equity funds used during construction		(4,359	)		(30.4	)		8,860			27.7
Equity in losses of unconsolidated subsidiaries		12,987			54.3			14,913			20.0
Interest expense, net of amounts capitalized		29,402			22.1			53,406			13.3
Other income (expense), net		14,417			175.2			30,250			95.5
Income taxes		40,247			13.2			(17,318	)		(2.9	)

Retail revenues. The chart below reflects the primary drivers of the 26.0% and 12.7% increases in retail revenues in the third quarter and year-to-date 2005 when compared to the prior year. See Note 3 to the financial statements of Southern Company under “Georgia Power Retail Rate Activity” in Item 8 of the Form 10-K for information on Georgia Power’s retail base rate increase that became effective January 1, 2005. Changes in revenue related to cost recovery mechanisms such as fuel, environmental, and storm damage have no effect on net income. In the third quarter and year-to-date 2005, retail kilowatt-hour energy sales increased by 5.6% and 1.2%, respectively, from the same periods a year ago, primarily due to warm weather in September 2005 and continued customer and demand growth from sustained economic growth in the Southeast. Even after the effects of Hurricane Katrina, the number of retail customers increased by 1.1% and weather-adjusted average consumption by retail customers increased by 1.2% for both the third quarter and year-to-date 2005 when compared with the third quarter and year-to-date 2004. See FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters – Storm Damage Cost Recovery” herein for additional information on the effects of Hurricane Katrina.

Details of retail revenues are as follows:


	Third Quarter					Year-to-Date
	2005					2005
	(in millions)		% change			(in millions)		% change
Retail – prior year	$	2,915				$	7,537
Change in —
Base rates		107		3.7			205		2.7
Sales growth		83		2.8			144		1.9
Weather		93		3.2			20		0.3
Fuel cost recovery		451		15.5			551		7.3
Other cost recovery		23		0.8			39		0.5

Retail – current year	$	3,672		26.0	%	$	8,496		12.7	%

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sales for resale. In the third quarter and year-to-date 2005, sales for resale increased $162.5 million, or 47.3%, and $200 million, or 19.3%, respectively, over the same periods in 2004. The increases reflect a rise in fuel revenues due to increases of 39.2% and 20.9%, respectively, in the average unit cost of fuel per net kilowatt-hour generated when compared to the same periods in the prior year, and new wholesale contracts between Georgia Power and 30 electric membership cooperatives (EMCs) and Flint EMC, both beginning in January 2005. In addition, Southern Power entered into new wholesale contracts with Flint EMC in January 2005 and added additional wholesale revenues through its acquisition of Oleander Power Project, L.P. (Oleander) and assumption of associated PPAs in June 2005. See FUTURE EARNINGS POTENTIAL – “Other Matters” herein for additional information on the Oleander acquisition.

Other electric revenues. In the third quarter and year-to-date 2005, when compared to the same periods in 2004, other electric revenues increased $11.0 million, or 11.0%, and $33.6 million, or 11.7%, respectively. These increases were primarily due to higher transmission revenues of $8.8 million and $18.4 million, respectively, and increased outdoor lighting revenues of $1.2 million and $4.4 million, respectively, in the third quarter and year-to-date 2005, respectively, as compared to the same periods in 2004. Customer fees increased $1.5 million and $4.1 million in the third quarter and year-to-date 2005, respectively, over the corresponding periods in 2004. Other electric revenues also increased by $2.8 million year-to-date 2005 when compared to the same period in 2004 as the result of early terminations of customer contracts at Alabama Power and Mississippi Power.

Fuel expense. Fuel expense was higher in the third quarter and year-to-date 2005 due to increases of 39.2% and 20.9%, respectively, in the average unit cost of fuel per net kilowatt-hour generated when compared to the same periods in the prior year. Increases in fuel expense at the retail operating companies are generally offset by fuel revenues and do not affect net income. See FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters – 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.

Purchased power expense. The $159.6 million and $43.6 million increases in purchased power expense in the third quarter and year-to-date 2005, respectively, compared with the same periods in the prior year are primarily a result of higher fuel prices and higher kilowatt-hour purchases resulting from increased demand due to warmer weather. Since these expenses generally are offset by energy revenues, they generally do not have a significant impact on earnings.

Other operations expense. The $106.1 million and $132.4 million increases in other operations expense in the third quarter and year-to-date 2005, respectively, compared with the same periods in the prior year are primarily a result of higher salaries and benefits costs of $62.1 million and $47.1 million, respectively. For the third quarter and year-to-date 2005, fossil generation operations expense increased $12.0 million and $22.4 million, respectively, and year-to-date transmission and distribution operations expense increased $48.6 million in each case when compared to the same periods in the prior year. These increases are due to a return to normal spending levels when compared to the prior year. Also in the third quarter and year-to-date 2005, insurance and workers compensation expenses increased $21.4 million and $12.0 million, respectively, over the corresponding periods in 2004.

Maintenance expense. The $45.4 million increase in maintenance expense year-to-date 2005 is mainly attributable to $45 million of expenses recorded by Alabama Power in accordance with an accounting order approved by the Alabama PSC to offset the costs of Hurricane Ivan and restore the natural disaster reserve. In accordance with the accounting order, Alabama Power also returned certain regulatory liabilities related to deferred taxes to its retail customers; therefore, the combined effects of this accounting order had no impact on net income. See Note 3 to the financial statements of Southern Company under “Gulf Power and Alabama

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Power Storm Damage Recovery” in Item 8 of the Form 10-K and “Income taxes” below for additional information.

Depreciation and amortization expense. The $58.8 million and $165.1 million increases in depreciation and amortization in the third quarter and year-to-date 2005, respectively, when compared to the prior year are primarily due to the expiration in 2004 of certain provisions in Georgia Power’s 2001 Retail Rate Plan. In accordance with the 2001 Retail Rate Plan, Georgia Power amortized an accelerated cost recovery liability equally as a credit to amortization expense and recognized new Georgia PSC-certified purchased power costs in rates evenly over the three years ended December 31, 2004. This treatment resulted in a credit to amortization expense of $47 million and $140 million during the third quarter and year-to-date 2004, respectively. See Note 3 to the financial statements of Southern Company under “Georgia Power Retail Rate Activity” in Item 8 of the Form 10-K for additional information.

Taxes other than income taxes. The $17.9 million and $30.7 million increases in taxes other than income taxes in the third quarter and year-to-date 2005, respectively, compared with the same periods in the prior year are primarily a result of increases in franchise and gross receipts taxes associated with increases in revenues from energy sales.

Allowance for equity funds used during construction. The $8.9 million increase in AFUDC equity year-to-date 2005 compared to the same period in the prior year relates primarily to construction of the McIntosh combined cycle units 10 and 11 by Georgia Power and Savannah Electric. See Note 3 to the financial statements of Southern Company under “Plant McIntosh Construction Project” in Item 8 of the Form 10-K for further information. AFUDC equity is non-taxable. See Note (H) to the Condensed Financial Statements herein for information on the impact on Southern Company’s 2005 annual effective tax rate.

Equity in losses of unconsolidated subsidiaries. The $13.0 million and $14.9 million increases in equity in losses of unconsolidated subsidiaries in the third quarter and year-to-date 2005, respectively, compared with the same periods in the prior year reflect increased production at synfuel production facilities that generate operating losses. These partnerships also claim federal income tax credits that offset these operating losses and make the projects profitable. See FUTURE EARNINGS POTENTIAL – “Income Tax Matters – Synthetic Fuel Tax Credits” herein for further information.

Interest expense, net of amounts capitalized. The $29.4 million and $53.4 million increases in interest expense, net of amounts capitalized, in the third quarter and year-to-date 2005, respectively, when compared to the same periods in 2004 are mainly attributed to $11.0 million and $24.2 million, respectively, associated with issuance of new long-term and short-term debt, and $11.2 million and $18.2 million, respectively, resulting from higher interest rates on variable rate debt. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” of Southern Company in Item 7 of the Form 10-K and herein for additional information.

Other income (expense), net. The increases in other income (expense), net of $14.4 million and $30.3 million in the third quarter and year-to-date 2005, respectively, when compared to the same periods in the prior year, are primarily a result of $13.5 million in realized gains on gas hedges at Georgia Power and Savannah Electric, under programs approved by the Georgia PSC. Also contributing to the year-to-date 2005 increases over the prior year were a $2.4 million increase in gains on the sale of certain investments, and a $4.9 million decrease in charitable contributions.

Income taxes. The $40.2 million increase in income taxes in the third quarter 2005 when compared to the prior year is primarily due to taxes associated with higher net income in 2005, offset by a $18.6 million increase

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

in tax benefits received related to higher production at synfuel production facilities. The $17.3 million decrease in year-to-date 2005 income taxes over the prior year is primarily the result of the impact of the Alabama PSC accounting order discussed under “Maintenance expense” above and a $27.9 million increase in tax benefits received related to higher production at synfuel production facilities. The year-to-date 2005 decrease over 2004 is partially offset by higher net income in 2005. Southern Company’s annual effective income tax rate is expected to be approximately 27% for 2005. See Note 5 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company’s future earnings potential. The level of Southern Company’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company’s primary business of selling electricity. These factors include the retail operating companies’ ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Future earnings for the electricity business in the near term will depend, in part, upon growth in 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 in the service area. For additional information relating to these issues, see BUSINESS – The SOUTHERN System – “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental regulations could affect earnings if such costs cannot be fully recovered in rates on a timely basis. For additional information, including information on certain environmental litigation, 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.

New Source Review Actions

On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued its decision in favor of Alabama Power on two primary legal issues in the case: (1) the scope of the routine maintenance repair and replacement exclusion under the New Source Review (NSR) rules and (2) the proper test for calculating emissions increases under those rules. The court decided that routine maintenance repair and replacement must be defined with reference to what is routine in the industry as opposed to what is routine at an individual unit and emissions increases must be measured against the maximum hourly emission rate. The decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations involving Plant Miller Units 3 and 4. In separate orders, the court dismissed Alabama Power’s motion for summary judgment on the Plant Miller claims, stayed the entire case, and referred the parties to mediation. Alabama Power may refile its motion for summary judgment if the mediation proves unsuccessful. At the request of the mediator, the deadline for completing the mediation has been extended from September 9, 2005 to November 30, 2005. The Georgia Power and Savannah Electric case, which is pending in federal district court in Georgia, remains administratively closed. The ultimate outcome of these matters cannot now be determined. See MANAGEMENT’S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL – “Environmental

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 and Note (B) to the Condensed Financial Statements herein under “New Source Review Actions” for additional information.

On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. On October 20, 2005, the EPA published a proposed rule clarifying the test for determining when an emissions increase is subject to the NSR requirements. The impact of the proposed rules will depend on adoption of the final rules by the EPA and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Plant Wansley Environmental Litigation

In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted Georgia Power’s petition for review of the U.S. District Court for the Northern District of Georgia’s December 15, 2004 order related to the Plant Wansley environmental litigation. Oral argument is scheduled for early 2006. The ultimate outcome of this matter cannot now be determined. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL – “Environmental Matters – Plant Wansley Environmental Litigation” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Environmental Matters – Plant Wansley Environmental Litigation” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under “Plant Wansley Environmental Litigation” for additional information.

Carbon Dioxide Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation” of Southern Company in Item 7 of the Form 10-K for information on a complaint filed by attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City in July 2004 against Southern Company and four other electric power companies alleging that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. A nearly identical complaint was filed by three environmental groups in the same court. In September 2005, the U.S. District Court for the Southern District of New York dismissed these cases. The plaintiffs filed an appeal on October 19, 2005. The ultimate outcome of this matter cannot be determined at this time.

Other Environmental Matters

The EPA issued the final Clean Air Interstate Rule on March 10, 2005. The rule addresses sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions that contribute to nonattainment of the eight-hour ozone and fine particulate matter National Ambient Air Quality Standards. Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the fine particulate matter and/or the eight-hour ozone requirements set forth within the rule. The rule may require additional reductions of NO_x and/or SO₂ to be achieved by the installation of additional controls at Southern Company’s coal-fired facilities or through the purchase of allowances.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, selecting a cap-and-trade approach to be implemented in two phases, 2010 and 2018. The rule sets a permanent cap on emissions at the 2018 level and provides for an emissions allowance trading market.

On June 15, 2005, the EPA issued final rules addressing Best Available Retrofit Technology (BART) standards under the Regional Haze Program. States must develop regulations to implement the federal regional haze requirements, including BART standards, by December 17, 2007.

On June 14 and 15, 2005, the EPA published final rules approving the redesignation of the Atlanta metro area to “attainment” under the one-hour ground-level ozone standard. On June 15, 2005, the EPA revoked the one-hour ground-level ozone standard, in connection with the implementation of its new eight-hour ozone standard.

On September 8, 2005, the EPA proposed a rule for the implementation of the fine particulate matter air quality standard. Several areas within Southern Company’s service area in Alabama and Georgia were previously designated by the EPA as “nonattainment” for the standard. The EPA plans to finalize the proposed implementation rule in 2006.

The impact of these rules on Southern Company will depend on the outcome of legal challenges and development and implementation of applicable state regulations and therefore cannot be determined at this time.

FERC and State PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters – Market-Based Rate Authority” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Market-Based Rate Authority” in Item 8 of the Form 10-K for information on the FERC’s April 2004 order adopting a new interim analysis for measuring generation market power and a proceeding initiated by the FERC in December 2004 to assess Southern Company’s generation dominance within its retail service territory. Each of the retail operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates at market-based prices. Through SCS, as agent, the retail operating companies and Southern Power also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. On February 15, 2005, Southern Company submitted additional information related to generation dominance in Southern Company’s retail service territory. A hearing before an administrative law judge to review the February filing is scheduled for March 2006. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event that the FERC’s default mitigation measures are ultimately applied, the retail operating companies and Southern Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The impact of such sales through September 30, 2005 is not material to Southern Company’s net income. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

subsidiary will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the refund period beginning July 19, 2005. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below. The impact of such sales through September 30, 2005 is not material to Southern Company’s net income.

Southern Company and its subsidiaries believe that there is no meritorious basis for these allegations and intend to vigorously defend themselves in the proceeding. However, the final outcome of this matter, including any remedies to be applied in the event of an adverse ruling in this proceeding, cannot now be determined.

Intercompany Interchange Contract

Also, in May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. The hearing is scheduled for June 2006. See Note 3 to the financial statements of Southern Company under “Plant McIntosh Construction Project” in Item 8 of the Form 10-K for further information on the McIntosh PPA proceeding. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.

Generation Interconnection Agreements

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters – Generation Interconnection Agreements” of Southern Company in Item 7 of the Form 10-K for information on the FERC’s Order 2003 related to standardization of generation interconnection agreements and procedures. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to three previously executed interconnection agreements with subsidiaries of Southern Company, have filed complaints at the FERC requesting that the FERC modify the agreements and that Southern Company refund a total of $19 million previously paid for interconnection facilities, with interest. Southern Company has also received similar requests from other entities totaling approximately $14 million. Southern Company has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on Southern Company and the final results of these matters cannot be determined at this time.

Alabama Power Environmental Rate Filing

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

that will be calculated annually. Environmental costs to be recovered include operation and maintenance expenses, depreciation, and a return on invested capital. Retail rates increased 1% in January 2005, which should yield an annual recovery of approximately $33 million, and are expected to increase approximately 1% in 2006. In conjunction with the Alabama PSC’s approval, Alabama Power agreed to a moratorium until 2007 on any retail rate increase under its previously approved Rate Stabilization and Equalization Plan (Rate RSE). See “Alabama Power Base Rates” below for further information on Rate RSE.

Alabama Power Rate RSE

See Note 3 to the financial statements of Southern Company under “Alabama Power Retail Regulatory Matters” in Item 8 of the Form 10-K for information on Alabama Power’s Rate RSE. On October 4, 2005, the Alabama PSC approved a revision to Rate RSE requested by Alabama Power. Rate RSE adjustments can be made effective January 2007 and annually thereafter and will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. The range of return on common equity, on which such adjustments are based, remains unchanged. If Alabama Power’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. Alabama Power will make its initial submission of projected data for calendar year 2007 by December 1, 2006.

Retail Fuel Cost Recovery

The retail operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In recent quarters, the retail operating companies have experienced higher than expected fuel costs for coal and gas. These higher fuel costs have increased the under recovered fuel costs included in the balance sheets to approximately $985 million at September 30, 2005. Operating revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes to the billing factors will have no significant effect on Southern Company’s revenues or net income, but will affect annual cash flow. The retail operating companies will continue to monitor the under recovered fuel cost balance in light of these higher fuel costs.

On October 19, 2005, Alabama Power filed with the Alabama PSC for a fuel cost recovery increase under the provisions of its energy cost recovery rate (Rate ECR). An approval of this filing would result in an increase of the energy billing factor for retail customers from 1.788 cents per kilowatt-hour to 2.650 cents per kilowatt-hour and would become effective December 3, 2005. This change represents an $8.62 per month increase for an average residential customer billing of 1,000 kilowatt-hours. The requested increase is intended to allow for the recovery of energy costs based on an estimate of future energy costs, as well as the collection of the existing under recovered energy costs by the end of 2006. Alabama Power’s under recovered retail energy costs as of September 30, 2005 totaled $182.4 million. Under the terms of Rate ECR, the increase will be effective 45 days after the filing unless modified by the Alabama PSC following a public hearing. The final outcome of this filing cannot be determined at this time. See Note 3 to the financial statements of Southern Company under “Alabama Power Retail Regulatory Matters” in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements herein for additional information.

On May 17, 2005, the Georgia PSC voted to allow Georgia Power to increase customer fuel rates to recover estimated under-recovered fuel costs of approximately $508 million as of May 31, 2005 over the period from June 1, 2005 through May 31, 2009, as well as future projected fuel costs based on a June 2005 through May 2006 test period. The new fuel rate became effective June 1, 2005 and represents an average annual increase in customer billings of approximately 9.5%, or approximately $473 million. Based on the order, a portion of the under recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

on the balance sheet. Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $198.3 million through September 30, 2005. In accordance with the Georgia PSC’s order, such amounts will be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power will be required to file for a temporary fuel rate change. However, Georgia Power has agreed with a Georgia PSC staff recommendation to suspend the temporary fuel rate provision and, instead, will file a request no later than April 2006 to increase its fuel cost recovery rate. 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 increase in the billing factor would have no significant effect on Georgia Power’s revenues or net income, but would increase annual cash flow. See Note 3 to the financial statements of Southern Company under “Georgia Power Retail Rate Activity” in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements herein for additional information.

Storm Damage Cost Recovery

Hurricane Ivan hit the Gulf coast of Florida and Alabama in September 2004, causing significant damage to the service areas of both Gulf Power and Alabama Power. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC and State PSC Matters — Storm Damage Cost Recovery” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Gulf Power and Alabama Power Storm Damage Recovery” in Item 8 of the Form 10-K for additional information. In March 2005, the Florida PSC approved a Stipulation and Settlement between Gulf Power, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group. The agreement allows Gulf Power to recover approximately $51.7 million in storm damage costs, plus interest and revenue taxes, from customers over a 24-month period that began in April 2005. Gulf Power also agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

In July and August 2005, Hurricanes Dennis and Katrina, respectively, hit the Gulf Coast of the United States and caused significant damage within Southern Company’s service area, including portions of Gulf Power, Alabama Power, and Mississippi Power. Hurricane Dennis and Katrina restoration costs are currently estimated to total approximately $425 million to $475 million, of which approximately $230 million to $250 million relates to operation and maintenance expenditures. Such cost estimates exclude approximately $60 million expected to be covered through external insurance. Restoration efforts following Hurricane Katrina are ongoing for approximately 19,200 Mississippi Power customers who remain unable to receive power, as well as to make permanent improvements in areas where temporary emergency repairs were necessary. In addition, business and governmental authorities are still reviewing redevelopment plans for portions of the most severely damaged areas along the Mississippi shoreline. Until such plans are complete, Mississippi Power cannot determine the related electric power needs or associated cost estimates. The ultimate impact of redevelopment plans in these areas on the cost estimates cannot now be determined.

Each retail operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. In addition, each of the affected retail operating companies has been authorized by their respective state PSCs to defer the portion of the Hurricane Dennis and Katrina restoration costs that exceeded the balance in their storm damage reserve accounts. As of September 30, 2005, the deficit balance in Southern Company’s storm damage reserve accounts totaled approximately $308 million, of which approximately $36 million and $272 million, respectively, is included in the Condensed Balance Sheets herein under “Other Current Assets” and “Other Regulatory Assets.”

The recovery of these deferred costs is subject to the approval of the respective state PSCs. On November 1, 2005, Alabama Power requested the Alabama PSC to approve a separate rate rider to recover its $69 million

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of deferred Hurricane Dennis and Katrina operation and maintenance costs over a two-year period and to replenish the reserve to a target balance of $75 million over a five-year period. In December 2005, Mississippi Power expects to file additional details of its $245 million to $295 million of Hurricane Katrina restoration costs with the Mississippi PSC, as required, and to establish a method to recover such costs from customers. In 2005, the Florida legislature authorized securitized financing for hurricane costs. Gulf Power is currently evaluating this option, along with other alternatives, to allow a more rapid recovery of its total deferred costs of approximately $58 million.

See Notes (I), (K), and (L) to the Condensed Financial Statements herein and Note 1 to the financial statements of Southern Company under “Storm Damage Reserves” in Item 8 of the Form 10-K for additional information. The estimates of storm damage restoration costs and expected external insurance recoveries are subject to change. The ultimate impact of these matters cannot now be determined.

Mirant Related Matters

See Note 3 to the financial statements of Southern Company under “Mirant Related Matters – Mirant Bankruptcy” in Item 8 of the Form 10-K for information regarding Southern Company’s contingent liabilities associated with Mirant, including guarantees of contractual commitments, litigation, and joint and several liabilities in connection with the consolidated federal income tax return.

In July 2003, Mirant filed for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code. In June 2004, Mirant’s bankruptcy counsel notified Southern Company that it was investigating, on behalf of a committee of independent Mirant directors, potential claims against Southern Company.

In June 2005, Mirant, as a debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas and filed an amended complaint on July 6, 2005. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company in 1999 and 2000 with actual intent to hinder, delay, or defraud creditors or, alternatively, when Southern Company knew or should have known that Mirant was allegedly insolvent, undercapitalized or unable to pay its debts. The alleged fraudulent transfers and/or illegal dividends include: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80% interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer Mirant asserts is valued at $247.9 million. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of liability and that Southern Company caused Mirant to breach its fiduciary duty of loyalty to its creditors. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys fees, and costs. Finally, Mirant objects to Southern Company’s claims against Mirant in the Bankruptcy Court (which, in the aggregate, currently total approximately $70 million) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company believes there is no meritorious basis for Mirant’s claims and intends to vigorously defend itself in this action. Southern Company filed an answer to the amended complaint in August 2005, and has filed motions to transfer the case from the Bankruptcy Court to the U.S. District Court for the Northern District of Georgia. The ultimate outcome of this matter cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In July 2005, The Official Committee of Unsecured Creditors of Mirant Corporation, on behalf of Mirant, as a debtor in possession, and its creditors, filed a complaint in the Bankruptcy Court against certain former officers and directors of Mirant and/or Southern Company. The complaint alleged that the defendants breached their fiduciary duties of loyalty and care owed to Mirant and its creditors by allowing Mirant to overpay for certain acquisitions of utility assets in 1997, 1998, and 1999, and by authorizing or participating in the transfers described above from Mirant to Southern Company in 1999 and 2000 when Mirant was allegedly insolvent, undercapitalized, or unable to pay its debts. In August 2005, the lawsuit was dismissed without prejudice. The ultimate outcome of this matter cannot be determined at this time.

Income Tax Matters

Leveraged Lease Transactions

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “Income Tax Matters - Leveraged Lease Transactions” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Income Tax Matters — Leveraged Lease Transactions” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under “Income Tax Matters” for information regarding IRS challenges to Southern Company’s transactions related to international leveraged leases that could have material impacts on Southern Company’s financial statements. The FASB has recently proposed changes to the accounting for both leveraged leases and uncertain tax positions that may be effective as early as December 31, 2005. If approved as proposed, these changes could require Southern Company to reflect the tax deductions that the IRS is challenging as currently payable on the balance sheet and to change the timing of income recognized under the leases, including a cumulative effect upon adoption of the change. For the lease settled with the IRS in February 2005, Southern Company estimates such cumulative effect would reduce Southern Company’s net income by approximately $11 million. The impact of these proposed changes related to the remaining three lease transactions would be dependent on the outcome of ongoing negotiations with the IRS, but could be significant, and potentially material, to Southern Company’s net income. The ultimate outcome of these matters cannot now be determined.

Synthetic Fuel Tax Credits

As discussed in Note 3 to the financial statements of Southern Company under “Income Tax Matters - Synthetic Fuel Tax Credits” in Item 8 of the Form 10-K, Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 29 of the IRC. In accordance with Section 29 of the IRC, these tax credits are subject to limitation as the annual average price of oil (as determined by the DOE) increases over a specified, inflation-adjusted dollar amount published in the spring of the subsequent year. Southern Company, along with its partners in these investments, will continue to monitor oil prices. Any indicated potential limitation on these credits could affect either the timing or the amount of the credit recognition and could also require an impairment analysis of these investments by Southern Company. In April 2005, Southern Company entered into a derivative transaction designed to reduce its exposure to the potential phase-out of these credits in 2005. The purchased option, which had an initial fair value of approximately $7 million, is being marked to market over the remainder of the year through other income (expense), net. See Note (F) to the Condensed Financial Statements herein for additional information.

Other Matters

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

partnership interests in Oleander was pursuant to a Purchase and Sale Agreement dated April 8, 2005, for an aggregate purchase price of approximately $206 million, plus approximately $12 million of working capital and other adjustments. The purchase was for a dual-fueled generating plant in Brevard County, Florida with a nominal installed capacity of 680 MW. The entire output of the plant is sold under separate PPAs with Florida Power & Light Company and Seminole Electric Cooperative, Inc. The PPAs expire in 2007 and 2009, respectively.

In July 2005, the U.S. Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush signed into law in August 2005. Among other things, the Energy Act includes various tax subsidies for electric utilities and provisions repealing the PUHCA. The Energy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. The implementation of the Energy Act requires proceedings at the state level and the development of regulations by the FERC, as well as other federal agencies. Southern Company is still reviewing the legislation. Its impacts will depend on the promulgation and implementation of final rules and cannot be determined at this time.

Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

New Accounting Standards

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

required under the revised statement differs slightly, the impacts on Southern Company’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements of Southern Company under “Stock Options” in Item 8 of the Form 10-K and in Note (C) to the Condensed Financial Statements herein.

FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations, was issued in March 2005. This interpretation of FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS No. 143), requires that asset retirement obligations be recorded when a legal obligation exists even though the timing and/or the method of settlement are conditional on a future event. As required under FAS No. 143, the present value of the ultimate cost of retiring long-lived assets is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. For Southern Company, FIN 47 is effective no later than December 31, 2005. Southern Company currently expects to record additional asset retirement obligations (and plant in service) of less than $200 million, primarily related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. However, Southern Company has not concluded its assessment of FIN 47 and other potential obligations are still being evaluated. The adoption of FIN 47 is not expected to have any effect on Southern Company’s income statement.

In December 2004, the FASB issued Staff Position No. 109-1 (FSP 109-1), Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction for utilities be accounted for as a special tax deduction rather than as a tax rate reduction. Southern Company adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition continued to be stable at September 30, 2005. Net cash flow from operating activities totaled $2.1 billion for first nine months of 2005, compared to $2.1 billion for the corresponding period in 2004. Gross property additions to utility plant were $1.7 billion in the first nine months of 2005. The majority of funds needed for gross property additions since 2000 has been provided from operating activities.

Significant balance sheet changes include a $406 million increase in long-term debt for the first nine months of 2005 primarily due to an increase of $711 million in property, plant, and equipment.

The market price of Southern Company’s common stock at September 30, 2005 was $35.76 per share and the book value was $14.59 per share, representing a market-to-book ratio of 245%, compared to $33.52, $13.86, and 242%, respectively, at the end of 2004. The dividend for the third quarter 2005 was $0.3725 per share compared to $0.3575 per share in the third quarter 2004.

The retail operating companies, Southern Power, and SCS have each maintained investment grade ratings from the major rating agencies.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY –“Capital Requirements and Contractual Obligations” of Southern Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for its construction program and other funding

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred stock dividends, leases, trust funding requirements, and other purchase commitments. Approximately $919 million will be required by September 30, 2006 for redemptions and maturities of long-term debt.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. The amounts and timing of additional equity capital to be raised will be contingent on Southern Company’s investment opportunities. The retail 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, and term loan and short-term borrowings. However, the amount, type, and timing of any financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Southern Company in Item 7 of the Form 10-K for additional information.

To meet short term cash needs and contingencies, the Southern Company system had at September 30, 2005 approximately $416 million of cash and cash equivalents and approximately $3.1 billion of unused credit arrangements with banks, of which $24.0 million expire in 2005 and $3.1 billion expire in 2006 and beyond. Of the facilities maturing in 2005 and 2006, $296 million contain provisions allowing one-year term loans executable at the expiration date and $168 million contain provisions allowing two-year term loans executable at the expiration date. These unused credit arrangements also provide liquidity support to variable rate pollution control bonds and commercial paper programs. Southern Company expects to renew its credit facilities, as needed, prior to expiration. In October 2005, additional credit facilities totaling $340 million were signed. A portion of these facilities will be used to fund costs related to Hurricanes Ivan, Dennis, and Katrina, with the remainder used to support obligations with respect to variable rate pollution control bonds and commercial paper. The retail operating companies may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of each of the retail operating companies. At September 30, 2005, the Southern Company system had outstanding commercial paper of $816.8 million, $20 million borrowed under revolving lines of credit, and extendible commercial notes of $16.2 million. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs and lines of credit without maintaining large cash balances.

Off-Balance Sheet Financing Arrangements

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

Credit Rating Risk

Southern Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. These contracts are primarily for physical electricity purchases and sales. At September 30, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $61 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $354 million. In addition, through the acquisition of Oleander, Southern Power assumed a PPA with Seminole

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Electric Cooperative, Inc. that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. The amount of this collateral cannot be determined at this time. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit, or cash. Southern Company is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At September 30, 2005, Southern Company and its subsidiaries had no material exposure related to these agreements.

Market Price Risk

Southern Company’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2004 reporting period. In addition, Southern Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.

Due to cost-based rate regulations, the retail operating companies have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. In addition, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. To mitigate residual risks relative to movements in electricity prices, the retail operating companies and Southern Power enter into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into similar contracts for gas purchases. The retail operating companies have implemented fuel hedging programs at the instruction of their respective state PSCs. Southern Company GAS also has in place a risk management program to substantially mitigate its exposure to price volatility for its natural gas purchases.

The fair value of derivative energy contracts at September 30, 2005 was as follows:


	Third Quarter
	2005			Year-to-Date
	Changes			Changes
	Fair Value
	(in millions)
Contracts beginning of period	$	64.0		$	10.5
Contracts realized or settled		(19.7	)		(54.8	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		122.6			211.2

Contracts at September 30, 2005	$	166.9		$	166.9

(a)

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


	Source of September 30, 2005
	Valuation Prices
	Total			Maturity
	Fair Value			Year 1			1-3 Years
	(in millions)
Actively quoted	$	173.3		$	153.7		$	19.6
External sources		(6.4	)		(6.4	)		—
Models and other methods		—			—			—

Contracts at September 30, 2005	$	166.9		$	147.3		$	19.6

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	1,172,295		$	979,768		$	2,744,536		$	2,571,549
Sales for resale —
Non-affiliates		165,923			134,068			410,935			366,504
Affiliates		73,551			95,739			228,771			215,472
Other revenues		46,201			36,798			129,303			111,359

Total operating revenues		1,457,970			1,246,373			3,513,545			3,264,884

Operating Expenses:
Fuel		419,306			331,853			1,042,454			880,942
Purchased power —
Non-affiliates		96,190			65,844			154,372			159,994
Affiliates		90,298			51,259			200,083			171,591
Other operations		180,574			156,179			495,851			463,454
Maintenance		60,335			60,307			264,747			231,412
Depreciation and amortization		108,634			106,860			318,144			318,359
Taxes other than income taxes		59,256			59,124			184,790			182,899

Total operating expenses		1,014,593			831,426			2,660,441			2,408,651

Operating Income		443,377			414,947			853,104			856,233
Other Income and (Expense):
Allowance for equity funds used during construction		5,372			4,237			15,811			12,261
Interest income		5,110			3,605			12,679			11,934
Interest expense, net of amounts capitalized		(50,797	)		(46,385	)		(147,519	)		(148,831	)
Interest expense to affiliate trusts		(4,059	)		(4,059	)		(12,178	)		(8,240	)
Distributions on mandatorily redeemable preferred securities		—			—			—			(3,938	)
Other income (expense), net		(7,082	)		(7,682	)		(10,919	)		(18,435	)

Total other income and (expense)		(51,456	)		(50,284	)		(142,126	)		(155,249	)

Earnings Before Income Taxes		391,921			364,663			710,978			700,984
Income taxes		149,764			138,834			241,782			268,669

Net Income		242,157			225,829			469,196			432,315
Dividends on Preferred Stock		6,072			6,072			18,216			17,524

Net Income After Dividends on Preferred Stock	$	236,085		$	219,757		$	450,980		$	414,791

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
	(in thousands)						(in thousands)
Net Income After Dividends on Preferred Stock	$	236,085		$	219,757		$	450,980		$	414,791
Other comprehensive income (loss):
Change in fair value of marketable securities, net of tax of $(285) and $-, respectively		—			(470	)		—			—
Changes in fair value of qualifying hedges, net of tax of $8,521, $(11,016), $3,318 and $(5,331), respectively		14,016			(18,118	)		5,458			(8,768	)
Reclassification adjustment for amounts included in net income, net of tax of $(350), $592, $(631) and $2,164, respectively		(576	)		975			(1,037	)		3,560

COMPREHENSIVE INCOME	$	249,525		$	202,144		$	455,401		$	409,583

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

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2005			2004
	(in thousands)
Operating Activities:
Net income	$	469,196		$	432,315
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		375,607			373,792
Deferred income taxes and investment tax credits, net		79,621			117,894
Deferred revenues		(9,939	)		(8,286	)
Allowance for equity funds used during construction		(15,811	)		(12,261	)
Pension, postretirement, and other employee benefits		(10,543	)		(16,129	)
Tax benefit of stock options		16,790			7,004
Hedge settlements		(21,445	)		3,594
Storm damage accounting order		45,000			—
Other, net		(18,971	)		(22,790	)
Changes in certain current assets and liabilities —
Receivables, net		(246,214	)		(203,743	)
Fossil fuel stock		(38,942	)		18,193
Materials and supplies		(9,356	)		(13,701	)
Other current assets		12,454			28,730
Accounts payable		(18,226	)		(87,173	)
Accrued taxes		64,162			150,153
Accrued compensation		(11,086	)		(26,040	)
Other current liabilities		55,914			3,582

Net cash provided from operating activities		718,211			745,134

Investing Activities:
Gross property additions		(605,720	)		(533,563	)
Cost of removal net of salvage		(40,689	)		(25,484	)
Other		26,210			14,142

Net cash used for investing activities		(620,199	)		(544,905	)

Financing Activities:
Increase in notes payable, net		—			130,791
Proceeds —
Senior notes		250,000			600,000
Preferred stock		—			100,000
Common stock		40,000			40,000
Capital contributions from parent company		(304	)		—
Redemptions —
Senior notes		—			(725,000	)
Other long-term debt		546			(1,445	)
Payment of preferred stock dividends		(16,684	)		(16,197	)
Payment of common stock dividends		(307,425	)		(327,975	)
Other		(2,459	)		(14,759	)

Net cash used for financing activities		(36,326	)		(214,585	)

Net Change in Cash and Cash Equivalents		61,686			(14,356	)
Cash and Cash Equivalents at Beginning of Period		84,461			42,752

Cash and Cash Equivalents at End of Period	$	146,147		$	28,396

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $5,802 and $5,118 capitalized for 2005 and 2004, respectively)	$	115,505		$	120,302
Income taxes (net of refunds)	$	111,473		$	18,490

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

ALABAMA POWER COMPANY

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

THIRD QUARTER 2005 vs. THIRD QUARTER 2004
AND
YEAR-TO-DATE 2005 vs. YEAR-TO-DATE 2004

OVERVIEW

Discussion of the results of operations is focused on Alabama Power’s business of electricity sales to retail customers within its traditional service area located within the State of Alabama and to wholesale customers in the Southeast. Many factors affect the opportunities, challenges, and risks of Alabama Power’s business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Hurricanes Dennis and Katrina hit Alabama Power’s service territory in July and August 2005, respectively. As a result of these storms, as well as Hurricane Ivan in September 2004, Alabama Power has incurred significant restoration costs. In addition, fuel costs have risen significantly during 2005. Alabama Power will continue to work with the Alabama PSC to develop methods to enable the timely recovery of these costs.

Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate and return on equity. 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

Earnings

Alabama Power’s net income after dividends on preferred stock for the third quarter and year-to-date 2005 was $236.1 million and $451.0 million, respectively, compared to $219.8 million and $414.8 million, respectively, for the corresponding periods of 2004. Earnings in the third quarter 2005 increased by $16.3 million, or 7.4%, and earnings year-to-date 2005 increased by $36.2 million, or 8.7%. These increases were primarily due to an increase in retail base-rate revenues due to favorable weather conditions during the third quarter 2005 and a 1% increase in retail rates that took effect January 1, 2005 under Alabama Power’s new environmental rate order approved by the Alabama PSC. See Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information on Alabama Power’s rates. Additionally, Alabama Power ceased accruing nuclear decommissioning expenses in 2005. See FUTURE EARNINGS POTENTIAL — “FERC and Alabama PSC Matters — Nuclear Relicensing” in Item 7 of the Form 10-K and herein and Note (I) to the Condensed Financial Statements herein for additional information on the related Alabama PSC order.

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

Significant income statement items appropriate for discussion include the following:


	Increase (Decrease)
	Third Quarter						Year-To-Date
	(in thousands)			%			(in thousands)			%
Retail revenues	$	192,527			19.7		$	172,987			6.7
Sales for resale-non-affiliates		31,855			23.8			44,431			12.1
Sales for resale-affiliates		(22,188	)		(23.2	)		13,299			6.2
Other revenues		9,403			25.6			17,944			16.1
Fuel expense		87,453			26.4			161,512			18.3
Purchased power-non-affiliates		30,346			46.1			(5,622	)		(3.5	)
Purchased power-affiliates		39,039			76.2			28,492			16.6
Other operations and maintenance expense		24,423			11.3			65,732			9.5
Income taxes		10,930			7.9			(26,887	)		(10.0	)

Retail revenues. The chart below reflects the primary drivers of the 19.7% increase in retail revenues in the third quarter 2005 compared to the same period in the prior year and the 6.7% increase in retail revenues year-to-date compared to the corresponding period in 2004. Energy cost recovery revenues and revenues associated with the recovery of costs associated with PPAs certificated by the Alabama PSC (Rate CNP-PPA) generally do not affect net income. Excluding these revenues, retail revenues increased by $76.6 million, or 11.3%, for the third quarter 2005 and $82.5 million, or 4.7%, year-to-date 2005 when compared to the corresponding periods in 2004. These increases were primarily due to a 6.9% increase and a 2.2% increase in kilowatt-hour energy sales for corresponding periods, as well as the retail rate increase implemented in January 2005 to recover environmental costs. See FUTURE EARNINGS POTENTIAL — “FERC and Alabama PSC Matters — Environmental Rate Filing” for additional information on this rate increase. Kilowatt-hour energy sales to residential and commercial customers increased 13.7% and 7.4%, respectively, for the third quarter 2005 and increased 2.9% and 2.1%, respectively, year-to-date 2005 when compared to the corresponding periods of 2004 primarily due to favorable weather conditions in 2005. Kilowatt-hour energy sales to industrial customers increased 0.4% for the third quarter 2005 and increased 1.8% year-to-date 2005 when compared to the corresponding periods of 2004 primarily from increased sales demand in the pulp and paper and the automotive sectors.

Details of retail revenues are as follows:



	Third Quarter					Year-to-Date
	2005					2005

	(in millions)		% change			(in millions)		% change
Retail — prior quarter/year	$	980				$	2,572
Change in —
Base rates		14		1.5			28		1.1
Sales growth		30		3.1			51		2.0
Weather		32		3.3			3		0.1
Energy cost recovery		110		11.2			82		3.2
Rate CNP-PPA cost recovery		6		0.6			9		0.3

Retail — current quarter/year	$	1,172		19.7	%	$	2,745		6.7	%

Sales for resale — non-affiliates. Energy sales to 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

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

system generation. In the third quarter 2005, revenues from sales for resale to non-affiliates increased $31.9 million when compared to the same period in 2004 primarily due to a 15.8% increase in price and a 6.9% increase in kilowatt-hour sales to non-affiliates. Year-to-date 2005, revenues from sales for resale to non-affiliates increased $44.4 million primarily due to a 7.0% increase in price and a 4.8% increase in kilowatt-hour sales. The 2005 price increases are generally the result of increased fuel costs. These transactions did not have a significant impact on earnings since energy is usually sold at variable cost.

Sales for resale — affiliates. Energy sales to affiliated companies within the Southern Company system vary from period to period depending on demand and the availability and cost of generating resources at each company. These sales are made in accordance with the IIC, as approved by the FERC. In the third quarter 2005, revenues from sales for resale to affiliates decreased $22.2 million when compared to the same period in 2004 primarily due to a 33.2% decrease in kilowatt-hour sales to affiliates as a result of a decrease in the availability of Alabama Power’s generating resources for sales to affiliates due to warmer weather in Alabama Power’s service territory. Year-to-date 2005, revenues from sales for resale to affiliates increased $13.3 million due to a 14.0% price increase related to the recovery of increased fuel-related expenses. These transactions did not have a significant impact on earnings since this energy is generally sold at marginal cost.

Other revenues. The increase in other revenues for the third quarter 2005 when compared to the corresponding period in 2004 is primarily attributed to a $5.4 million increase in revenues from cogeneration steam facilities due to increased fuel revenue resulting from higher natural gas prices (since cogeneration steam fuel revenues are generally offset by fuel expense, these revenues do not have a significant impact on earnings), a $1.4 million increase in transmission revenue, and a $0.9 million increase in rent from electric property. The year-to-date 2005 increase in other revenues when compared to the same period in 2004 is mainly due to a $6.2 million increase in revenues from cogeneration steam facilities due to increased fuel revenue resulting from higher natural gas prices, a $5.8 million increase in transmission revenues, a $1.8 million increase in rent from electric property, and a $2.2 million increase in miscellaneous electric revenues due to early termination of customer electric service contracts.

Fuel expense. Fuel expense was higher in the third quarter 2005 when compared to the corresponding period in 2004 due to a 21.1% increase in the average cost of coal and a 3.6% increase in generation from Alabama Power’s coal-fired facilities. The increase in generation from coal-fired facilities for third quarter 2005 is chiefly due to a 26.9% decrease in generation in Alabama Power’s gas-fired generation facilities because of an 80.7% increase in natural gas prices. The year-to-date 2005 increase in fuel expense when compared to the same period in 2004 is mainly due to a 19.6% increase in the average cost of coal and a 4.9% increase in generation from coal-fired facilities. The increase in generation from coal-fired facilities for year-to-date 2005 is mainly due to a 22.5% decrease in generation from gas-fired generating facilities because of a 39.8% increase in natural gas prices. Since energy expenses are generally offset by energy revenues, these expenses do not have a significant impact on earnings.

Purchased power — non-affiliates. Purchased power from non-affiliates will vary depending on market cost of available energy being lower than Southern Company system generated energy, demand for energy within the service territory, and availability of Southern Company system generation. In the third quarter 2005, purchased power from non-affiliates increased when compared to the same period in 2004 primarily due to a 47.5% increase in the amount of energy purchased resulting mainly from increased demand for energy in Alabama Power’s service territory. Year-to-date 2005, purchased power from non-affiliates decreased $5.6 million when compared to the same period in 2004 mainly due to a 9.9% decrease in energy purchased as a result of a 7.0% increase in self generation. These transactions did not have a significant impact on earnings

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

since energy purchases are generally offset by energy revenues through Alabama Power’s energy cost recovery clause.

Purchased power — affiliates. Purchased power from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC, as approved by the FERC. Purchased power from affiliates increased in the third quarter 2005 compared to the same period in 2004 due to a 35.1% increase in the amount of energy purchased as a result of increased demand in Alabama Power’s service territory and a 30.4% increase in price primarily due to an increase in fuel costs. Year-to-date 2005, purchased power from affiliates increased $28.5 million when compared to the same period in 2004 due primarily to a 26.2% increase in purchased power prices offset by a 7.6% decrease in energy purchased and a 7.0% increase in self generation. These transactions did not have a significant impact on earnings since energy purchases are generally offset by energy revenues through Alabama Power’s energy cost recovery clause.

Other operations and maintenance expense. The increases in other operations expense for the third quarter and year-to-date 2005 when compared to the same periods in 2004 are primarily attributed to an $18.2 million increase in administrative and general expenses related to employee salary and benefits, a $5.1 million increase in customer accounts expense related to customer accounting payroll and uncollectible accounts, and a $4.7 million increase in the accrued expenses for liability insurance, litigation, and workers’ compensation reserve. The increases in maintenance expense for the third quarter and year-to-date 2005 are principally attributed to a $5.4 million increase in transmission expense and a $24.6 million increase in distribution expense. These increases are mainly a result of the Alabama PSC accounting order to offset the costs of the damage from Hurricane Ivan in September 2004 and to restore a balance in the natural disaster reserve. See Notes 1 and 3 to the financial statements of Alabama Power under “Natural Disaster Reserve” and “Natural Disaster Cost Recovery,” respectively, in Item 8 of the Form 10-K for additional information. Also, see “Income taxes” below for additional offsetting impacts of the Alabama PSC’s order.

Income taxes. Year-to-date 2005, in accordance with the Alabama PSC accounting order described above, Alabama Power returned $27.7 million of regulatory liabilities related to deferred income taxes to its retail customers. The remainder of the decrease in income tax expense primarily reflects the $17.3 million tax effect of the additional maintenance expenses recorded under the accounting order and is offset by the increase in 2005 earnings over 2004. For additional information, see “Other operations and maintenance expense” above and Note 3 to the financial statements of Alabama Power under “Natural Disaster Cost Recovery” in Item 8 of the Form 10-K. The impact of this accounting order is expected to reduce Alabama Power’s annual effective income tax rate to approximately 35% for 2005. See Note 5 to the financial statements of Alabama Power in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.

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 business of selling electricity. These factors include Alabama Power’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Future earnings in the near term will depend, in part, upon growth in 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 in Alabama Power’s service area. For additional information relating to these

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

issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 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 regulations could affect earnings if such costs cannot be fully recovered in rates on a timely basis. For additional information, including information on certain environmental litigation, 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.

New Source Review Actions

On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued its decision in favor of Alabama Power on two primary legal issues in the case: (1) the scope of the routine maintenance repair and replacement exclusion under the New Source Review (NSR) rules and (2) the proper test for calculating emissions increases under those rules. The court decided that routine maintenance repair and replacement must be defined with reference to what is routine in the industry as opposed to what is routine at an individual unit and emissions increases must be measured against the maximum hourly emission rate. The decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations involving Plant Miller Units 3 and 4. In separate orders, the court dismissed Alabama Power’s motion for summary judgment on the Plant Miller claims, stayed the entire case, and referred the parties to mediation. Alabama Power may refile its motion for summary judgment if the mediation proves unsuccessful. At the request of the mediator, the original deadline for completing the mediation has been extended from September 9, 2005 to November 30, 2005. The ultimate outcome of this matter cannot now be determined. 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 “New Source Review Actions” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under “New Source Review Actions” for additional information.

Carbon Dioxide Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation” of Alabama Power in Item 7 of the Form 10-K for information on a complaint filed by attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City in July 2004 against Southern Company and four other electric power companies alleging that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. A nearly identical complaint

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

was filed by three environmental groups in the same court. In September 2005, the U.S. District Court for the Southern District of New York dismissed these cases. The plaintiffs filed an appeal on October 19, 2005. The ultimate outcome of this matter cannot be determined at this time.

Other Environmental Matters

The EPA issued the final Clean Air Interstate Rule on March 10, 2005. The rule addresses sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions that contribute to nonattainment of the eight-hour ozone and fine particulate matter National Ambient Air Quality Standards. Twenty-eight eastern states, including the State of Alabama, are subject to the fine particulate matter and/or the eight-hour ozone requirements set forth within the rule. The rule may require additional reductions of NO_x and/or SO₂ to be achieved by the installation of additional controls at Alabama Power’s coal-fired facilities or through the purchase of allowances.

On September 8, 2005, the EPA proposed a rule for the implementation of the fine particulate matter air quality standard. Several areas within Alabama Power’s service area were previously designated by the EPA as “nonattainment” for the standard. The EPA plans to finalize the proposed implementation rule in 2006.

The impact of these rules on Alabama Power will depend on the outcome of legal challenges and development and implementation of applicable state regulations and therefore cannot be determined at this time.

FERC and Alabama PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Alabama PSC Matters — Market-Based Rate Authority” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “Market-Based Rate Authority” in Item 8 of the Form 10-K for information on the FERC’s April 2004 order adopting a new interim analysis for measuring generation market power and a proceeding initiated by the FERC in December 2004 to assess Southern Company’s generation dominance within its retail service territory. Alabama Power has authorization from the FERC to sell power to non-affiliates at market-based prices. Alabama Power, through SCS as agent, also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. On February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. A hearing before an administrative law judge to review the February filing is scheduled for March 2006. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event that the FERC’s default mitigation measures are ultimately applied, Alabama Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The impact of such sales through September 30, 2005 is not material to Alabama Power’s net income. The final outcome of this matter will

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

depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

In addition, in May 2005, the FERC started an investigation to determine whether Southern Company satisfies the other three parts of the FERC’s market-based rate analysis: transmission market power, barriers to entry, and affiliate abuse or reciprocal dealing. The FERC established a new refund period related to this expanded investigation. Any and all new market-based rate transactions involving any Southern Company subsidiary will be subject to refund to the extent the FERC orders lower rates as a result of this new investigation, with the refund period beginning July 19, 2005. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below. The impact of such sales through September 30, 2005 is not material to Alabama Power’s net income.

Intercompany Interchange Contract

Also, in May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a previous proceeding involving Southern Power, Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. The hearing is scheduled for June 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.

Generation Interconnection Agreements

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Alabama PSC Matters — Generation Interconnection Agreements” of Alabama Power in Item 7 of the Form 10-K for information on the FERC’s Order 2003 related to standardization of generation interconnection agreements and procedures. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with Alabama Power, have filed complaints at the FERC requesting that the FERC modify the agreements and that Alabama Power refund a total of $11 million previously paid for interconnection facilities, with interest. Alabama Power has also received similar requests from other entities totaling $7 million. Alabama Power has opposed such relief, and the proceedings are still

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

pending. The impact of Order 2003 and its subsequent rehearings on Alabama Power and the final results of these matters cannot be determined at this time.

Environmental Rate Filing

On October 5, 2004, the Alabama PSC approved a specific rate mechanism for the recovery of Alabama Power’s retail costs associated with environmental laws, regulations, or other such mandates. The rate mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a factor that will be calculated annually. Environmental costs to be recovered include operation and maintenance
expenses, depreciation, and a return on invested capital. Retail rates increased 1% in January 2005, which should yield an annual recovery of approximately $33 million, and are expected to increase approximately 1% in 2006. In conjunction with the Alabama PSC’s approval, Alabama Power agreed to a moratorium until 2007 on any retail rate increase under its previously approved Rate Stabilization and Equalization Plan (Rate RSE). See “Rate RSE” below for further information.

Rate RSE

See Note 3 to the financial statements of Alabama Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for information on Alabama Power’s Rate RSE. On October 4, 2005, the Alabama PSC approved a revision to Rate RSE requested by Alabama Power. Rate RSE adjustments can be made effective January 2007 and annually thereafter and will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. The range of return on common equity, on which such adjustments are based, remains unchanged. If Alabama Power’s actual retail return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return on common equity fall below the allowed equity return range. Alabama Power will make its initial submission of projected data for calendar year 2007 by December 1, 2006.

Hydro Relicensing

On July 28, 2005, Alabama Power filed two applications with the FERC for a new 50-year license for Alabama Power’s seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and a new 50-year license for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine projects expire in 2007. Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain requirements that could result in additional costs to Alabama Power. The final outcome of this matter cannot be determined at this time. See Note (I) to the Condensed Financial Statements herein for additional information.

Nuclear Relicensing

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Alabama PSC Matters — Nuclear Relicensing” of Alabama Power in Item 7 and Note 1 to the financial statements of Alabama Power under “Nuclear Decommissioning” in Item 8 of the Form 10-K for information on Alabama Power’s application to extend the operating license for Plant Farley for an additional 20 years and Alabama Power’s nuclear decommissioning trust funds (NDT). In May 2005, the NRC approved the license extension. Consequently, amounts previously contributed to the NDT are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved a request by Alabama Power to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million

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

in decommissioning costs and to suspend also the associated obligation to make semi-annual contributions to the NDT. Should projections of balances in the external trusts prove to be inadequate to meet future estimates for decommissioning costs, Alabama Power would seek Alabama PSC approval to address that issue in a manner consistent with NRC and other applicable requirements. See Note (I) to the Condensed Financial Statements herein for additional information.

Retail Fuel Cost Recovery

On October 19, 2005, Alabama Power filed with the Alabama PSC for a fuel cost recovery increase under the provisions of its energy cost recovery rate (Rate ECR). An approval of this filing would result in an increase of the energy billing factor for retail customers from 1.788 cents per kilowatt-hour to 2.650 cents per kilowatt-hour and would become effective December 3, 2005. This change to the billing factor represents on average an increase of approximately $8.62 per month for a customer billing of 1,000 kilowatt-hours. Rate ECR revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this increase in the billing factor will have no significant effect on Alabama Power’s revenues or net income, but will increase annual cash flow. The requested increase is intended to allow for the recovery of energy costs based on an estimate of future energy costs, as well as the collection of the existing under recovered energy costs by the end of 2006. Alabama Power’s under recovered retail energy costs as of September 30, 2005 totaled $182.4 million. Under the terms of Rate ECR, the increase will be effective 45 days after the filing unless modified by the Alabama PSC following a public hearing. The final outcome of this filing cannot be determined at this time. See Note (I) to the Condensed Financial Statements herein for additional information.

Natural Disaster Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Alabama PSC Matters — Natural Disaster Cost Recovery” of Alabama Power in Item 7 and Notes 1 and 3 to the financial statements of Alabama Power under “Natural Disaster Reserve” and “Natural Disaster Cost Recovery,” respectively, in Item 8 of the Form 10-K. Alabama Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property.

On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, impacted the coast of Alabama and continued north through the state of Alabama, causing significant damage in parts of the service territory of Alabama Power. Approximately 241,000 and 637,000, respectively, of Alabama Power’s 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina. Alabama Power sustained significant damage to its distribution and transmission facilities during these storms.

In August 2005, Alabama Power received approval from the Alabama PSC to defer the Hurricane Dennis storm-related operation and maintenance costs (estimated at $28 million), which resulted in a negative balance in the natural disaster reserve. In October 2005, Alabama Power also received similar approval from the Alabama PSC to defer the Hurricane Katrina storm-related operation and maintenance costs (estimated at $45 million). See Note (I) to the Condensed Financial Statements herein for further information concerning the Alabama PSC’s approval of deferring the costs of the storms. Alabama Power’s current annual accrual to the natural disaster reserve, as approved by the Alabama PSC, is $3 million, with additional accruals allowed whenever the reserve balance is less than $22.4 million.

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

its depleted natural disaster reserve. This request would provide for a separate rate rider, Rate NDR (Natural Disaster Reserve), based on a monthly charge per customer account. Rate NDR would consist of two components. One part of Rate NDR would be a monthly charge to allow recovery of the previously deferred storm costs, which totaled approximately $69 million as of September 30, 2005, over a two-year period. The second part of Rate NDR would be a monthly charge to replenish the natural disaster reserve’s balance over a five-year period to a newly authorized target of $75 million. As revenue from Rate NDR is recognized, an equal amount of operation and maintenance expense related to the natural disaster reserve will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase the annual cash flow. If approved by the Alabama PSC, Rate NDR would become effective in January, 2006. A final decision from the Alabama PSC is expected in December 2005. The final outcome of the filing cannot be determined at this time.

Other Matters

In July 2005, the U.S. Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush signed into law in August 2005. Among other things, the Energy Act includes various tax subsidies for electric utilities and provisions repealing the PUHCA. The Energy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. The implementation of the Energy Act requires proceedings at the state level and the development of regulations by the FERC, as well as other federal agencies. Alabama Power is still reviewing the legislation. Its impacts will depend on the promulgation and implementation of final rules and cannot be determined at this time.

Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Alabama Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Alabama Power cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Alabama Power’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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

New Accounting Standards

FASB Statement No. 123R, Share-Based Payments, was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity instruments issued. In April 2005, the SEC amended the compliance dates for FASB Statement No. 123R. For Alabama Power, this statement is now effective beginning January 1, 2006. Although the compensation expense calculation required under the revised statement differs slightly, the impacts on Alabama Power’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements of Alabama Power under “Stock Options” in Item 8 of the Form 10-K and in Note (C) to the Condensed Financial Statements herein.

FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations, was issued in March 2005. This interpretation of FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS No. 143), requires that asset retirement obligations be recorded when a legal obligation exists even though the timing and/or the method of settlement are conditional on a future event. As required under FAS No. 143, the present value of the ultimate cost of retiring long-lived assets is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. For Alabama Power, FIN 47 is effective no later than December 31, 2005. Alabama Power currently expects to record additional asset retirement obligations (and plant in service) of less than $47 million, primarily related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. However, Alabama Power has not concluded its assessment of FIN 47 and other potential obligations are still being evaluated. The adoption of FIN 47 is not expected to have any effect on Alabama Power’s income statement.

In December 2004, the FASB issued Staff Position No. 109-1 (FSP 109-1), Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction for utilities be accounted for as a special tax deduction rather than as a tax rate reduction. Alabama Power adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Alabama Power’s financial condition continued to be stable at September 30, 2005. Net cash flows from operating activities totaled $718.2 million for the first nine months of 2005, compared to $745.1 million for the first nine months of 2004. The $26.9 million decrease in the first nine months resulted primarily from higher fuel costs. Those costs are recoverable in future periods and are reflected on the balance sheets as under recovered regulatory clause revenues. Gross property additions to utility plant were $605.7 million in the first nine months of 2005 and are included in the balance sheets herein. The majority of funds needed for gross property additions since 2000 has been provided from operating activities.

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

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

long-term debt, as well as related interest, preferred stock dividends, lease obligations, purchase commitments, and trust funding requirements. See Note (I) to the Condensed Financial Statements herein for information concerning the suspension of the funding of the Nuclear Decommissioning Trust. Approximately $422 million will be required by September 30, 2006 for redemptions and maturities of long-term debt.

Sources of Capital

Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, including funds from operations and new security issuances. The amount, type, and timing of any financings — if needed — will depend upon maintenance of adequate earnings, 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.

To meet short-term cash needs and contingencies, Alabama Power had at September 30, 2005 approximately $146 million of cash and cash equivalents, unused committed lines of credit of approximately $873 million (including $504 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which $0.5 million will expire at various times during the remainder of 2005, and an extendible commercial note program. Alabama Power expects to renew its credit facilities, as needed, prior to expiration. See Note 6 to the financial statements of Alabama Power under “Bank Credit Arrangements” in Item 8 of the Form 10-K for additional information. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of Alabama Power and other Southern Company subsidiaries. Alabama Power has regulatory authority for up to $1.4 billion of short-term borrowings. At September 30, 2005, Alabama Power had no commercial paper or extendible notes payable outstanding. Management believes that the need for working capital can be adequately met by issuing commercial paper or utilizing lines of credit without maintaining large cash balances.

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. However, Alabama Power is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At September 30, 2005, Alabama Power had no material exposure related to these agreements.

Market Price Risk

Alabama Power’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2004 reporting period. In addition, Alabama Power is not aware of any facts or circumstances that would significantly affect such exposures in the near term.

Due to cost-based rate regulations, Alabama Power has 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 fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Alabama Power has also implemented a retail fuel hedging program at the instruction of the Alabama PSC.

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

The fair value of derivative energy contracts at September 30, 2005 was as follows:


	Third Quarter
	2005			Year-to-Date
	Changes			Changes

	Fair Value

	(in thousands)
Contracts beginning of period	$	19,255		$	4,017
Contracts realized or settled		(6,423	)		(17,793	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		44,090			70,698

Contracts at September 30, 2005	$	56,922		$	56,922

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

Source of September 30, 2005
Valuation Prices



	Total			Maturity
	Fair Value			Year 1			1-3 Years

	(in thousands)
Actively quoted	$	57,298		$	52,476		$	4,822
External sources		(376	)		(376	)		—
Models and other methods		—			—			—

Contracts at September 30, 2005	$	56,922		$	52,100		$	4,822

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

Financing Activities

In the first quarter 2005, Alabama Power issued $250 million of Series DD 5.65% Senior Notes due March 15, 2035. The proceeds from the sale were used to repay a portion of Alabama Power’s outstanding short-term indebtedness and for other general corporate purposes, including Alabama Power’s continuing construction activities. Alabama Power settled interest rate swaps related to the transaction at a cost of $21 million, which was recorded in other comprehensive income. This cost will be amortized over a 30-year period.

In the second quarter 2005, Alabama Power entered into two interest rate hedges related to the anticipated issuance of senior notes totaling $600 million. The notes are expected to be issued in 2005 and 2006. Also, in the second quarter 2005, Alabama Power issued 1,000,000 shares of common stock to Southern Company at $40.00 a share ($40 million aggregate purchase price). The proceeds from the sale were used by Alabama Power for general corporate purposes.

Alabama Power did not issue or redeem any long-term securities during the third quarter of 2005. In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	1,888,358		$	1,450,148		$	4,300,681		$	3,687,163
Sales for resale —
Non-affiliates		146,328			58,789			385,180			185,842
Affiliates		130,814			25,778			211,188			128,870
Other revenues		53,562			46,773			151,631			132,164

Total operating revenues		2,219,062			1,581,488			5,048,680			4,134,039

Operating Expenses:
Fuel		624,061			362,347			1,345,377			971,781
Purchased power —
Non-affiliates		200,350			90,591			317,847			250,672
Affiliates		203,350			188,568			564,154			463,029
Other operations		258,837			216,782			684,387			635,974
Maintenance		105,509			106,761			345,734			339,904
Depreciation and amortization		127,834			69,588			375,933			205,867
Taxes other than income taxes		73,070			60,381			192,477			173,301

Total operating expenses		1,593,011			1,095,018			3,825,909			3,040,528

Operating Income		626,051			486,470			1,222,771			1,093,511
Other Income and (Expense):
Allowance for equity funds used during construction		4,424			8,845			21,616			16,892
Interest income		1,028			1,631			1,530			5,751
Interest expense, net of amounts capitalized		(57,959	)		(43,724	)		(163,553	)		(137,667	)
Interest expense to affiliate trusts		(14,878	)		(14,878	)		(44,633	)		(29,688	)
Distributions on mandatorily redeemable preferred securities		—			—			—			(15,839	)
Other income (expense), net		12,096			8,524			12,075			(1,484	)

Total other income and (expense)		(55,289	)		(39,602	)		(172,965	)		(162,035	)

Earnings Before Income Taxes		570,762			446,868			1,049,806			931,476
Income taxes		215,345			159,334			394,139			344,051

Net Income		355,417			287,534			655,667			587,425
Dividends on Preferred Stock		191			168			526			503

Net Income After Dividends on Preferred Stock	$	355,226		$	287,366		$	655,141		$	586,922

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
	(in thousands)						(in thousands)
Net Income After Dividends on Preferred Stock	$	355,226		$	287,366		$	655,141		$	586,922
Other comprehensive income (loss):
Change in fair value of marketable securities, net of tax of $(155) and $(52), respectively		(247	)		—			(83	)		—
Changes in fair value of qualifying hedges, net of tax of $9,085, $(7,780), $3,195 and $(4,070), respectively		14,403			(13,980	)		5,065			(8,098	)
Reclassification adjustment for amounts included in net income, net of tax of $359, $412, $880 and $1,649, respectively		569			654			1,095			2,615

COMPREHENSIVE INCOME	$	369,951		$	274,040		$	661,218		$	581,439

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

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Nine Months
	Ended September 30,
	2005			2004
	(in thousands)
Operating Activities:
Net income	$	655,667		$	587,425
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization		446,677			269,916
Deferred income taxes and investment tax credits		178,421			199,113
Deferred expenses — affiliates		(18,682	)		(30,549	)
Allowance for equity funds used during construction		(21,616	)		(16,892	)
Pension, postretirement, and other employee benefits		9,582			(675	)
Tax benefit of stock options		14,953			7,203
Other, net		(48,651	)		(36,182	)
Changes in certain current assets and liabilities —
Receivables, net		(597,901	)		(231,421	)
Fossil fuel stock		23,489			3,018
Materials and supplies		(29,539	)		(5,696	)
Other current assets		6,709			19,064
Accounts payable		45,625			65,072
Accrued taxes		167,274			48,855
Accrued compensation		(20,658	)		(38,448	)
Other current liabilities		24,862			15,467

Net cash provided from operating activities		836,212			855,270

Investing Activities:
Gross property additions		(588,072	)		(516,287	)
Purchase of property from affiliates		—			(339,750	)
Cost of removal net of salvage		(15,564	)		(11,182	)
Change in construction payables, net of joint owner portion		(38,566	)		(36,206	)
Other		28,860			26,111

Net cash used for investing activities		(613,342	)		(877,314	)

Financing Activities:
Increase (decrease) in notes payable, net		12,332			(137,277	)
Proceeds —
Senior notes		375,000			600,000
Pollution control bonds		185,000			—
Mandatorily redeemable preferred securities		—			200,000
Capital contributions from parent company		107,800			226,400
Redemptions —
Senior notes		(300,000	)		(200,000	)
Pollution control redemptions		(185,000	)		—
Mandatorily redeemable preferred securities		—			(200,000	)
Payment of preferred stock dividends		(381	)		(521	)
Payment of common stock dividends		(417,075	)		(424,125	)
Other		(19,462	)		(17,086	)

Net cash provided from (used for) financing activities		(241,786	)		47,391

Net Change in Cash and Cash Equivalents		(18,916	)		25,347
Cash and Cash Equivalents at Beginning of Period		33,497			8,699

Cash and Cash Equivalents at End of Period	$	14,581		$	34,046

Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $8,804 and $5,686 capitalized for 2005 and 2004, respectively)	$	191,233		$	177,167
Income taxes (net of refunds)	$	64,160		$	38,170

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

Significant income statement items appropriate for discussion include the following:


	Increase (Decrease)
	Third Quarter				Year-To-Date
	(in thousands)		%		(in thousands)		%
Retail revenues	$	438,210		30.2	$	613,518		16.6
Sales for resale — non-affiliates		87,539		148.9		199,338		107.3
Sales for resale — affiliates		105,036		N/M		82,318		63.9
Other revenues		6,789		14.5		19,467		14.7
Fuel expense		261,714		72.2		373,596		38.4
Purchased power expense — non-affiliates		109,759		121.2		67,175		26.8
Purchased power expense — affiliates		14,782		7.8		101,125		21.8
Other operations expense		42,055		19.4		48,413		7.6
Depreciation and amortization expense		58,246		83.7		170,066		82.6
Taxes other than income taxes		12,689		21.0		19,176		11.1
Interest expense, net of amounts capitalized		14,235		32.6		25,886		18.8
Other income (expense), net		3,572		41.9		13,559		N/M


		N/M — Not meaningful

Retail revenues. The chart below reflects the primary drivers of the 30.2% and 16.6% increases in retail revenues in the third quarter and year-to-date 2005, respectively, compared to the corresponding periods in 2004. Excluding fuel cost recovery revenues, which generally do not affect net income, retail sales revenue increased by $192.8 million, or 19.3%, and $282.2 million, or 11.3%, in the third quarter and year-to-date 2005, respectively, compared to the same periods in the prior year, primarily due to the retail rate increase effective January 1, 2005 and warmer temperatures in September 2005. See Note 3 to the financial statements of Georgia Power under “Retail Rate Orders” in Item 8 of the Form 10-K for additional information on the rate increase. In the third quarter 2005, kilowatt-hour energy sales to residential and commercial customers were up by 10.4% and 11.3%, respectively. Year-to-date 2005 kilowatt-hour energy sales to residential and commercial customers increased by 1.1% and 5.9%, respectively. These increases are primarily attributed to the warmer temperatures in September 2005. Additionally, the increases in commercial kilowatt-hour energy sales are also attributed to sustained economic strength, customer growth of 2.4%, and a reclassification of customers from industrial to commercial to be consistent with the rate structure approved by the Georgia PSC when compared to the corresponding periods in 2004. During the third quarter and year-to-date 2005, kilowatt-hour energy sales to industrial customers decreased by 4.2% and 4.1%, respectively, primarily as a result of this reclassification of customers.

Details of retail revenues are as follows:


	Third Quarter				Year-to-Date
	2005				2005

	(in millions)		% change		(in millions)		% change
Retail — prior year	$	1,450			$	3,687
Change in —
Base rates		89		6.1		176		4.8
Sales growth		57		3.9		90		2.4
Weather		47		3.3		17		0.4
Fuel cost recovery		245		16.9		331		9.0

Retail — current year	$	1,888		30.2	$	4,301		16.6

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

Sales for resale — non-affiliates. Energy revenues from sales for resale to non-affiliates increased $64.2 million and $142.2 million, respectively, in the third quarter and year-to-date 2005 compared to the same periods in 2004 as a result of a 22.3% and 22.2% increase, respectively, in price and a 152.1% and 94.6% increase, respectively, in kilowatt-hour sales. The 2005 price increases are generally the result of increasing fuel costs. The kilowatt-hour sales increases are primarily a result of new contracts with non-affiliated customers effective in January 2005 which increased the demand for energy. Energy sales do not have a significant impact on earnings since energy is usually sold at variable cost. The capacity component of these transactions increased $18.3 million and $54.9 million in the third quarter and year-to-date 2005, respectively, over the corresponding periods in 2004.

Sales for resale — affiliates and Purchased power expense — affiliates. Energy sales to and purchases from affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. These sales and purchases are made in accordance with the IIC, as approved by the FERC. These transactions did not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Georgia Power’s fuel cost recovery clause. The third quarter 2005 increase in purchased power from affiliates is primarily due to a 61.1% increase in the cost of fuel. Year-to-date 2005, purchased power from affiliates increased when compared to the same period in 2004 by $30.3 million primarily as a result of additional capacity expenses under PPAs with Southern Power that went into effect in June 2004. See Note 7 to the financial statements of Georgia Power under “Purchased Power Commitments” in Item 8 of the Form 10-K for additional information.

Other revenues. In the third quarter and year-to-date 2005, other revenues increased when compared with the corresponding periods in 2004 primarily as a result of $6.0 million and $8.3 million, respectively, of higher transmission revenues, $1.6 million and $4.0 million, respectively, of higher customer fees that went into effect January 2005, and $1.2 million and $4.3 million, respectively, of higher outdoor lighting revenues.

Fuel expense. Fuel expense increased in the third quarter and year-to-date 2005 primarily as a result of an increase in the average cost of fuel per net kilowatt-hour generated of 41.6% and 28.8%, respectively, when compared to the corresponding periods in 2004 due to higher coal and natural gas prices. These expenses do not have a significant impact on earnings since fuel expenses are generally offset by fuel revenues through Georgia Power’s fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL — “FERC and Georgia PSC Matters — Retail Fuel Cost Recovery” and Note (J) to the Condensed Financial Statements herein for additional information.

Purchased power expense — non-affiliates. Purchased power expense — non-affiliates was higher in the third quarter 2005 due to an increase in purchases to meet higher demand and a 157% increase in the cost of fuel and in year-to-date 2005 due to a 52.1% increase in the cost of fuel due to higher natural gas prices. These expenses 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.

Other operations expense. Other operations expense increased in the third quarter and year-to-date 2005 by $49.6 million and $55.9 million, respectively, primarily due to increased employee labor costs and benefits of $27.0 million and $38.7 million, respectively, and litigation expenses of $1.7 million and $2.6 million, respectively. Such increases for both the third quarter and year-to-date 2005 were partially offset by increased billings of approximately $7.5 million to Georgia Power’s affiliates for hurricane assistance when compared to the prior year.

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

Depreciation and amortization expense. Depreciation and amortization expenses in the third quarter and year-to-date 2005 were higher when compared to the corresponding periods in the prior year mainly due to the expiration in 2004 of certain provisions in Georgia Power’s three-year retail rate plan ending December 31, 2004 (2001 Retail Rate Plan). In accordance with the 2001 Retail Rate Plan, Georgia Power amortized an accelerated cost recovery liability as a credit to amortization expense and recognized new Georgia PSC-certified purchased power costs in rates evenly over the three years ended December 31, 2004. This treatment resulted in a credit to amortization expense of $47 million and $140 million, respectively, during the third quarter and year-to-date 2004. See Note 3 to the financial statements of Georgia Power under “Retail Rate Orders” in Item 8 of the Form 10-K for additional information.

Taxes other than income taxes. The increases in taxes other than income taxes for the third quarter and year-to-date 2005 are attributed primarily to higher municipal gross receipts taxes of $9.1 million and $12.9 million, respectively, resulting from increased operating revenues.

Interest expense, net of amounts capitalized. The third quarter and year-to-date 2005 increases in interest expense, net of amounts capitalized mainly result from the issuance of additional senior notes in the first half of 2005, and from higher interest rates on variable rate debt. See FINANCIAL CONDITION AND LIQUIDITY — “Financing Activities” herein for additional information.

Other income (expense), net. The third quarter and year-to-date 2005 increases in other income (expense), net compared to the corresponding periods in 2004 relate primarily to $11.8 million of gas hedge gains in September 2005. See Note 3 to the financial statements of Georgia Power under “Retail Fuel Hedging Program” in Item 8 of the Form 10-K for information on these hedges and the sharing of financial gains with retail customers. Also see FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” herein for information on hedges outstanding as of September 30, 2005.

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 stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Future earnings in the near term will depend, in part, upon growth in 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 in Georgia Power’s service area. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 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 regulations could affect earnings if such costs cannot be fully recovered in rates on a timely basis. For additional information, including information on certain environmental litigation, 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 “New Source Review Actions” in Item 8 of the Form 10-K.

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

New Source Review Actions

On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its new source review (NSR) regulations, which included changes to the regulatory exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. On October 20, 2005, the EPA published a proposed rule clarifying the test for determining when an emissions increase is subject to the NSR requirements. The impact of the proposed rules will depend on adoption of the final rules by the EPA and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Plant Wansley Environmental Litigation

In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted Georgia Power’s petition for review of the U.S. District Court for the Northern District of Georgia’s December 15, 2004 order related to the Plant Wansley environmental litigation. Oral argument is scheduled for early 2006. The ultimate outcome of this matter cannot now be determined. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Plant Wansley Environmental Litigation” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Plant Wansley Environmental Litigation” in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under “Plant Wansley Environmental Litigation” for additional information.

Carbon Dioxide Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation” of Georgia Power in Item 7 of the Form 10-K for information on a complaint filed by attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City in July 2004 against Southern Company and four other electric power companies alleging that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. A nearly identical complaint was filed by three environmental groups in the same court. In September 2005, the U.S. District Court for the Southern District of New York dismissed these cases. The plaintiffs filed an appeal on October 19, 2005. The ultimate outcome of this matter cannot be determined at this time.

Other Environmental Matters

The EPA issued the final Clean Air Interstate Rule on March 10, 2005. The rule addresses sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions that contribute to nonattainment of the eight-hour ozone and fine particulate matter National Ambient Air Quality Standards. Twenty-eight eastern states, including the State of Georgia, are subject to the fine particulate matter and/or the eight-hour ozone requirements set forth within the rule. The rule may require additional reductions of SO₂and/or NO_x to be achieved by the installation of additional controls at Georgia Power’s coal-fired facilities or through the purchase of allowances.

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

On September 8, 2005, the EPA proposed a rule for the implementation of the fine particulate matter air quality standard. Several areas within Georgia Power’s service area were previously designated by the EPA as “nonattainment” for the standard. The EPA plans to finalize the proposed implementation rule in 2006.

The impact of these rules on Georgia Power will depend on the outcome of legal challenges and development and implementation of applicable state regulations and therefore cannot be determined at this time.

FERC and Georgia PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Georgia PSC Matters — Market-Based Rate Authority” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Market-Based Rate Authority” in Item 8 of the Form 10-K for information on the FERC’s April 2004 order adopting a new interim analysis for measuring generation market power and a proceeding initiated by the FERC in December 2004 to assess Southern Company’s generation dominance within its retail service territory. Georgia Power has authorization from the FERC to sell power to non-affiliates at market-based prices. Georgia Power, through SCS as agent, also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. On February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. A hearing before an administrative law judge to review the February filing is scheduled for March 2006. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event that the FERC’s default mitigation measures are ultimately applied, Georgia Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The impact of such sales through September 30, 2005 is not material to Georgia Power’s net income. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

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

proceeding be held in abeyance pending the outcome of the proceeding on the IIC discussed below. The impact of such sales through September 30, 2005 is not material to Georgia Power’s net income.

Intercompany Interchange Contract

Also, in May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. The hearing is scheduled for June 2006. See Note 3 to the financial statements of Georgia Power under “Plant McIntosh Construction Project” in Item 8 of the Form 10-K for further information on the McIntosh PPA proceeding. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.

Generation Interconnection Agreements

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Georgia PSC Matters — Generation Interconnection Agreements” of Georgia Power in Item 7 of the Form 10-K for information on the FERC’s Order 2003 related to standardization of generation interconnection agreements and procedures. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to previously executed interconnection agreements with Georgia Power and another Southern Company subsidiary, have filed complaints at the FERC requesting that the FERC modify the agreements and that Georgia Power refund a total of $7.9 million previously paid for interconnection facilities, with interest. Georgia Power has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on Georgia Power and the final results of these matters cannot be determined at this time.

Retail Fuel Cost Recovery

On May 17, 2005, the Georgia PSC voted to allow Georgia Power to increase customer fuel rates to recover estimated under recovered fuel costs of approximately $508 million as of May 31, 2005 over the period from June 1, 2005 through May 31, 2009, as well as future projected fuel costs based on a June 2005 through May 2006 test period. The new fuel rate became effective June 1, 2005 and represents an average annual increase in

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

customer billings of approximately 9.5%, or approximately $473 million. Based on the order, a portion of the under-recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets on the balance sheet. Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $198.3 million through September 30, 2005. In accordance with the Georgia PSC’s order, such amounts will be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power will be required to file for a temporary fuel rate change. However, Georgia Power has agreed with a Georgia PSC staff recommendation to suspend the temporary fuel rate provision and, instead, will file a request no later than April 2006 to increase its fuel cost recovery rate. 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 increase in the billing factor would have no significant effect on Georgia Power’s revenues or net income, but would increase annual cash flow. See Note 3 to the financial statements of Georgia Power under “Fuel Cost Recovery” in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements herein for additional information.

Other Matters

In July 2005, the U.S. Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush signed into law in August 2005. Among other things, the Energy Act includes various tax subsidies for electric utilities and provisions repealing the PUHCA. The Energy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. The implementation of the Energy Act requires proceedings at the state level and the development of regulations by the FERC, as well as other federal agencies. Georgia Power is reviewing the legislation. Its impacts will depend on the promulgation and implementation of final rules and cannot be determined at this time.

Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Georgia Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Georgia Power cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Georgia Power’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Georgia Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial

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

statements. Also see MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Unbilled Revenues.

New Accounting Standards

FASB Statement No. 123R, Share-Based Payments, was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity instruments issued. In April 2005, the SEC amended the compliance dates for FASB Statement No. 123R. For Georgia Power, this statement is now effective beginning January 1, 2006. Although the compensation expense calculation required under the revised statement differs slightly, the impacts on Georgia Power’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements of Georgia Power under “Stock Options” in Item 8 of the Form 10-K and in Note (C) to the Condensed Financial Statements herein.

FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations, was issued in March 2005. This interpretation of FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS No. 143), requires that asset retirement obligations be recorded when a legal obligation exists even though the timing and/or the method of settlement are conditional on a future event. As required under FAS No. 143, the present value of the ultimate cost of retiring long-lived assets is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. For Georgia Power, FIN 47 is effective no later than December 31, 2005. Georgia Power currently expects to record additional asset retirement obligations (and plant in service) of less than $116 million, primarily related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. However, Georgia Power has not concluded its assessment of FIN 47 and other potential obligations are still being evaluated. The adoption of FIN 47 is not expected to have any effect on Georgia Power’s income statement.

In December 2004, the FASB issued Staff Position No. 109-1 (FSP 109-1), Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction for utilities be accounted for as a special tax deduction rather than as a tax rate reduction. Georgia Power adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Georgia Power’s financial condition remained stable at September 30, 2005. Net cash flow from operating activities totaled $836.2 million for the year-to-date 2005, compared to $855.3 million for the same period in 2004. The decrease of $19.1 million in 2005 is primarily the result of higher fuel costs, which are recoverable in future periods and are reflected in the balance sheets as under recovered regulatory clause revenues. Year-to-date 2005, gross property additions were $588.1 million. These additions were primarily related to the construction of Plant McIntosh Units 10 and 11, transmission and distribution facilities, purchases of nuclear fuel, and purchases of equipment to comply with environmental standards. The majority of funds for these additions and other capital requirements were derived primarily from operating activities and financing activities. See Georgia Power’s Condensed Statements of Cash Flows herein for further details.

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

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of 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, preferred stock dividends, lease obligations, purchase commitments, and trust funding requirements. Approximately $302.7 million will be required by September 30, 2006 for redemptions and maturities of long-term debt.

Sources of Capital

Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, including funds from operations and new security issuances. The amount, type, and timing of any financings, if needed, will depend upon maintenance of adequate earnings, 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.

At September 30, 2005, Georgia Power’s current liabilities exceeded current assets because of the continued use of short-term debt as a funding source to meet cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at September 30, 2005 approximately $14.6 million of cash and cash equivalents and $780 million of unused credit arrangements with banks. Of these facilities, $70.4 million expire in 2006, $350 million expire in 2007, and $360 million expire in 2010. The facilities that expire in 2006 contain provisions allowing two year term loans executable at expiration. Georgia Power expects to renew its credit facilities, as needed, prior to expiration. These unused credit arrangements provide liquidity support to Georgia Power’s obligations with respect to variable rate pollution control bonds and commercial paper. Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At September 30, 2005, Georgia Power had approximately $220.6 million of commercial paper and no extendible commercial notes outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs and lines of credit without maintaining large cash balances.

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- or Baa3 or below. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At September 30, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $8 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $246 million. Georgia Power is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At September 30, 2005, Georgia Power had no material exposure related to these agreements.

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	294,267		$	215,087		$	663,659		$	571,360
Sales for resale —
Non-affiliates		23,321			18,980			62,647			56,938
Affiliates		14,137			24,488			61,180			67,147
Other revenues		12,355			10,831			32,488			30,030

Total operating revenues		344,080			269,386			819,974			725,475

Operating Expenses:
Fuel		118,892			100,649			306,336			269,843
Purchased power —
Non-affiliates		12,342			6,478			22,408			24,635
Affiliates		42,441			18,048			59,282			33,319
Other operations		45,459			31,191			120,376			100,639
Maintenance		13,346			13,612			47,231			46,591
Depreciation and amortization		21,433			20,674			63,515			61,948
Taxes other than income taxes		21,596			19,106			56,873			53,245

Total operating expenses		275,509			209,758			676,021			590,220

Operating Income		68,571			59,628			143,953			135,255
Other Income and (Expense):
Interest income		1,673			277			2,372			564
Interest expense, net of amounts capitalized		(9,033	)		(7,468	)		(26,284	)		(23,500	)
Interest expense to affiliate trusts		(1,148	)		(1,148	)		(3,443	)		(2,295	)
Distributions on mandatorily redeemable preferred securities		—			—			—			(1,113	)
Other income (expense), net		(266	)		(1,481	)		(234	)		(1,841	)

Total other income and (expense)		(8,774	)		(9,820	)		(27,589	)		(28,185	)

Earnings Before Income Taxes		59,797			49,808			116,364			107,070
Income taxes		22,546			17,854			42,901			39,167

Net Income		37,251			31,954			73,463			67,903
Dividends on Preferred Stock		54			54			162			162

Net Income After Dividends on Preferred Stock	$	37,197		$	31,900		$	73,301		$	67,741

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months					For the Nine Months
	Ended September 30,					Ended September 30,
	2005		2004			2005		2004
	(in thousands)					(in thousands)
Net Income After Dividends on Preferred Stock	$	37,197	$	31,900		$	73,301	$	67,741
Other comprehensive income (loss):
Change in fair value of marketable securities, net of tax of $(40) and $—, respectively		—		(63	)		—		—
Reclassification adjustment for amounts included in net income, net of tax of $31, $32, $94 and $94, respectively		51		50			151		151

COMPREHENSIVE INCOME	$	37,248	$	31,887		$	73,452	$	67,892

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

GULF POWER COMPANY

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

THIRD QUARTER 2005 vs. THIRD QUARTER 2004
AND
YEAR-TO-DATE 2005 vs. YEAR-TO-DATE 2004

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast. Prices for electricity provided by Gulf Power to retail customers are set by the Florida PSC. Many factors affect the opportunities, challenges, and risks of Gulf Power’s business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Hurricanes Dennis and Katrina hit Gulf Power’s service territory in July and August 2005, respectively. As a result of these storms, as well as Hurricane Ivan in September 2004, Gulf Power has incurred significant restoration costs. In addition, fuel costs have risen significantly during 2005. Gulf Power will continue to work with the Florida PSC to enable the timely recovery of these costs.

Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate, and return on equity. 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

Earnings

Gulf Power’s net income after dividends on preferred stock for the third quarter and year-to-date 2005 was $37.2 million and $73.3 million, respectively, compared to $31.9 million and $67.7 million, respectively, for the corresponding periods in 2004. Earnings in the third quarter and year-to-date 2005 increased by $5.3 million, or 16.6%, and $5.6 million, or 8.2%, respectively, primarily due to higher operating revenues when compared to the same period in 2004.

Significant income statement items appropriate for discussion include the following:


	Increase (Decrease)
	Third Quarter						Year-To-Date
	(in thousands)			% change			(in thousands)			% change
Retail revenues	$	79,180			36.8		$	92,299			16.2
Sales for resale — non-affiliates		4,341			22.9			5,709			10.0
Sales for resale — affiliates		(10,351	)		(42.3	)		(5,967	)		(8.9	)
Other revenues		1,524			14.1			2,458			8.2
Fuel expense		18,243			18.1			36,493			13.5
Purchased power expense — non-affiliates		5,864			90.5			(2,227	)		(9.0	)
Purchased power expense — affiliates		24,393			135.2			25,963			77.9
Other operations expense		14,268			45.7			19,737			19.6
Income tax expense		4,692			26.3			3,734			9.5

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

Retail revenues. The chart below reflects the primary drivers of the 36.8% increase in retail revenues in the third quarter and 16.2% increase year-to-date 2005 when compared to the corresponding periods in the prior year. Excluding revenues related to fuel and other cost recovery, which do not affect net income, retail revenues increased by $14.7 million, or 6.9%, for the third quarter 2005 and increased by $10.4 million, or 1.8%, year-to-date 2005 as compared to the corresponding periods in 2004. Retail energy sales to residential, commercial, and industrial customers increased by 15.9%, 7.3%, and 6.4%, respectively, in the third quarter 2005 as compared to the same period in 2004 primarily due to an increase in the number of customers and more favorable weather. Retail energy sales for year-to-date 2005 from residential, commercial, and industrial customers remained mostly constant as compared to the same period in 2004. Other cost recovery for the third quarter and year-to-date 2005 includes approximately $7.9 million and $14.3 million, respectively, of revenues related to the recovery of expenses for Hurricane Ivan as approved by the Florida PSC. See Note (K) to the Condensed Financial Statements herein and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information on storm cost recovery related to Hurricane Ivan.

Details of retail revenues are as follows:


	Third Quarter					Year-to-Date
	2005					2005
	(in thousands)		%			(in thousands)			%

Retail — prior year	$	215,087				$	571,360
Change in —
Sales growth		8,508		4.0			11,905			2.1
Weather		6,227		2.9			(1,528	)		(0.3	)
Fuel cost recovery		48,355		22.4			54,063			9.5
Other cost recovery		16,090		7.5			27,859			4.9

Retail — current year	$	294,267		36.8	%	$	663,659			16.2	%

Sales for resale — affiliates and Purchased power expense — affiliates. Revenues from sales for resale to affiliates and purchases of energy 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 and purchases are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Gulf Power’s fuel cost recovery mechanism. The decreases in sales for resale to affiliates and increases in purchased power from affiliates in the third quarter and year-to-date 2005 are primarily a result of higher sales demand in Gulf Power’s retail service territory as described under “Retail revenues” above.

Other revenues. In the third quarter and year-to-date 2005, other revenues were higher primarily due to an increase in franchise fees, which have no impact on earnings. Franchise fees are generally proportional to sales revenue and are also offset by operating expenses.

Fuel expense. In the third quarter and year-to-date 2005, fuel expense was higher than the same period in 2004 primarily due to a 13.0% increase in coal prices and a 32.9% increase in natural gas prices year-to-date. Since energy expenses are generally offset by energy revenues through Gulf Power’s fuel cost recovery mechanism, these expenses do not have a material impact on net income. See FUTURE EARNINGS POTENTIAL — “FERC and Florida PSC Matters — Retail Fuel Cost Recovery” herein for additional information.

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

Sales for resale — non-affiliates and Purchased power expense — non-affiliates. The increases for the third quarter and year-to-date 2005 sales for resale to non-affiliates are primarily the result of higher natural gas prices that made energy from Southern Company generation resources more attractive for non-affiliated customers. Purchased power expense from non-affiliates increased during the third quarter 2005 due to higher sales demand in Gulf Power’s retail service territory as described under “Retail revenues” above in September that coincided with planned system maintenance activities. The decrease in year-to-date 2005 purchased power expense from non-affiliates, when compared to the corresponding period in 2004, is primarily the result of an increase in available Southern Company system generation. Since energy expenses are generally offset by revenues through Gulf Power’s fuel cost recovery mechanism, these expenses do not have a significant impact on net income.

Other operations expense. The increases in other operations expense during the third quarter and year-to-date 2005, as compared to the same periods in 2004, are primarily due to the recovery of Hurricane Ivan restoration costs as approved by the Florida PSC. Since these costs are recognized as revenues are collected, there is no impact on net income. See Note (K) to the Condensed Financial Statements herein and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information. An additional factor was increases of $3.0 million and $3.9 million, during the third quarter and year-to-date 2005, respectively, in employee benefit costs.

Income tax expense. The increases in income tax expense during the third quarter and year-to-date 2005 are primarily due to the increase in taxable income when compared to the same periods in 2004.

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 stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Future earnings in the near term will depend, in part, upon growth in 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 in Gulf Power’s service area. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 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 regulations could affect earnings if such costs cannot be fully recovered in rates on a timely basis. For additional information, including information on certain environmental litigation, 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 “New Source Review Actions” and “Environmental Remediation” in Item 8 of the Form 10-K.

New Source Review Actions

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

exclusions and methods of calculating emissions increases. However, the court vacated portions of those revisions, including those addressing the exclusion of certain pollution control projects. On October 20, 2005, the EPA published a proposed rule clarifying the test for determining when an emissions increase is subject to the NSR requirements. The impact of the proposed rules will depend on adoption of the final rules by the EPA and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Carbon Dioxide Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation” of Gulf Power in Item 7 of the Form 10-K for information on a complaint filed by attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City in July 2004 against Southern Company and four other electric power companies alleging that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. A nearly identical complaint was filed by three environmental groups in the same court. In September 2005, the U.S. District Court for the Southern District of New York dismissed these cases. The plaintiffs filed an appeal on October 19, 2005. The ultimate outcome of this matter cannot be determined at this time.

Other Environmental Matters

The EPA issued the final Clean Air Interstate Rule on March 10, 2005. The rule addresses sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions that contribute to nonattainment of the eight-hour ozone and fine particulate matter National Ambient Air Quality Standards. Twenty-eight eastern states, including the States of Georgia, Florida, and Mississippi, are subject to the fine particulate matter and/or the eight-hour ozone requirements set forth within the rule. The rule may require additional reductions of NO_x and/or SO₂ to be achieved by the installation of additional controls at Gulf Power’s facilities or through the purchase of allowances.

The impact of these rules on Gulf Power will depend on the outcome of legal challenges and development and implementation of applicable state regulations and therefore cannot be determined at this time.

FERC and Florida PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Florida PSC Matters — Market-Based Rate Authority” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Market-Based Rate Authority” in Item 8 of the Form 10-K for information on the FERC’s April 2004 order adopting a new interim analysis for measuring generation market power and a proceeding initiated by the FERC in December 2004 to assess Southern Company’s

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

generation dominance within its retail service territory. Gulf Power has authorization from the FERC to sell power to non-affiliates at market-based prices. Gulf Power, through SCS as agent, also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. On February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. A hearing before an administrative law judge to review the February filing is scheduled for March 2006. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event that the FERC’s default mitigation measures are ultimately applied, Gulf Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The impact of such sales through September 30, 2005 is not material to Gulf Power’s net income. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Intercompany Interchange Contract

Also in May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over a previous proceeding involving Southern Power, Georgia Power and Savannah Electric be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. The hearing is scheduled for June 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.

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

Generation Interconnection Agreements

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Florida PSC Matters — Generation Interconnection Agreements” of Gulf Power in Item 7 of the Form 10-K for information on the FERC’s Order 2003 related to standardization of generation interconnection agreements and procedures. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection agreements. Subsidiaries of Tenaska, Inc., as counterparties to previously executed interconnection agreements with other Southern Company subsidiaries, have filed complaints at the FERC requesting that the FERC modify the agreements and that the applicable Southern Company subsidiary refund amounts previously paid for interconnection facilities, with interest. Gulf Power has also received similar requests from other entities totaling $6.6 million. Gulf Power has opposed such relief, and the proceedings are still pending. The impact of Order 2003 and its subsequent rehearings on Gulf Power and the final results of these matters cannot be determined at this time.

Storm Damage Cost Recovery

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Florida PSC Matters — Storm Damage Cost Recovery” of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information. Gulf Power maintains an accumulated provision for property damage to cover the cost of damages from major storms and other uninsured damages to its property. Hurricane Ivan hit Gulf Power’s service territory in September 2004. In March 2005, the Florida PSC approved a Stipulation and Settlement (Stipulation) between Gulf Power, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group which allows Gulf Power to recover the retail portion of $51.7 million, the projected reserve deficiency, plus interest and revenue taxes from customers over a 24-month period which began in April 2005. In connection with the Stipulation, Gulf Power has agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

Hurricanes Dennis and Katrina hit the Gulf Coast of Florida in July 2005 and August 2005, respectively, causing damage to the service area of Gulf Power. Hurricane Dennis and Katrina restoration costs were approximately $65 million and $5 million, respectively. As of September 30, 2005, Gulf Power’s accumulated provision for property damage had a deficit balance of approximately $57.7 million, and is included in the balance sheet under “Property Damage” and “Other Regulatory Assets.” The established policy of the Florida PSC, as recently reaffirmed by its decisions following the 2004 hurricane experience of Florida’s investor owned electric utilities, provides for recovery of these costs through the mechanism of the property insurance reserve and, where necessary, through a special recovery surcharge. In 2005, the Florida legislature authorized securitized financing as an additional mechanism available to the Florida PSC and electric utilities in Florida for addressing the extraordinary costs associated with hurricanes. Gulf Power is evaluating this option, along with other alternatives, for recovery of storm-related costs.

Fuel Cost Recovery

Gulf Power has established fuel cost recovery rates approved by the Florida PSC. In recent quarters, Gulf Power has experienced higher than expected fuel costs for coal and gas, which has led to an increase in the under-recovered fuel costs. If the over or under recovery exceeds ten percent of the projected fuel costs for the period, Gulf Power is required to notify the Florida PSC to determine if an adjustment to the fuel cost recovery factor is necessary. Under recovered fuel costs at September 30, 2005 totaled $24.9 million, and are included in “Under recovered regulatory clause revenues” on the balance sheet. Gulf Power’s operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with

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

the currently approved cost recovery rate. Accordingly, changes to the billing factor will have no significant effect on Gulf Power’s revenues or net income, but will change annual cash flow.

Other Matters

On September 15, 2005, Gulf Power’s Board of Directors approved a Plan of Domestication pursuant to Maine law as a first step towards domesticating Gulf Power as a Florida corporation. By domesticating Gulf Power in the same state where it operates as an electric utility subject to state regulation, Gulf Power simplifies certain state and federal regulatory compliance requirements. Gulf Power was formed in 1925 as a Maine corporation and was qualified to do business in Florida as a foreign corporation the following year when it began operations as an electric utility. Gulf Power has maintained its principal place of business in Florida continuously since 1926. The domestication process was effective as of November 2, 2005. Gulf Power is now a Florida corporation. Under the applicable provisions of Florida law, Gulf Power’s legal existence was uninterrupted, with only its state of incorporation changed.

In July 2005, the U.S. Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush signed into law in August 2005. Among other things, the Energy Act includes various tax subsidies for electric utilities and provisions repealing the PUHCA. The Energy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. The implementation of the Energy Act requires proceedings at the state level and the development of regulations by the FERC, as well as other federal agencies. Gulf Power is still reviewing the legislation. Its impacts will depend on the promulgation and implementation of final rules and cannot be determined at this time.

Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Gulf Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Gulf Power cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Gulf Power’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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

New Accounting Standards

FASB Statement No. 123R, Share-Based Payments, was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity instruments issued. In April 2005, the SEC amended the compliance dates for FASB Statement No. 123R. For Gulf Power, this statement is now effective beginning January 1, 2006. Although the compensation expense calculation required under the revised statement differs slightly, the impacts on Gulf Power’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements of Gulf Power under “Stock Options” in Item 8 of the Form 10-K and in Note (C) to the Condensed Financial Statements herein.

FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations, was issued in March 2005. This interpretation of FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS No. 143), requires that asset retirement obligations be recorded when a legal obligation exists even though the timing and/or the method of settlement are conditional on a future event. As required under FAS No. 143, the present value of the ultimate cost of retiring long-lived assets is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. For Gulf Power, FIN 47 is effective no later than December 31, 2005. Gulf Power currently expects to record additional asset retirement obligations (and plant in service) of less than $11 million, primarily related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. However, Gulf Power has not concluded its assessment of FIN 47 and other potential obligations are still being evaluated. The adoption of FIN 47 is not expected to have any effect on Gulf Power’s income statement.

In December 2004, the FASB issued Staff Position No. 109-1 (FSP 109-1), Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction for utilities be accounted for as a special tax deduction rather than as a tax rate reduction. Gulf Power adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Gulf Power’s financial condition remained stable at September 30, 2005. Net cash flow from operating activities totaled $144.5 million for year-to-date 2005, compared to $169.7 million for the corresponding period in 2004. The $25.2 million decrease in 2005 resulted primarily from payments related to storm damage from Hurricanes Ivan, Dennis, and Katrina. Gross property additions to utility plant were $100.1 million for year-to-date 2005. Funds for Gulf Power’s property additions were provided by operating activities and other financing activities. See the Condensed Statements of Cash Flows for additional information.

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, lease obligations, purchase commitments, and trust funding requirements. Approximately $112.1 million will be required by September 30, 2006 for maturities of long-term debt.

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

Sources of Capital

Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past including funds from operations and new security issuances. The amount, type, and timing of any financings, if needed, will depend upon maintenance of adequate earnings, 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. In addition, Gulf Power is also evaluating recent Florida legislation, which authorized securitized financing as an alternative financing source for hurricane-related costs.

At September 30, 2005, Gulf Power’s current liabilities exceeded current assets because of the continued use of short-term debt as a funding source to meet cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Gulf Power has various internal and external sources of liquidity. At September 30, 2005, Gulf Power had approximately $33.3 million of cash and cash equivalents and $60.5 million of unused committed lines of credit with banks, all of which will expire in 2006. Gulf Power expects to renew its credit facilities, as needed, prior to expiration. These credit arrangements provide liquidity support to Gulf Power’s obligations with respect to variable rate pollution control bonds and commercial paper. In addition to the unused committed credit lines, Gulf Power had $20 million borrowed from a revolving line of credit at September 30, 2005. In October 2005, Gulf Power entered into two revolving credit agreements totaling $135.0 million. A portion of these facilities will be used to fund or refinance costs related to Hurricanes Ivan, Dennis, and Katrina, with the remainder used to support Gulf Power’s increased obligations with respect to its commercial paper program which will also be used to fund storm-related costs. In addition, Gulf Power has substantial cash flow from operating activities. Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At September 30, 2005, Gulf Power had no commercial paper and no extendible commercial notes outstanding.

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- or Baa3 or below. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit, or cash. These contracts are for the sale of electric capacity. At September 30, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $5 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $10 million. Gulf Power is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At September 30, 2005, Gulf Power had no exposure related to these agreements.

Market Price Risk

Gulf Power’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2004 reporting period. In addition, Gulf Power is not aware of any facts or circumstances that would significantly affect such exposures in the near term.

Due to cost-based rate regulation, Gulf Power has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity

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

prices, Gulf Power enters into fixed-price contracts for purchase of coal supplies and the purchase and sale of electricity through the wholesale electricity market. Gulf Power has received approval from the Florida PSC to recover prudently incurred costs related to its fuel hedging program through the fuel cost recovery mechanism.

The fair value of derivative energy contracts at September 30, 2005 was as follows:


	Third Quarter
	2005			Year-to-Date
	Changes			Changes
	Fair Value

	(in thousands)
Contracts beginning of period	$	6,653		$	317
Contracts realized or settled		(1,698	)		(4,802	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		19,314			28,754

Contracts at September 30, 2005	$	24,269		$	24,269

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


	Source of September 30, 2005
	Valuation Prices

	Total			Maturity
	Fair Value			Year 1			1-3 Years

				(in thousands)
Actively quoted	$	24,347		$	22,537		$	1,810
External sources		(78	)		(78	)		—
Models and other methods		—			—			—

Contracts at September 30, 2005	$	24,269		$	22,459		$	1,810

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

Financing Activities

In August 2005, Gulf Power issued $60 million of Series L 5.65% Senior Notes due September 1, 2035. A portion of the proceeds from this sale were used for the legal defeasance of $30 million of principal amount of its First Mortgage Bonds, 6 7/8% Series due January 1, 2026. An irrevocable trust agreement was executed by Gulf Power and the trustee for the bondholders under which the bonds will be redeemed in January 2006. Gulf Power has extinguished the liability related to such first mortgage bonds since Gulf Power has been legally released from being the primary obligor. The remainder of the funds from the sale of Senior Notes was used for general corporate purposes.

On September 16, 2005, Gulf Power issued a notice of redemption to the shareholders of its three outstanding preferred stock issues, totaling $4.2 million principal amount. On October 17, 2005, the stockholders were paid the outstanding stated value, accrued dividends and call premium to redeem all

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	176,288		$	167,770		$	474,679		$	448,186
Sales for resale —
Non-affiliates		82,960			72,077			210,272			206,812
Affiliates		14,606			14,481			43,526			34,848
Other revenues		4,053			4,236			13,222			11,231

Total operating revenues		277,907			258,564			741,699			701,077

Operating Expenses:
Fuel		88,961			97,081			270,639			249,971
Purchased power —
Non-affiliates		12,896			6,783			23,525			26,831
Affiliates		43,981			13,966			78,504			54,119
Other operations		40,515			40,261			119,749			114,371
Maintenance		15,619			14,192			52,840			47,408
Depreciation and amortization		8,320			10,051			24,572			30,068
Taxes other than income taxes		15,640			14,486			44,932			41,675

Total operating expenses		225,932			196,820			614,761			564,443

Operating Income		51,975			61,744			126,938			136,634
Other Income and (Expense):
Interest income		120			79			186			241
Interest expense		(2,751	)		(3,064	)		(6,874	)		(8,915	)
Interest expense to affiliate trusts		(649	)		(650	)		(1,948	)		(1,299	)
Distributions on mandatorily redeemable preferred securities		—			—			—			(630	)
Other income (expense), net		(2,371	)		56			(1,725	)		277

Total other income and (expense)		(5,651	)		(3,579	)		(10,361	)		(10,326	)

Earnings Before Income Taxes		46,324			58,165			116,577			126,308
Income taxes		17,647			22,151			44,455			48,118

Net Income		28,677			36,014			72,122			78,190
Dividends on Preferred Stock		433			433			1,299			3,399

Net Income After Dividends on Preferred Stock	$	28,244		$	35,581		$	70,823		$	74,791

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2005			2004			2005			2004
	(in thousands)						(in thousands)

Net Income After Dividends on Preferred Stock	$	28,244		$	35,581		$	70,823		$	74,791
Other comprehensive income (loss):
Change in fair value of marketable securities, net of tax of $(49) and $-, respectively		—			(80	)		—			—
Changes in fair value of qualifying hedges, net of tax of $(1,043), $580, $(1,168) and $(820), respectively		(1,682	)		936			(1,885	)		(1,324	)

COMPREHENSIVE INCOME	$	26,562		$	36,437		$	68,938		$	73,467

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

THIRD QUARTER 2005 vs. THIRD QUARTER 2004
AND
YEAR-TO-DATE 2005 vs. YEAR-TO-DATE 2004

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 stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Hurricane Katrina hit Mississippi Power’s service territory in August 2005. As a result, Mississippi Power has incurred significant restoration costs. In addition, fuel costs have risen significantly during 2005. Mississippi Power will continue to work with the Mississippi PSC to develop methods to enable the timely recovery of these costs.

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, return on equity, and peak season equivalent forced outage rate. 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

Earnings

Mississippi Power’s net income after dividends on preferred stock for the third quarter and year-to-date 2005 was $28.2 million and $70.8 million, respectively, compared to $35.6 million and $74.8 million, respectively, for the corresponding periods of 2004. Earnings in the third quarter and year-to-date 2005 decreased by $7.3 million, or 20.6%, and $4.0 million, or 5.3%, respectively, compared to the same periods of 2004 primarily as a result of lower revenues from base rates due to Hurricane Katrina, which struck Mississippi on August 29, 2005. An increase in year-to-date operations and maintenance expenses was offset by a reduction in depreciation and amortization expense resulting from the credit amortization of the regulatory liability related to additional Plant Daniel Capacity. See FUTURE EARNINGS POTENTIAL – “FERC and Mississippi PSC Matters – Storm Cost Recovery” and Note (L) to the Condensed Financial Statements herein for additional information on the effects of Hurricane Katrina.

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

Significant income statement items appropriate for discussion include the following:


	Increase (Decrease)
	Third Quarter						Year-To-Date
	(in thousands)			%			(in thousands)			%
Retail revenues	$	8,518			5.1		$	26,493			5.9
Sales for resale – non-affiliates		10,883			15.1			3,460			1.7
Sales for resale – affiliates		125			0.9			8,678			24.9
Other revenues		(183	)		(4.3	)		1,991			17.7
Fuel expense		(8,120	)		(8.4	)		20,668			8.3
Purchased power expense – non-affiliates		6,113			90.1			(3,306	)		(12.3	)
Purchased power expense – affiliates		30,015			214.9			24,385			45.1
Other operations expense		254			0.6			5,378			4.7
Maintenance expense		1,427			10.1			5,432			11.5
Depreciation and amortization		(1,731	)		(17.2	)		(5,496	)		(18.3	)
Taxes other than income taxes		1,154			8.0			3,257			7.8
Interest expense		(313	)		(10.2	)		(2,041	)		(22.9	)
Other income (expense), net		(2,427	)		N/M			(2,002	)		N/M
Income taxes		(4,504	)		(20.3	)		(3,663	)		(7.6	)
Dividends on preferred stock		—			—			(2,100	)		(61.8	)


N/M		Not meaningful

Retail revenues. The chart below reflects the primary drivers of the 5.1% increase and 5.9% increase in retail revenues in the third quarter and year-to-date 2005, respectively, compared to the same periods in the prior year. Excluding revenues related to fuel and other cost recovery, which do not affect net income, retail revenues decreased as a result of Hurricane Katrina. Immediately following the storm, all of Mississippi Power’s 195,000 customers were without electrical service. Service was restored to all customers who could receive power by September 10, 2005. At September 30, 2005, approximately 19,200 customers remained unable to receive service. In the third quarter 2005, kilowatt-hour energy sales to residential, commercial, and industrial customers were down 10.3%, 10.2%, and 17.9%, respectively, when compared to the corresponding period in 2004, and year-to-date 2005 kilowatt-hour energy sales to residential, commercial, and industrial customers were down 4.7%, 3.0%, and 5.7%, respectively, when compared to the corresponding period in 2004 due to the outages following Hurricane Katrina. The decrease in year-to-date kilowatt-hour energy sales for industrial customers also reflects an extended maintenance outage at a major industrial customer’s plant during the second quarter 2005. Despite the impacts of Hurricane Katrina, weather in the third quarter of 2005 added to retail revenues due to warmer weather in September 2005 when compared to a very mild third quarter of 2004.

Details of retail revenues are as follows:


	Third Quarter						Year-to-Date
	2005						2005
	(in thousands)			% change			(in thousands)			% change
Retail – prior year	$	167,770					$	448,186
Change in —
Base rates		—			—			—			—
Sales growth and weather		(7,764	)		(4.6	)		(6,001	)		(1.3	)
Fuel cost recovery		15,746			9.4			30,482			6.8
Other cost recovery		536			0.3			2,012			0.4

Retail – current year	$	176,288			5.1	%	$	474,679			5.9	%

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

Sales for resale – non-affiliates and Purchased power expense – non-affiliates. The increases in sales for resale to non-affiliates and purchased power expense from non-affiliates in the third quarter 2005 as compared to the same period in 2004 are primarily the result of higher fuel costs. In addition, Hurricane Katrina’s impact resulted in reduced sales and increased purchases during the third quarter 2005. The increase in sales for resale to non-affiliates for year-to-date 2005 as compared to the same period in 2004 is primarily the result of higher demand by customers within Mississippi Power’s service territory, partially off-set by the impact of Hurricane Katrina, and an increase in fuel costs. The decrease in purchased power expense from non-affiliates year-to-date 2005 as compared to the same period in 2004 is due to fewer sale transactions with wholesale customers outside Mississippi Power’s service territory, which resulted in fewer corresponding purchase transactions. See FUTURE EARNINGS POTENTIAL—“FERC and Mississippi PSC Matters—Storm Damage Cost Recovery” herein for additional information on the impacts of Hurricane Katrina.

Sales for resale – affiliates and Purchased power expense – affiliates. Revenues from sales for resale to affiliates, as well as purchases of energy 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 and purchases 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 and energy purchases are generally offset by energy revenues through Mississippi Power’s retail and wholesale fuel cost recovery clauses. The increases in sales for resale to affiliates and purchased power expense from affiliates in the third quarter and year-to-date 2005 as compared to the same periods in 2004 are primarily the result of an increase in fuel prices. The increase in purchased power from affiliates in the third quarter 2005 is also due to the unavailability of Plant Watson as a result of Hurricane Katrina.

Other revenues. The third quarter 2005 decrease in other revenues when compared to the same period in 2004 is primarily due to the reduction in customer fees and late fees, which Mississippi Power waived during the month of September immediately following Hurricane Katrina. The year-to-date 2005 other revenues when compared to the same period in 2004 also increased by $1.2 million as a result of the buyout of electric service contracts by two of Mississippi Power’s customers.

Fuel expense. The third quarter 2005 decrease in fuel expense when compared to the same period in 2004 is primarily due to $17.7 million in realized gains on derivative energy contracts, which reduce fuel expense, as well as decreases of 15.9% in coal generation, and 29.5% in gas generation, primarily as a result of Hurricane Katrina. The year-to-date 2005 increase in fuel expense when compared to the same period in 2004 is a result of a 27.5% increase in coal expenses, a $15.9 million increase in realized gains on derivative energy contracts and a 25.1% decrease in gas generation, as a result of higher costs. Since energy expenses are generally offset by energy revenues through Mississippi Power’s retail and wholesale fuel cost recovery clauses, these expenses do not have a significant impact on earnings. See FUTURE EARNINGS POTENTIAL – “FERC and Mississippi PSC Matters – Fuel Cost Recovery” herein for additional information.

Other operations expense. The increase in other operations expense for year-to-date 2005 as compared to the same period in 2004 results from an increase of $1.0 million in Plant Daniel lease expenses, $3.7 million in employee benefit costs, and an increase to bad debt reserves of $0.6 million related to Hurricane Katrina.

Maintenance expense. The third quarter 2005 increase in maintenance expense when compared to the same period in 2004 is due to the accrual of certain expenses arising from Hurricane Katrina related to the wholesale portion of Mississippi Power’s business. The year-to-date 2005 increase in maintenance expense when compared to the same period in 2004 is a result of routine scheduled maintenance at Plant Watson and Plant Daniel, along with an increase in overhead line clearing expense in the first part of 2005.

Depreciation and amortization. The third quarter and year-to-date 2005 decreases in depreciation and amortization expense when compared to the same period in 2004 are due to an increase in the amortization of the regulatory liability related to additional Plant Daniel capacity in 2005. An order approved in May 2004 by

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

the Mississippi PSC required $25.1 million to be credited to earnings in 2005. See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information.

Taxes other than income taxes. The increases in taxes other than income taxes for the third quarter and year-to-date 2005 as compared to the same periods in 2004 are the result of higher property taxes due to the increase in property investment and increases in municipal franchise tax due to increases in retail revenues. Since the retail portion of property taxes is recoverable through Mississippi Power’s ad valorem tax adjustment clause, this increase does not have a significant impact on earnings.

Interest expense. The decrease in interest expense for year-to-date 2005 as compared to 2004 is due to a reversal in June 2005, as a result of changes in the legal and regulatory environment of a $2.5 million liability originally recorded for the potential assessment of interest associated with a customer advance.

Other income (expense), net. The third quarter and year-to-date 2005 increases in other expense are the result of an increase in employee-related expenses arising from Hurricane Katrina and customer projects.

Income Taxes. The decreases in income taxes for the third quarter and year-to-date 2005 as compared to the same periods in 2004 are directly related to the reductions in pre-tax income.

Dividends on preferred stock. The decrease in dividends on preferred stock for year-to-date 2005 as compared to the same period in 2004 is a result of a one-time loss in 2004 associated with the redemption of preferred stock.

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 stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Future earnings in the near term will depend, in part, upon growth in 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 in Mississippi Power’s service area. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 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 regulations could affect earnings if such costs cannot be fully recovered in rates on a timely basis. For additional information, including information on certain environmental litigation, 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 in Item 8 of the Form 10-K.

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

New Source Review Actions

Carbon Dioxide Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL – “Environmental Matters – Carbon Dioxide Litigation” of Mississippi Power in Item 7 of the Form 10-K for information on a complaint filed by attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City in July 2004 against Southern Company and four other electric power companies alleging that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. A nearly identical complaint was filed by three environmental groups in the same court. In September 2005, the U.S. District Court for the Southern District of New York dismissed these cases. The plaintiffs filed an appeal on October 19, 2005. The ultimate outcome of this matter cannot be determined at this time.

Other Environmental Matters

The EPA issued the final Clean Air Interstate Rule on March 10, 2005. The rule addresses sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions that contribute to nonattainment of the eight-hour ozone and fine particulate matter National Ambient Air Quality Standards. Twenty-eight eastern states, including the States of Alabama and Mississippi, are subject to the fine particulate matter and/or the eight-hour ozone requirements set forth within the rule. The rule may require additional reductions of NO_x and/or SO₂ to be achieved by the installation of additional controls at Mississippi Power’s facilities or through the purchase of allowances.

The impact of these rules on Mississippi Power will depend on the outcome of legal challenges and development and implementation of applicable state regulations and therefore cannot be determined at this time.

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

FERC and Mississippi PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – “FERC and Mississippi PSC Matters – Market-Based Rate Authority” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “Market-Based Rate Authority” in Item 8 of the Form 10-K for information on the FERC’s April 2004 order adopting a new interim analysis for measuring generation market power and a proceeding initiated by the FERC in December 2004 to assess Southern Company’s generation dominance within its retail service territory. Mississippi Power has authorization from the FERC to sell power to non-affiliates at market-based prices. Mississippi Power, through SCS as agent, also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. On February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. A hearing before an administrative law judge to review the February filing is scheduled for March 2006. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event that the FERC’s default mitigation measures are ultimately applied, Mississippi Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The impact of such sales through September 30, 2005 is not material to Mississippi Power’s net income. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Intercompany Interchange Contract

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

preserved to the extent appropriate. The hearing is scheduled for June 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.

Storm Damage Cost Recovery

See Note 1 to the financial statements of Mississippi Power under “Provision for Property Damage” in Item 8 of the Form 10-K for information on how Mississippi Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. At August 31, 2005, the balance in the accumulated provision for property damage was $5.6 million. Mississippi Power’s current annual accrual to the provision for property damage, as approved by the Mississippi PSC, is $1.5 million to $4.6 million.

Hurricane Katrina hit the coast of Florida, Alabama, Mississippi, and Louisiana on August 29, 2005, causing substantial damage. Mississippi Power sustained significant damage to its distribution and transmission facilities. Mississippi Power’s Plant Watson was also damaged. Plant Watson has six generating units, including three gas-fired units totaling 262 MW, two coal-fired units totaling 750 MW, and a 40 MW gas turbine. One of the coal-fired units at the plant has been returned to service and Mississippi Power currently expects the second coal-fired unit to be returned to service by the end of 2005. The gas units operate primarily to serve summer peak loads. Their condition is currently being evaluated, with repairs expected to be completed before the summer of 2006.

As of September 30, 2005, approximately 19,200 of Mississippi Power’s customers remained unable to receive service. Mississippi Power currently estimates total incremental cost of repairing the damages to its facilities and restoring service to customers will be approximately $245 million to $295 million. It is estimated that approximately $59 million of this cost will be covered through external insurance. The ability of Mississippi Power to obtain future insurance is not expected to be affected. Business and government authorities are still reviewing redevelopment plans for portions of the severely damaged areas along the Mississippi shoreline. Until such plans are complete, Mississippi Power cannot determine the related electric power needs and has excluded these areas from its current cost estimates. The ultimate impact of the redevelopment plans in these areas on Mississippi Power's cost estimates cannot now be determined. Mississippi Power estimates approximately $176 million of the total incremental restoration costs were incurred as of September 30, 2005. These estimates include environmental costs of approximately $10 million associated with Plant Watson and certain distribution facilities.

The Mississippi PSC issued an Interim Accounting Order on October 21, 2005, requiring Mississippi Power to create and recognize a regulatory asset on its books as of September 30, 2005, in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs. The disposition of these costs will be considered as part of an overall consideration of Mississippi Power’s Hurricane Katrina related costs. Mississippi Power is planning to file with the Mississippi PSC later in 2005 to provide a detailed review of Hurricane Katrina restoration costs as required in the Interim Accounting Order and to establish a method to recover such costs.

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

Additionally, the power outages from Hurricane Katrina and related reductions to certain customer loads reduced retail and territorial wholesale sales revenues by approximately $14.7 million for the quarter ended September 30, 2005 and are estimated to reduce revenues by an additional $10 million to $12 million for the quarter ending December 31, 2005. Mississippi Power is evaluating opportunities to mitigate the impact of these reductions in customer loads. Absent such mitigating measures, the impact of these reduced revenues is expected to be material to Mississippi Power’s net income for the year ending December 31, 2005.

Fuel Cost Recovery

Mississippi Power has established a fuel cost recovery factor that is approved by the Mississippi PSC. In recent quarters, Mississippi Power has experienced higher than expected fuel costs for coal and gas, which has led to an increase in the under-recovered fuel costs. Mississippi Power is required to file for an adjustment to the fuel cost recovery factor annually; such filing is expected to occur in November 2005, with the new rate to be effective in January 2006. 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, changes to the billing factor will have no significant effect on Mississippi Power’s revenues or net income, but will change annual cash flow.

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under “Environmental Compliance Overview Plan” in Item 8 of the Form 10-K for additional information on the ECO Plan. Mississippi Power’s ECO Plan annual filing for 2005 was approved by the Mississippi PSC at the conclusion of the ECO Plan hearings on April 5, 2005. An order was issued on July 7, 2005, resulting in a slight increase in rates effective May 2005.

Other Matters

In July 2005, the U.S. Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush signed into law in August 2005. Among other things, the Energy Act includes various tax subsidies for electric utilities and provisions repealing the PUHCA. The Energy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. The implementation of the Energy Act requires proceedings at the state level and the development of regulations by the FERC, as well as other federal agencies. Mississippi Power is still reviewing the legislation. Its impacts will depend on the promulgation and implementation of final rules and cannot be determined at this time.

Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Mississippi Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Mississippi Power cannot be predicted at this time; however, management does not anticipate that the

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

liabilities, if any, arising from such current proceedings would have a material adverse effect on Mississippi Power’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

New Accounting Standards

FASB Statement No. 123R, Share-Based Payments, was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity instruments issued. In April 2005, the SEC amended the compliance dates for FASB Statement No. 123R. For Mississippi Power, this statement is now effective beginning January 1, 2006. Although the compensation expense calculation required under the revised statement differs slightly, the impacts on Mississippi Power’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements of Mississippi Power under “Stock Options” in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements herein.

FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations, was issued in March 2005. This interpretation of FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS No. 143), requires that asset retirement obligations be recorded when a legal obligation exists even though the timing and/or the method of settlement are conditional on a future event. As required under FAS No. 143, the present value of the ultimate cost of retiring long-lived assets is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset’s useful life. For Mississippi Power, FIN 47 is effective no later than December 31, 2005. Mississippi Power currently expects to record additional asset retirement obligations (and plant in service) of less than $12 million, primarily related to asbestos removal and disposal of polychlorinated biphenyls in certain transformers. However, Mississippi Power has not concluded its assessment of FIN 47 and other potential obligations are still being evaluated. The adoption of FIN 47 is not expected to have any effect on Mississippi Power’s income statement.

In December 2004, the FASB issued Staff Position No. 109-1 (FSP 109-1), Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction for utilities be accounted for as a special tax deduction rather than as a tax rate reduction. Mississippi Power adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

Mississippi Power’s financial condition remained stable at September 30, 2005. Net cash flow provided from operating activities totaled $84.5 million for year-to-date 2005, compared to net cash flow provided from operating activities of $80.4 million for the same period in 2004. The $4.1 million increase in 2005 resulted primarily from income tax refunds in 2005. To meet the cash requirements associated with Hurricane Katrina restoration, Mississippi Power has secured a $225 million 3-year credit agreement to cover the cash requirements until permanent financing is secured.

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, and trust funding requirements. Mississippi Power has no maturities or redemptions of long-term debt required by September 30, 2006.

Sources of Capital

In addition to the financing activities described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past including funds from operations and new security issuances. The amount, type, and timing of any financings, if needed, will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Sources of Capital” of Mississippi Power in Item 7 of the Form 10-K for additional information.

At September 30, 2005, Mississippi Power’s current liabilities exceeded current assets primarily as a result of obligations incurred as a result of Hurricane Katrina, as well as the continued use of short-term debt as a funding source to meet cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Mississippi Power had at September 30, 2005 approximately $3.9 million of cash and cash equivalents and $100.5 million of unused committed credit arrangements with banks, $13.0 million of which expire in 2005, and $87.5 million of which expire in 2006. Approximately $38.0 million of these credit arrangements contain provisions allowing two-year term loans executable at expiration and $15 million contain provisions allowing one-year term loans executable at expiration. Mississippi Power expects to renew its credit facilities, as needed, prior to expiration. The credit arrangements provide liquidity support to Mississippi Power’s obligations with respect to variable rate pollution control bonds and commercial paper. On October 20, 2005, Mississippi Power entered into an additional three year, $225 million revolving credit facility to pay for Hurricane Katrina costs until permanent financing is obtained. Currently, $50 million is drawn under the facility, with the remaining $175 million providing liquidity support for Mississippi Power’s obligations with respect to variable rate pollution control bonds and commercial paper. At September 30, 2005, Mississippi Power had $17.8 million in commercial paper and $5.0 million in extendible commercial notes outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs and lines of credit without maintaining large cash balances.

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

Off-Balance Sheet Financing Arrangements

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

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. Mississippi Power is party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At September 30, 2005, Mississippi Power had no exposure related to these agreements.

Market Price Risk

Mississippi Power’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2004 reporting period. However, as a result of storm damage from Hurricane Katrina, Mississippi Power expects to increase its short-term indebtedness in the coming months, which could significantly increase its exposure to interest rate risk. Mississippi Power will manage this increased exposure through a number of means, including interest rate hedges, where appropriate.

Due to cost-based rate regulation, Mississippi Power has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power has also implemented retail fuel hedging programs at the instruction of the Mississippi PSC and wholesale fuel hedging programs under agreements with wholesale customers.

The fair value of derivative, fuel, and energy contracts at September 30, 2005 was as follows:


	Third Quarter
	2005			Year-to-Date
	Changes			Changes
	Fair Value
	(in thousands)
Contracts beginning of period	$	13,983		$	889
Contracts realized or settled		(3,646	)		(9,791	)
New contracts at inception		—			—
Changes in valuation techniques		—			—
Current period changes (a)		19,670			38,909

Contracts at September 30, 2005	$	30,007		$	30,007


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

SAVANNAH ELECTRIC AND POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
				2004						2004
				As Restated						As Restated
	2005			(Note N)			2005			(Note N)
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	143,596		$	104,822		$	319,743		$	259,847
Sales for resale —
Non-affiliates		1,992			966			3,805			3,670
Affiliates		3,513			960			6,828			5,050
Other revenues		1,882			1,141			5,783			2,792

Total operating revenues		150,983			107,889			336,159			271,359

Operating Expenses:
Fuel		39,316			15,381			71,339			39,988
Purchased power —
Non-affiliates		5,007			2,373			9,238			9,102
Affiliates		40,552			35,966			105,614			85,241
Other operations		15,816			15,054			45,752			44,732
Maintenance		4,878			4,932			20,954			18,268
Depreciation and amortization		5,655			5,452			16,531			15,902
Taxes other than income taxes		4,613			4,190			12,310			11,582

Total operating expenses		115,837			83,348			281,738			224,815

Operating Income		35,146			24,541			54,421			46,544
Other Income and (Expense):
Interest income		22			31			57			129
Interest expense, net of amounts capitalized		(3,969	)		(3,023	)		(10,798	)		(9,155	)
Distributions on mandatorily redeemable preferred securities		—			—			—			(109	)
Other income (expense), net		1,649			774			3,802			255

Total other income and (expense)		(2,298	)		(2,218	)		(6,939	)		(8,880	)

Earnings Before Income Taxes		32,848			22,323			47,482			37,664
Income taxes		12,480			8,232			17,016			13,806

Net Income		20,368			14,091			30,466			23,858
Dividends on Preferred Stock		675			675			2,025			825

Net Income After Dividends on Preferred Stock	$	19,693		$	13,416		$	28,441		$	23,033

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months				For the Nine Months
	Ended September 30,				Ended September 30,
			2004				2004
			As Restated				As Restated
	2005		(Note N)		2005		(Note N)
	(in thousands)				(in thousands)
Net Income After Dividends on Preferred Stock	$	19,693	$	13,416	$	28,441	$	23,033
Other comprehensive income (loss):
Changes in fair value of qualifying hedges, net of tax of $411, $8, $194 and $(2), respectively		653		12		308		(3	)
Reclassification adjustment for amounts included in net income, net of tax of $12, $9, $17 and $39, respectively		15		14		24		61

COMPREHENSIVE INCOME	$	20,361	$	13,442	$	28,773	$	23,091

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2005 vs. THIRD QUARTER 2004
AND
YEAR-TO-DATE 2005 vs. YEAR-TO-DATE 2004

OVERVIEW

Savannah Electric operates as a vertically integrated utility providing electricity to retail customers within its traditional service area of southeastern Georgia. Many factors affect the opportunities, challenges, and risks of Savannah Electric’s business of selling electricity. These factors include the ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. In addition, fuel costs have risen significantly during 2005. Savannah Electric will continue to work with the Georgia PSC to enable the timely recovery of these costs.

Savannah Electric continues to focus on several key performance indicators. These indicators include customer satisfaction, peak season equivalent forced outage rate, and return on equity. For additional information on these indicators, see MANAGEMENT’S DISCUSSION AND ANALYSIS — OVERVIEW — “Key Performance Indicators” of Savannah Electric in Item 7 of the Form 10-K.

See Note 9 to the financial statements of Savannah Electric in Item 8 of the Form 10-K and Note (N) to the Condensed Financial Statements herein for information regarding Savannah Electric’s restatement of its financial statements for the third quarter and year-to-date September 30, 2004 as the result of errors in the estimate of unbilled revenues for these periods.

RESULTS OF OPERATIONS

Earnings

Savannah Electric’s net income after dividends on preferred stock for the third quarter and year-to-date 2005 was $19.7 million and $28.4 million, respectively, compared to $13.4 million and $23.0 million, respectively, for the corresponding periods of 2004. The $6.3 million and $5.4 million increases in the third quarter and year-to-date 2005, respectively, over the corresponding periods in 2004 were primarily due to higher revenues resulting from the retail base rate increase effective June 1, 2005, increases in transmission revenues, and gains on the settlement of gas and oil hedges. These increases were partially offset by increases in franchise taxes, interest expense, and a year-to-date increase in maintenance expense. See Note (M) to the Condensed Financial Statements herein for further information on the base rate increase and the energy hedging program.

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Significant income statement items appropriate for discussion include the following:


	Increase (Decrease)
	Third Quarter					Year-to-Date
	(in thousands)			%		(in thousands)		%
Retail revenues	$	38,774			37.0	$	59,896		23.1
Sales for resale — non-affiliates		1,026			106.2		135		3.7
Sales for resale — affiliates		2,553			265.9		1,778		35.2
Other revenues		741			64.9		2,991		107.1
Fuel expense		23,935			155.6		31,351		78.4
Purchased power expense — non-affiliates		2,634			111.0		136		N/M
Purchased power expense — affiliates		4,586			12.8		20,373		23.9
Maintenance expense		(54	)		N/M		2,686		14.7
Taxes other than income taxes		423			10.1		728		6.3
Interest expense, net of amounts capitalized		946			31.3		1,643		17.9
Other income (expense), net		875			113.0		3,547		N/M
Income taxes		4,248			51.6		3,210		23.3
Dividends on preferred stock		—			—		1,200		145.5


N/M		Not meaningful

Retail revenues. The chart below reflects the primary drivers of the 37.0% third quarter and 23.1% year-to-date 2005 increases in retail revenues, compared to the same periods in the prior year. Excluding fuel cost recovery revenues, which do not affect net income, retail revenue increased by $7.5 million, or 12.5%, in the third quarter 2005 and increased by $6.3 million, or 4.3%, year-to-date 2005, when compared to the corresponding periods in 2004. For the third quarter and year-to-date 2005, these revenue increases are primarily related to the base rate increases in all customer classes effective June 2005, as well as an increase in customer growth and favorable weather conditions. See FUTURE EARNINGS POTENTIAL — “FERC and Georgia PSC Matters — Retail Rate Case Filing” in Item 7 of the Form 10-K and Note (M) to the Condensed Financial Statements herein for further information on the base rate increase.

Details of retail revenues are as follows:



	Third Quarter					Year-to-Date

	(in thousands)		% change			(in thousands)		% change
Retail — prior year	$	104,822				$	259,847
Change in —
Base rates		3,034		2.9			4,039		1.6
Sales growth		481		0.5			1,416		0.5
Weather		3,957		3.8			834		0.3
Fuel cost recovery		31,302		29.8			53,607		20.7

Retail — current year	$	143,596		37.0	%	$	319,743		23.1	%

Sales for resale — non-affiliates. In the third quarter and year-to-date 2005, revenues from sales for resale to non-affiliates were higher primarily due to increased fuel costs. As a result, the average price per kilowatt-hour for these sales increased 34% in the third quarter and 61% year-to-date when compared to the same

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periods in the prior year. These transactions had no significant effect on net income, since the energy is generally sold at variable cost.

Sales for resale — affiliates and Purchased power expense — affiliates. Energy sales to and purchases from affiliated companies within the Southern Company system will vary depending on demand, and the availability and cost of generating resources at each company. These sales and purchases are made in accordance with the IIC, as approved by the FERC. Sales to affiliated companies increased for the third quarter and year-to-date 2005 when compared to the corresponding periods in 2004 due to increases in energy costs. Purchased power from affiliates increased in the third quarter and year-to-date 2005 due to an increase in the average cost of fuel. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Savannah Electric’s fuel cost recovery clause.

Other revenues. Other revenues increased in the third quarter and year-to-date 2005 when compared to the corresponding periods in 2004. The increases were primarily due to revenues of $0.4 million for the quarter and $2.4 million year-to-date associated with a transmission facilities agreement with Georgia Power related to the Plant McIntosh combined cycle units. Following FERC approval of the contract, which was received in May 2005, these revenues were recorded retroactive to June 2004. Approximately $0.9 million of the revenues were related to 2004.

Fuel expense. Fuel expense increased in the third quarter and year-to-date 2005 primarily as a result of the Plant McIntosh combined cycle units which were placed in service in June 2005, an adjustment in 2004 as a result of billing credits relating to the Plant McIntosh combustion turbines which reduced 2004 fuel expense, and increases in the average cost of fuel per net kilowatt-hour generated of 73% in the third quarter and 62% year-to-date 2005, offset partially by realized gains on gas and oil hedges, when compared to the same periods in the prior year. Since fuel expenses are generally offset by fuel revenues through Savannah Electric’s fuel cost recovery clause, these expenses do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL — “FERC and Georgia PSC Matters — Fuel Cost Recovery” and Note (M) to the Condensed Financial Statements herein for additional information.

Purchased power expense — non-affiliates. The increases in the amount of purchased power from non-affiliates in the third quarter and year-to-date 2005 when compared to the corresponding periods in 2004 resulted from increases in the average cost per kilowatt-hour purchased of 96% and 52%, respectively. These transactions do not have a significant impact on earnings, as energy costs are generally recovered through Savannah Electric’s fuel cost recovery clause.

Maintenance expense. Maintenance expense increased for the year-to-date 2005 as a result of scheduled maintenance outages at Plant Kraft and Plant McIntosh and a transformer failure in July 2005.

Taxes other than income taxes. In the third quarter and year-to-date 2005, taxes other than income taxes were higher primarily due to increased franchise taxes resulting from the increases in operating revenues.

Interest expense, net of amounts capitalized. Interest expense increases in the third quarter and year-to-date 2005 when compared to the corresponding periods in 2004 were primarily higher due to the issuance in December 2004 of $35 million of senior notes, as well as an increase in short-term borrowings and higher interest rates, and for the third quarter, a decrease in the debt component of AFUDC as a result of the commercial operation of the Plant McIntosh combined cycle project in June 2005.

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

Other income (expense), net. In the third quarter 2005, other income increased as a result of a $1.7 million gain on the settlement of gas and oil hedges, as allowed by the Georgia PSC, offset partially by a $0.8 million decrease in non-taxable AFUDC equity following the commercial operation of the Plant McIntosh combined cycle project in June 2005. Year-to-date 2005, such AFUDC equity increased $0.8 million from 2004. The timing of accruals associated with the cash surrender value on company-owned life insurance policies also contributed approximately $0.6 million to the year-to-date 2005 increase in other income. See Note (M) to the Condensed Financial Statements herein for further information on the gas and oil hedging program.

Income taxes. The increase in income taxes for the third quarter and year-to-date 2005 as compared to the prior year is mainly attributed to higher taxable income, with the year-to-date 2005 amount being partially offset by the increase in non-taxable AFUDC equity mentioned above. As a result, Savannah Electric’s annual effective income tax rate is expected to be approximately 35% for 2005. See Note 5 to the financial statements of Savannah Electric in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.

Dividends on preferred stock. Dividends on preferred stock increased year-to-date 2005 due to the issuance of 1.8 million shares of 6.00% Series Preferred Stock in June 2004.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Savannah Electric’s future earnings potential. The level of Savannah Electric’s future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Savannah Electric’s business of selling electricity. These factors include Savannah Electric’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stringent environmental standards. Future earnings in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in Savannah Electric’s service area. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Savannah Electric in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to the Clean Air Act and other environmental regulations could affect earnings if such costs cannot be recovered. For additional information, including information on certain environmental litigation, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters” of Savannah Electric in Item 7 and Note 3 to the financial statements of Savannah Electric under “New Source Review Actions” in Item 8 of the Form 10-K.

New Source Review Actions

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

and the individual state implementation of such rules, as well as the outcome of any additional legal challenges, and, therefore, cannot be determined at this time.

Carbon Dioxide Litigation

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “Environmental Matters — Carbon Dioxide Litigation” of Savannah Electric in Item 7 of the Form 10-K for information on a complaint filed by attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City in July 2004 against Southern Company and four other electric power companies alleging that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. A nearly identical complaint was filed by three environmental groups in the same court. In September 2005, the U.S. District Court for the Southern District of New York dismissed these cases. The plaintiffs filed an appeal on October 19, 2005. The ultimate outcome of this matter cannot be determined at this time.

Other Environmental Matters

The EPA issued the final Clean Air Interstate Rule on March 10, 2005. The rule addresses sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions that contribute to nonattainment of the eight-hour ozone and fine particulate matter National Ambient Air Quality Standards. Twenty-eight eastern states, including the State of Georgia, are subject to the fine particulate matter and/or the eight-hour ozone requirements set forth within the rule. The rule may require additional reductions of NO_x and/or SO₂ to be achieved by the installation of additional controls at Savannah Electric’s facilities or through the purchase of allowances.

The impact of these rules on Savannah Electric will depend on the outcome of legal challenges and development and implementation of applicable state regulations and therefore cannot be determined at this time.

FERC and Georgia PSC Matters

Market-Based Rate Authority

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Georgia PSC Matters — Market-Based Rate Authority” of Savannah Electric in Item 7 and Note 3 to the financial statements of Savannah Electric under “Market-Based Rate Authority” in Item 8 of the Form 10-K for information on the FERC’s April 2004 order adopting a new interim analysis for measuring generation market power and a proceeding initiated by the FERC in December 2004 to assess Southern Company’s generation dominance within its retail service territory. Savannah Electric has authorization from the FERC to sell power to non-affiliates at market-based prices. Savannah Electric, through SCS as agent, also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. On February 15, 2005, Southern Company submitted additional

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

information related to generation dominance in its retail service territory. A hearing before an administrative law judge to review the February filing is scheduled for March 2006. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event that the FERC’s default mitigation measures are ultimately applied, Savannah Electric may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The impact of such sales through September 30, 2005 is not material to Savannah Electric’s net income. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Intercompany Interchange Contract

Also in May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. The hearing is scheduled for June 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiary will be subject to refund to the extent the FERC orders any changes to the IIC. See Note 3 to the financial statements of Savannah Electric under “Plant McIntosh Construction Project” in Item 8 of the Form 10-K for additional information on the McIntosh PPA proceeding.

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

Retail Rate Case Filing

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC and Georgia PSC Matters — Retail Rate Case Filing” in Item 7 and Note 3 to the financial statements of Savannah Electric under “Retail Regulatory Matters — 2004 Retail Rate Case Filing” in Item 8 of the Form 10-K and Note (M) to the Condensed Financial Statements herein for additional information.

On May 17, 2005, the Georgia PSC approved a new three-year retail rate plan for Savannah Electric ending May 31, 2008 (2005 Plan). Under the terms of the 2005 Plan, earnings will be evaluated against a retail return on common equity range of 9.75% to 11.75%. Two-thirds of any earnings above 11.75% will be applied to rate refunds with the remaining one-third retained by Savannah Electric. Retail base revenues were increased by approximately $9.6 million, or 5.1%, on an annual basis effective in June 2005 to cover the cost of new generation and PPAs, higher operating and maintenance expenses, and continued investment in new transmission and distribution facilities to support growth and ensure reliability. Savannah Electric will not file for a general base rate increase unless its projected retail return on common equity falls below 9.75%. Savannah Electric is required to file a general rate case on November 30, 2007, in response to which the Georgia PSC would be expected to determine whether the rate plan should be continued, modified, or discontinued.

Retail Fuel Cost Recovery

On August 19, 2005, Savannah Electric filed a request with the Georgia PSC for a fuel cost recovery rate increase. The requested increase, representing an annual increase in customer billings of approximately $53.5 million, will allow for the recovery of fuel costs based on an estimate of future fuel costs, as well as the collection of the existing under recovery of fuel costs over a period of up to three years. The Georgia PSC may order that this existing under recovery be collected over a different period. Savannah Electric’s under recovered fuel costs as of September 30, 2005 totaled $59.6 million. Hearings before the Georgia PSC were held in October 2005. A final decision from the Georgia PSC is expected in November 2005, with the new fuel rate effective in December 2005. 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, this increase in the billing factor will have no significant effect on Savannah Electric’s revenues or net income, but will increase annual cash flow. The final outcome of the filing cannot be determined at this time. See Note (M) to the Condensed Financial Statements herein for additional information.

In a separate proceeding on August 2, 2005, the Georgia PSC approved its staff recommendation to initiate an investigation of Savannah Electric’s fuel practices. The final outcome of this matter cannot now be determined.

Other Matters

In July 2005, the U.S. Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush signed into law in August 2005. Among other things, the Energy Act includes various tax subsidies for electric utilities and provisions repealing the PUHCA. The Energy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. The implementation of the Energy Act requires proceedings at the state level and the development of regulations by the FERC, as well as other federal agencies. Savannah Electric is still reviewing the legislation. Its impacts will depend on the promulgation and implementation of final rules and cannot be determined at this time.

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

Effective September 30, 2004, Savannah Electric retired Units 4 and 5 at Plant Riverside. The remaining units at the plant were retired on May 31, 2005. These retirements had no material impact on Savannah Electric’s financial statements.

Savannah Electric is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Savannah Electric’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, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Savannah Electric cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Savannah Electric’s financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Savannah Electric prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Savannah Electric 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 Savannah Electric’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. Also see MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” of Savannah Electric in Item 7 of the Form 10-K for a complete discussion of Savannah Electric’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Unbilled Revenues.

New Accounting Standards

FASB Statement No. 123R, Share-Based Payments, was issued in December 2004. This statement requires that compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the grant date fair value of the equity instruments issued. In April 2005, the SEC amended the compliance dates for FASB Statement No. 123R. For Savannah Electric, this statement is now effective beginning January 1, 2006. Although the compensation expense calculation required under the revised statement differs slightly, the impacts on Savannah Electric’s financial statements are expected to be similar to the pro forma disclosures included in Note 1 to the financial statements of Savannah Electric under “Stock Options” in Item 8 of the Form 10-K and in Note (C) to the Condensed Financial Statements herein.

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over the asset’s useful life. For Savannah Electric, FIN 47 is effective no later than December 31, 2005. Savannah Electric currently expects to record additional asset retirement obligations (and plant in service) of less than $4 million, primarily related to asbestos removal. However, Savannah Electric has not concluded its assessment of FIN 47 and other potential obligations are still being evaluated. The adoption of FIN 47 is not expected to have any effect on Savannah Electric’s income statement.

In December 2004, the FASB issued Staff Position No. 109-1 (FSP 109-1), Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004, which requires that the generation deduction for utilities be accounted for as a special tax deduction rather than as a tax rate reduction. Savannah Electric adopted FSP 109-1 in the first quarter of 2005 with no material impact on its financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Savannah Electric’s financial condition remained stable at September 30, 2005. Net cash flow provided from operating activities totaled $30.6 million for the first nine months of 2005, compared to $36.8 million for the first nine months of 2004. The $6.2 million decrease in 2005 resulted primarily from higher fuel costs. Those costs are recoverable in future periods and are reflected on the balance sheets as under recovered regulatory clause revenues. Major changes in Savannah Electric’s financial condition during the first nine months of 2005 included the addition of approximately $33.8 million to utility plant, which includes the Plant McIntosh combined cycle facility. The funds for these additions and other capital requirements were derived primarily from operations and routine financing activities. See Savannah Electric’s Condensed Statements of Cash Flows herein for further details.

Capital Requirements and Contractual Obligations

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Savannah Electric in Item 7 of the Form 10-K for a description of Savannah Electric’s capital requirements for its construction program, lease obligations, purchase commitments, and trust funding requirements. Approximately $21 million will be required by September 30, 2006 for redemptions and maturities of long-term debt.

Sources of Capital

Savannah Electric plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, including funds from operations and new securities issuances. The amount, type, and timing of any future financings, if needed, will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Sources of Capital” of Savannah Electric in Item 7 of the Form 10-K for additional information.

To meet short-term cash needs and contingencies, Savannah Electric had at September 30, 2005 approximately $1.7 million of cash and cash equivalents and $80 million of unused committed credit arrangements with banks, of which $10 million expire in 2005, $50 million expire in 2006, and $20 million expires in 2008. All of the unused credit arrangements expiring in 2005 and 2006 include two-year term loan options executable at the expiration date. The credit arrangements provide liquidity support to some of Savannah Electric’s obligations with respect to variable rate debt and commercial paper. Savannah Electric

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SOUTHERN POWER COMPANY

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

THIRD QUARTER 2005 vs. THIRD QUARTER 2004
AND
YEAR-TO-DATE 2005 vs. YEAR-TO-DATE 2004

OVERVIEW

Southern Power constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the Super Southeast wholesale market. Southern Power continues to focus on executing its regional strategy in the Super Southeast in 2005. Southern Power continues to address questions at the federal regulatory level relative to market power and affiliate transactions. See FUTURE EARNINGS POTENTIAL — “FERC Matters” herein for additional detail.

To evaluate operating results and to ensure Southern Power’s ability to meet its contractual commitments to customers, Southern Power focuses on two key performance indicators. These indicators consist of plant availability and peak season equivalent forced outage rate (EFOR). Plant availability shows the percentage of time during the year that Southern Power’s generating units are available to be called upon to generate (the higher the better), whereas the EFOR more narrowly defines the hours during peak demand times when Southern Power’s generating units are not available due to forced outages (the lower the better). 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

Earnings

Southern Power’s net income for the third quarter and year-to-date 2005 was $39.2 million and $87.5 million compared to $37.3 million and $86.9 million, respectively, for the corresponding periods of 2004. The increase in third quarter 2005 earnings of $1.9 million, or 5.1%, was primarily the result of the acquisition of Plant Oleander in June 2005 and its operation, partially offset by higher purchased power and fuel expenses. Year-to-date 2005 earnings remained relatively flat as compared to 2004 as a result of the addition of operations at Plant Oleander being offset by the impact of ceasing the capitalization of interest on construction. Capitalization of construction interest ended with the sale of Plant McIntosh Units 10 and 11 to Georgia Power and Savannah Electric in May 2004 and the cessation of construction activities at Plant Franklin Unit 3 in August 2004. For further information, see Note 2 to the financial statements of Southern Power under “Plant Franklin Unit 3 Construction Project” and “Plant McIntosh Construction Project” in Item 8 of the Form 10-K. Also see Note (O) to the Condensed Financial Statements herein for information on the acquisition of Oleander Power Project, L.P. (Oleander) in June 2005.

Significant income statement items appropriate for discussion include the following:


	Increase (Decrease)
	Third Quarter						Year-To-Date
	(in thousands)			%			(in thousands)			%
Sales for resale — non-affiliates	$	26,910			46.1		$	(53,014	)		(24.3	)
Sales for resale — affiliates		51,839			40.5			79,380			24.6
Other revenues		(2,079	)		(86.2	)		(6,003	)		(85.5	)
Fuel expense		46,742			131.8			33,683			30.7
Purchased power expense — non-affiliates		3,914			23.4			(15,870	)		(28.3	)
Purchased power expense — affiliates		16,261			65.8			(17,608	)		(18.4	)
Interest expense, net of amounts capitalized		1,712			9.2			13,982			30.7

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

Sales for resale — affiliates and non-affiliates. Third quarter revenues increased for sales for resale to both non-affiliates and affiliates. Year-to-date 2005 revenues from sales for resale to non-affiliates decreased and sales to affiliates increased when compared to the corresponding periods in 2004. These changes were primarily related to the June 2004 inception of a new PPA with Georgia Power at Plant Harris Unit 2 and a scheduled increase in the existing PPA with Georgia Power at Plant Franklin Unit 2. These units were initially placed into service in June 2003 and available for market sales to non-affiliates until the commencement of the affiliate PPAs. Reductions in operating revenues at Plant Harris Unit 2 and Plant Franklin Unit 2 caused by the shift from market sales of this capacity to sales to affiliates under PPAs in June 2004 were largely offset by reductions in purchased power expense and fuel expense. Additional non-affiliated sales from PPAs at Plant Oleander also contributed to the third quarter 2005 increase. See FUTURE EARNINGS POTENTIAL — “Other Matters” of Southern Power in Item 7 of the Form 10-K and Note (O) to the Condensed Financial Statements herein for additional information on the acquisition of Plant Oleander.

Other revenues. In the third quarter and year-to-date 2005, other revenues decreased when compared to the corresponding quarter and year-to-date 2004, primarily due to the expiration of a contract that included significant transmission components.

Fuel expense. Fuel expense in the third quarter 2005 increased when compared to the same period in 2004 due to a 90% increase in fuel prices when compared to the third quarter 2004. Fuel expense also increased year-to-date 2005 when compared to the same period in 2004 primarily due to a 39% increase in fuel prices. Existing PPAs generally provide that the purchasers are responsible for substantially all of the fuel costs relating to energy delivered under the PPAs; therefore, changes in fuel expenses do not have a significant impact on net income.

Purchased power expense — affiliates and non-affiliates. The increases in purchased power from affiliates and non-affiliates during the third quarter 2005 when compared to the corresponding period of 2004 are primarily due to a 52% increase in the average price of power available from affiliates and a 75% increase in the average price of available market energy. Purchased power decreased year-to-date compared to the corresponding period of 2004 primarily due to the Plant Harris Unit 2 PPA and the commitment of an additional portion of Plant Franklin Unit 2 to Georgia Power beginning in June 2004; prior to that time the capacity from these units was sold into short-term markets and related energy sales were sometimes served with short-term power purchases from both affiliates and non-affiliates when market costs were lower than the cost of self-generation.

Interest expense, net of amounts capitalized. Interest expense, net of amounts capitalized increased in the third quarter and year-to-date 2005 when compared to the same periods in 2004 primarily as the result of ceasing the capitalization of interest on construction. Capitalized interest on construction ended with the sale of Plant McIntosh Units 10 and 11 to Georgia Power and Savannah Electric in May 2004 and the cessation of construction activities at Plant Franklin Unit 3 in August 2004. For further information, see Note 2 to the financial statements of Southern Power under “Plant Franklin Unit 3 Construction Project” and “Plant McIntosh Construction Project” in Item 8 of the Form 10-K. For the third quarter 2005, interest expense also increased due to the additional financing for the purchase of Oleander in June 2005. Year-to-date 2005, these increases were partially offset by lower interest expense related to the repurchase of Southern Power’s higher interest senior notes in December 2004.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power’s future earnings. Several factors affect the opportunities, challenges, and risks of Southern Power’s competitive wholesale

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

energy business. These factors include the ability to achieve sales growth while containing costs. Another major factor is federal regulatory policy, which may impact Southern Power’s level of participation in this market. The level of future earnings depends on numerous factors, especially regulatory matters, including those related to affiliate contracts, sales, creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

FERC Matters

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “FERC Matters — Market-Based Rate Authority” of Southern Power in Item 7 and Note 2 to the financial statements of Southern Power under “FERC Matters — Market-Based Rate Authority” in Item 8 of the Form 10-K for information on the FERC’s April 2004 order adopting a new interim analysis for measuring generation market power and a proceeding initiated by the FERC in December 2004 to assess Southern Company’s generation dominance within its retail service territory. Southern Power has authorization from the FERC to sell power to non-affiliates at market-based prices. Southern Power, through SCS as agent, also has FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. On February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. A hearing before an administrative law judge to review the February filing is scheduled for March 2006. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event that the FERC’s default mitigation measures are ultimately applied, Southern Power may be required to charge cost-based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The impact of such sales through September 30, 2005 is not material to Southern Power’s net income. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Intercompany Interchange Contract

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

have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. The hearing is scheduled for June 2006. See Note 2 to the financial statements of Southern Power under “Plant McIntosh Construction Project” in Item 8 of the Form 10-K for more information on the McIntosh PPA proceeding. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.

Other Matters

See MANAGEMENT’S DISCUSSION AND ANALYSIS — FUTURE EARNINGS POTENTIAL — “General” and “Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K for additional information on long-term power sales agreements and PPAs. Southern Power’s PPAs with non-affiliated counterparties have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that the counterparty does not meet certain rating or financial requirements. The PPAs are expected to provide Southern Power with a stable source of revenue during their respective terms.

On June 7, 2005, Southern Power, through certain of its wholly-owned subsidiaries, acquired all of the outstanding general and limited partnership interests of Oleander from Constellation Power, Inc. and certain other subsidiaries of Constellation Energy Group, Inc. Southern Power’s acquisition of the general and limited partnership interests in Oleander was pursuant to a Purchase and Sale Agreement dated April 8, 2005, for an aggregate purchase price of approximately $206 million, plus approximately $12 million of working capital and other adjustments. The purchase was for a dual-fueled generating plant in Brevard County, Florida with a nominal installed capacity of 680 MW. The entire output of the plant is sold under separate PPAs with Florida Power & Light Company and Seminole Electric Cooperative, Inc. The PPAs expire in 2007 and 2009, respectively. See Note (O) to the Condensed Financial Statements herein for additional information.

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 emission of air pollution from industrial sources, including electric generating facilities. Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered.

In July 2005, the U.S. Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush signed into law in August 2005. Among other things, the Energy Act includes various tax subsidies for electric utilities and provisions repealing the PUHCA. The Energy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. The implementation of the Energy Act requires proceedings at the state level and the development of regulations by the FERC, as well as other federal agencies. Southern Power is still reviewing the legislation. Its impacts will depend on the promulgation and implementation of final rules and cannot be determined at this time.

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

Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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, and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. No such personal injury litigation is currently pending against Southern Power.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of 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. Also 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 and Asset Impairments.

New Accounting Standards

FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligations, was issued in March 2005. This interpretation requires that asset retirement obligations be recorded when a legal obligation exists even though the timing and/or the method of settlement are conditional on a future event. For Southern Power, FIN 47 is effective no later than December 31, 2005. Southern Power has not identified any such obligations; therefore, the impact of adopting FIN 47 currently is not expected to have any effect on Southern Power’s financial statements. However, Southern Power has not concluded its assessment of FIN 47 and other potential obligations are still being evaluated.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Major changes in Southern Power’s financial condition during the nine months ended September 30, 2005 include a September 2005 dividend of $36.2 million to Southern Company and the acquisition of Oleander in June 2005 which contributed an additional $218 million of utility plant and working capital items. This acquisition was originally financed with the addition of $143 million of commercial paper and funds generated from operations. As of September 30, 2005, the outstanding balance of commercial paper used in the acquisition has been reduced to $102 million from funds generated from operations.

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

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

description of Southern Power’s capital requirements for its construction program, maturing debt, purchase commitments, and long-term service agreements.

Sources of Capital

Southern Power may use external funds, equity capital from Southern Company, or internally generated cash from operations to finance any new projects 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. 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.

At September 30, 2005, Southern Power’s current liabilities exceeded current assets due to the issuance of commercial paper and the use of internal cash to finance the Oleander acquisition. To meet liquidity and capital resource requirements, in June 2005 Southern Power entered into a new $400 million committed credit facility with banks expiring in 2010. This new arrangement replaces Southern Power’s previous $325 million unsecured syndicated credit arrangement. The new arrangement eliminates all cross defaults related to projects under construction and Southern Company guarantee terms and conditions that existed in the previous arrangement. The new $400 million revolving credit facility does include two financial covenants, a 65% debt to capitalization test and an 80% contract coverage test. Proceeds from borrowings under this arrangement may be used for working capital and general corporate purposes. This arrangement also provides liquidity support for Southern Power’s commercial paper program. At September 30, 2005, Southern Power had no outstanding borrowings under its new credit facility.

At September 30, 2005, Southern Power had approximately $102.2 million of commercial paper outstanding. Amounts drawn under the commercial paper program may be used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes.

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- or Baa3 or below. Generally, collateral may be provided with a Southern Company guaranty, letter of credit, or cash. These contracts are primarily for physical electricity purchases and sales. At September 30, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $53 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $108 million. In addition, through the acquisition of Oleander, Southern Power assumed a PPA with Seminole Electric Cooperative, Inc. that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- or Baa3 or below. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade, limited to Southern Power’s remaining obligations under the contract. See Note (O) to the Condensed Financial Statements herein for additional information on the Oleander acquisition. Southern Power is also party to certain derivative agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below investment grade. These agreements are primarily for natural gas price risk management activities. At September 30, 2005, Southern Power had no material exposure related to these agreements.

125

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

	(A)		The condensed financial statements of the registrants included herein have been prepared by each registrant, without audit, pursuant to the rules and regulations of the SEC. In the opinion of each registrant’s management, the information regarding such registrant furnished herein reflects all adjustments necessary to present fairly the results of operations for the periods ended September 30, 2005 and 2004. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosure which would substantially duplicate the disclosure 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 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. Certain prior period amounts have been reclassified to conform to current period presentation. Due to seasonal variations in the demand for energy, operating results for the periods presented do not necessarily indicate operating results for the entire year.

	(B)		See Note 3 to the financial statements of Southern Company and the retail operating companies and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.

			NEW SOURCE REVIEW ACTIONS

			See Note 3 to the financial statements of Southern Company and Alabama Power under “Environmental Matters – New Source Review Actions” and Georgia Power, Gulf Power, and Savannah Electric under “New Source Review Actions” in Item 8 of the Form 10-K. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued its decision in favor of Alabama Power on two primary legal issues in the case: (1) the scope of the routine maintenance repair and replacement exclusion under the New Source Review rules and (2) the proper test for calculating emissions increases under those rules. The court decided that routine maintenance repair and replacement must be defined with reference to what is routine in the industry as opposed to what is routine at an individual unit and emissions increases must be measured against the maximum hourly emission rate. The decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations involving Plant Miller Units 3 and 4. In separate orders, the court dismissed Alabama Power’s motion for summary judgment on the Plant Miller claims, stayed the entire case, and referred the parties to mediation. Alabama Power may refile its motion for summary judgment if the mediation proves unsuccessful. At the request of the mediator, the deadline for completing the mediation has been extended from September 9, 2005 to November 30, 2005. The Georgia Power and Savannah Electric case, which is pending in federal district court in Georgia, remains administratively closed. The ultimate outcome of these matters cannot now be determined.

On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the EPA’s December 2002 revisions to its NSR regulations, which included changes to the regulatory

128

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

PLANT WANSLEY ENVIRONMENTAL LITIGATION

See Note 3 to the financial statements of Southern Company under “Environmental Matters - Plant Wansley Environmental Litigation” and Georgia Power under “Plant Wansley Environmental Litigation” in Item 8 of the Form 10-K. In March 2005, the U.S. Circuit Court of Appeals for the Eleventh Circuit accepted Georgia Power’s petition for review of the U.S. District Court for the Northern District of Georgia’s December 15, 2004 order related to the Plant Wansley environmental litigation. Oral argument is scheduled for early 2006. The ultimate outcome of this matter cannot now be determined.

MIRANT RELATED MATTERS

In June 2005, Mirant, as a debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas and filed an amended complaint in July 2005. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company in 1999 and 2000 with actual intent to hinder, delay, or defraud creditors or, alternatively, when Southern Company knew or should have known that Mirant was allegedly insolvent, undercapitalized or unable to pay its debts. The alleged fraudulent transfers and/or illegal dividends include: (1) certain dividends from Mirant to Southern Company in the aggregate amount of $668 million, (2) the repayment of certain intercompany loans and accrued interest in an aggregate amount of $1.035 billion, and (3) the dividend distribution of one share of Series B Preferred Stock and its subsequent redemption in exchange for Mirant’s 80% interest in a holding company that owned SE Finance Capital Corporation and Southern Company Capital Funding, Inc., which transfer Mirant asserts is valued at $247.9 million. The complaint also seeks to recharacterize certain advances from Southern Company to Mirant for investments in energy facilities from debt to equity. The complaint further alleges that Southern Company is liable to Mirant’s creditors for the full amount of Mirant’s liability under an alter ego theory of liability and that Southern Company caused Mirant to breach its fiduciary duty of loyalty to its creditors. The complaint seeks monetary damages in excess of $2 billion plus interest, punitive damages, attorneys fees, and costs. Finally, Mirant objects to Southern Company’s claims against Mirant in the Bankruptcy Court (which, in the aggregate, currently total approximately $70 million) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company believes there is no meritorious basis for Mirant’s claims and intends to vigorously defend itself in this action. Southern Company filed an answer to the amended complaint on August 17, 2005. Southern Company has filed motions to remove the case from the Bankruptcy Court and to transfer the case to the U.S. District Court for the Northern District of Georgia. The ultimate outcome of this matter cannot be determined at this time.

129

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

SOUTHERN COMPANY EMPLOYEE SAVINGS PLAN LITIGATION

See Note 3 to the financial statements of Southern Company under “Mirant Related Matters - Southern Company Employee Savings Plan Litigation” in Item 8 of the Form 10-K. On October 4, 2005, the U.S. District Court for the Northern District of Georgia granted in part and denied in part the Southern Company defendants’ motion to dismiss the amended complaint. The court dismissed the plaintiff’s claims for certain types of equitable relief, but allowed the remainder of the claims to proceed. The plaintiff is scheduled to file a second amended complaint by November 8, 2005, and the defendants are scheduled to respond by November 29, 2005. Thereafter, the parties will proceed with discovery and class certification. The ultimate outcome of this matter cannot now be determined.

RACE DISCRIMINATION LITIGATION

See Note 3 to the financial statements of Southern Company and Georgia Power under “Race Discrimination Litigation” in Item 8 of the Form 10-K. In April 2005, the U.S. Court of Appeals for the Eleventh Circuit denied the plaintiffs’ petition for rehearing by the entire Eleventh Circuit panel of judges. On July 13, 2005, the plaintiffs filed a petition for writ of certiorari, which, on October 17, 2005, was denied by the U.S. Supreme Court. Since this was the final avenue of appeal, this matter is now concluded.

FERC MATTERS

See Note 3 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric under “Market-Based Rate Authority” and Note 2 to the financial statements of Southern Power under “FERC Matters — Market-Based Rate Authority” in Item 8 of the Form 10-K for information on the FERC’s April 2004 order adopting a new interim analysis for measuring generation market power and a proceeding initiated by the FERC in December 2004 to assess Southern Company’s generation dominance within its retail service territory. Each of the retail operating companies and Southern Power has authorization from the FERC to sell power to non-affiliates at market-based prices. Through SCS, as agent, the retail operating companies and Southern Power also have FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. On February 15, 2005, Southern Company submitted additional information related to generation dominance in its retail service territory. A hearing before an administrative law judge to review the February filing is scheduled for March 2006. Any new market-based rate transactions in Southern Company’s retail service territory entered into after February 27, 2005 will be subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. In the event that the FERC’s default mitigation measures are ultimately applied, Southern Power and the retail operating companies may be required to charge cost- based rates for certain wholesale sales in the Southern Company retail service territory, which may be lower than negotiated market-based rates. The impact of such sales through September 30, 2005 is not material to the net income of Southern Company, any of the retail operating companies, or Southern Power. The final outcome of this matter will depend on the form in which the final methodology for

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.

Also in May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, Southern Power, and SCS, as agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have violated the FERC’s standards of conduct applicable to utility companies that are transmission providers, and (3) whether Southern Company’s code of conduct defining Southern Power as a “system company” rather than a “marketing affiliate” is just and reasonable. In connection with the formation of Southern Power, the FERC authorized Southern Power’s inclusion in the IIC in 2000. The FERC also previously approved Southern Company’s code of conduct. The FERC order directs that the administrative law judge who presided over the McIntosh PPA proceeding be assigned to preside over the hearing in this proceeding and that the testimony and exhibits presented in that proceeding be preserved to the extent appropriate. The hearing is scheduled for June 2006. See Note 3 to the financial statements of Southern Company, Georgia Power and Savannah Electric and Note 2 to the financial statements of Southern Power under “Plant McIntosh Construction Project” in Item 8 of the Form 10-K for information on the McIntosh PPA proceeding. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries will be subject to refund to the extent the FERC orders any changes to the IIC.

Southern Company and its subsidiaries believe that there is no meritorious basis for these allegations and intend to vigorously defend themselves in the proceedings. However, the final outcome of these matters, including any remedies to be applied in the event of an adverse ruling in these proceedings, cannot now be determined.

INCOME TAX MATTERS

See Note 3 to the financial statements of Southern Company under “Income Tax Matters - Leveraged Lease Transactions” in Item 8 of the Form 10-K. The IRS challenged Southern Company’s deductions related to three international lease transactions (so-called SILO or sale-in-lease-out transactions), in connection with its audit of Southern Company’s 2000 and 2001 tax returns. If the IRS is ultimately successful in disallowing the tax deductions related to these transactions beginning with the 2000 tax year, Southern Company could be subject to additional interest charges of up to $29 million. The IRS has also proposed a penalty of approximately $16 million. Additionally, although the payment of the tax liability, exclusive of interest and any penalties, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. See Note 1 to the financial statements of Southern Company under “Leveraged Leases” in Item 8 of the Form 10-K for additional details of the deferred taxes related to these transactions. Furthermore, the FASB has recently proposed changes to the accounting for both leveraged leases and uncertain tax positions that may be effective as early as December 31, 2005. If approved as proposed, these changes could require Southern Company to reflect the tax deductions that the IRS is challenging as currently payable on the

131

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

balance sheet and to change the timing of income recognized under the leases, including a cumulative effect upon adoption of the change. For the lease-in-lease-out (LILO) transaction settled with the IRS in February 2005, Southern Company estimates such cumulative effect would reduce Southern Company’s net income by approximately $11 million. The impact of these proposed changes related to the SILO transactions would be dependent on the outcome of ongoing negotiations with the IRS, but could be significant, and potentially material, to Southern Company’s net income. Southern Company believes these transactions are valid leases for U.S. tax purposes, the related deductions are allowable, and the assessment of a penalty is inappropriate. Southern Company is continuing to pursue resolution of these matters with the IRS; however, the ultimate outcome of these matters cannot now be determined.

	(C)		See Note 1 to the financial statements of Southern Company and the retail operating companies under “Stock Options” and Note 8 to the financial statements of Southern Company and the retail operating companies under “Stock Option Plan” in Item 8 of the Form 10-K for information regarding non-qualified employee stock options provided by Southern Company. Southern Company accounts for options granted in accordance with Accounting Principles Board Opinion No. 25; thus, no compensation expense is recognized because the exercise price of all options granted equaled the fair market value on the date of the grant. The estimated fair values of stock options granted during the three-month and nine-month periods ending September 30, 2005 and 2004 have been derived using the Black-Scholes stock option pricing model.

			The following table shows the assumptions and the weighted average fair values of these stock options:


	Three			Three			Nine			Nine
	Months			Months			Months			Months
	Ended			Ended			Ended			Ended
	September			September			September			September
	30, 2005			30, 2004			30, 2005			30, 2004
Interest rate		4.1	%		3.8	%		3.9	%		3.1	%
Average expected life of stock options (in years)		5			5			5			5
Expected volatility of common stock		17.3	%		19.0	%		17.9	%		19.6	%
Expected annual dividends on common stock	$	1.49		$	1.43		$	1.43		$	1.40
Weighted average fair value of stock options Granted	$	4.21		$	3.34		$	3.90		$	3.29

The pro forma impact of fair-value accounting for options granted on Southern Company’s consolidated earnings per share is as follows:


	Three Months Ended				Three Months Ended
	September 30, 2005				September 30, 2004
	As Reported		Pro Forma		As Reported		Pro Forma
Earnings per share (dollars):
Basic	$	0.97	$	0.97	$	0.87	$	0.87
Diluted	$	0.97	$	0.96	$	0.87	$	0.87


	Nine Months Ended				Nine Months Ended
	September 30, 2005				September 30, 2004
	As Reported		Pro Forma		As Reported		Pro Forma
Earnings per share (dollars):
Basic	$	1.92	$	1.90	$	1.80	$	1.78
Diluted	$	1.91	$	1.89	$	1.79	$	1.77

132

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(E)

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


	Three Months		Three Months		Nine Months		Nine Months
	Ended		Ended		Ended		Ended
	September 30,		September 30,		September 30,		September 30,
	2005		2004		2005		2004

As reported shares		743,214		739,345		744,654		738,056
Effect of options		4,603		4,350		4,725		4,215
Diluted shares		747,817		743,695		749,379		742,271

(F)

See Note 6 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric under “Financial Instruments” in Item 8 of the Form 10-K. At September 30, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows (in millions):


	Southern			Alabama			Georgia			Gulf			Mississippi			Savannah
	Company			Power			Power			Power			Power			Electric

Regulatory liabilities, net	$	182.8		$	57.2		$	55.5		$	24.3		$	33.6		$	12.1
Other comprehensive income (loss)		(3.5	)		—			—			—			(3.5	)		—
Net income (loss)		(12.4	)		(0.3	)		(0.3	)		(0.1	)		(0.1	)		—

Total fair value	$	166.9		$	56.9		$	55.2		$	24.2		$	30.0		$	12.1

For the three months and nine months ended September 30, 2005, the expense recognized in income for derivative energy contracts that are not hedges was $12 million for Southern Company and was immaterial for the other registrants, and for the three months and nine months ended September 30, 2004 the amounts were immaterial for all registrants.

The amounts expected to be reclassified from other comprehensive income to fuel expense for the twelve month period ending September 30, 2006 were immaterial for each registrant. Additionally, no material ineffectiveness has been recorded in net income for the three months and nine months ended September 30, 2005 and 2004.

In addition to the derivative energy contracts discussed above, Southern Company entered into a purchased option in April 2005 with an initial fair value of approximately $7 million to reduce its exposure to a potential phase-out of certain income tax credits in 2005. In accordance with Section 29 of the IRC, these tax credits are subject to limitation as the annual average price of oil increases. At September 30, 2005 the fair value of the option was approximately $11 million. For the three months and nine months ended September 30, 2005, the gain recognized in income to mark the option to market was $5 million and $4 million, respectively.

At September 30, 2005, Southern Company had $3.1 billion notional amount of interest rate derivatives outstanding with net fair value gains of $34 million as follows:

134

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


	Southern			Alabama			Georgia			Gulf			Mississippi			Savannah
POSTRETIREMENT PLANS	Company			Power			Power			Power			Power			Electric

Three Months Ended September 30, 2005

Service cost	$	7		$	2		$	3		$	—		$	—		$	—
Interest cost		24			6			10			1			1			1
Expected return on plan assets		(11	)		(4	)		(6	)		—			—			—
Net amortization		9			3			5			—			—			—
Net cost (income)	$	29		$	7		$	12		$	1		$	1		$	1

Nine Months Ended September 30, 2005

Service cost	$	21		$	5		$	8		$	1		$	1		$	—
Interest cost		72			20			31			3			3			2
Expected return on plan assets		(34	)		(12	)		(17	)		(1	)		(1	)		(1	)
Net amortization		29			8			14			1			1			1
Net cost (income)	$	88		$	21		$	36		$	4		$	4		$	2

Three Months Ended September 30, 2004

Service cost	$	7		$	2		$	3		$	—		$	—		$	—
Interest cost		21			5			9			1			1			1
Expected return on plan assets		(13	)		(5	)		(6	)		—			—			—
Net amortization		8			3			3			—			—			—
Net cost (income)	$	23		$	5		$	9		$	1		$	1		$	1

Nine Months Ended September 30, 2004

Service cost	$	21		$	6		$	7		$	—		$	—		$	—
Interest cost		69			17			31			3			3			3
Expected return on plan assets		(37	)		(13	)		(18	)		—			—			—
Net amortization		26			7			13			—			—			—
Net cost (income)	$	79		$	17		$	33		$	3		$	3		$	3

(H)

See Note 5 to the financial statements of Southern Company, Alabama Power, and Savannah Electric in Item 8 of the Form 10-K for information on each company’s effective income tax rate. In accordance with an Alabama PSC-approved accounting order to restore the natural disaster reserve, Alabama Power recorded a reduction in its income tax expense of approximately $27.7 million for the nine months ended September 30, 2005. In addition, in connection with construction on the Plant McIntosh combined cycle units, Savannah Electric recorded a decrease in its income tax expense of $0.7 million for the nine months ended September 30, 2005 related to AFUDC equity, which is not taxable. The impact of these entries caused significant reductions in the effective income tax rate for the first two quarters of 2005 for each of Southern Company, Alabama Power, and Savannah Electric. On an annual basis, the effective income tax rate for 2005 is expected to be approximately 27% for Southern Company, 35% for Alabama Power, and 35% for Savannah Electric. For additional information on Alabama Power’s accounting order, see Note 3 to the financial statements of Southern Company and Alabama Power under “Gulf Power and Alabama Power Storm Damage Recovery” and “Natural Disaster Cost Recovery,” respectively, in Item 8 of the Form 10-K. For additional information on the Plant McIntosh construction, see Note 3 to the financial statements of Southern Company and Savannah Electric under “Plant McIntosh Construction Project” in Item 8 of the Form 10-K.

137

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(I)

See Note 3 to the financial statements of Southern Company and Alabama Power under “Alabama Power Retail Regulatory Matters” and “Retail Regulatory Matters,” respectively, in Item 8 of the Form 10-K for information on Alabama Power’s Rate Stabilization and Equalization Plan (Rate RSE). On October 4, 2005, the Alabama PSC approved a requested revision to Rate RSE. Rate RSE adjustments can be made effective January 2007 and annually thereafter and will be based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4% per year and any annual adjustment is limited to 5%. The range of return on common equity, on which such adjustments are based, remains unchanged. If Alabama Power’s actual return on common equity is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual return on common equity fall below the allowed equity return range. Alabama Power will make its initial submission of projected data for calendar year 2007 by December 1, 2006.

On October 19, 2005, Alabama Power filed with the Alabama PSC for a fuel cost recovery increase under the provisions of its energy cost recovery rate (Rate ECR). An approval of this filing would result in an increase of the energy billing factor for retail customers from 1.788 cents per kilowatt-hour to 2.650 cents per kilowatt-hour and would become effective December 3, 2005. This change to the billing factor represents an average increase of approximately $8.62 per month for a customer billing of 1,000 kilowatt-hours. Rate ECR revenues as recorded on the financial statements are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, this increase in the billing factor will have no significant effect on Alabama Power’s revenues or net income, but will increase annual cash flow. The requested increase is intended to allow for the recovery of energy costs based on an estimate of future energy costs, as well as the collection of the existing under recovered energy costs by the end of 2006. Alabama Power’s under recovered retail energy costs as of September 30, 2005 totaled $182.4 million. Under the terms of Rate ECR, the increase will be effective 45 days after the filing unless modified by the Alabama PSC following a public hearing. The final outcome of this filing cannot be determined at this time.

See Note 1 to the financial statements of Southern Company and Alabama Power under “Nuclear Decommissioning” in Item 8 of the Form 10-K for information on Alabama Power’s external nuclear decommissioning trust funds (NDT). In May 2005, Alabama Power received notice from the NRC renewing the licenses on both reactor units at Plant Farley for an additional 20 years. As a result of the license extension, amounts previously contributed to the NDT are currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, the Alabama PSC approved Alabama Power’s request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in decommissioning costs and to also suspend the associated obligation to make semi-annual contributions to the NDT. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the NDT to the Alabama PSC and, if necessary, would seek the Alabama PSC’s approval to address any changes in a manner consistent with NRC and other applicable requirements. The approved suspension would not affect the transfer of internal reserves (less than $1 million annually) previously collected from customers prior to the establishment of the NDT over the remaining life of the licenses.

See Note 1 to the financial statements of Southern Company and Alabama Power under “Storm Damage Reserves” and “Natural Disaster Reserve,” respectively, in Item 8 of the Form 10-K for information on how Alabama Power maintains a reserve to cover uninsured expenses resulting from storms. On July 10, 2005 and August 29, 2005, Hurricanes Dennis and Katrina, respectively, impacted the coast of Alabama and continued north through the state of Alabama, causing significant damage in parts of the service territory of Alabama Power. Approximately 241,000 and 637,000, respectively, of Alabama Power’s 1.4 million customer accounts were without electrical service immediately after Hurricanes Dennis and Katrina. Alabama Power sustained significant damage to its distribution and transmission facilities during these storms.

138

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

In August 2005, Alabama Power received approval from the Alabama PSC to defer approximately $28 million of the Hurricane Dennis storm-related operation and maintenance costs, which resulted in a negative balance in the natural disaster reserve. In October 2005, Alabama Power also received similar approval from the Alabama PSC to defer approximately $45 million of Hurricane Katrina storm-related operation and maintenance costs. Alabama Power’s current annual accrual to the natural disaster reserve, as approved by the Alabama PSC, is $3 million, with additional accruals allowed whenever the reserve balance is less than $22.4 million.

On November 1, 2005, Alabama Power filed a request with the Alabama PSC to approve a plan designed to recover its deferred Hurricanes Dennis- and Katrina-related operation and maintenance costs and to replenish its depleted natural disaster reserve. This request would provide for a separate rate rider, Rate NDR (Natural Disaster Reserve), based on a monthly charge per customer account. Rate NDR would consist of two components. One part of Rate NDR would be a monthly charge to allow recovery of the previously deferred storm costs, which totaled approximately $69 million as of September 30, 2005, over a two year period. The second part of Rate NDR would be a monthly charge to replenish the natural disaster reserve’s balance over a five year period to a newly authorized target of $75 million. As revenue from Rate NDR is recognized, an equal amount of operation and maintenance expense related to the natural disaster reserve will also be recognized. As a result, this increase in revenue and expense will not have an impact on net income, but will increase the annual cash flow. If approved by the Alabama PSC, Rate NDR would become effective in January, 2006. A final decision from the Alabama PSC is expected in December 2005. The final outcome of the filing cannot be determined at this time.

On July 28, 2005, Alabama Power filed two applications with the FERC for a new 50-year license for the Alabama Power’s seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and a new 50-year license for the Lewis Smith and Bankhead developments on the Warrior River. The FERC licenses for all of these nine projects expire in 2007. Upon or after the expiration of each license, the United States Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. The FERC may grant relicenses subject to certain requirements that could result in additional costs to Alabama Power. The final outcome of this matter cannot be determined at this time.

	(J)		On May 17, 2005, the Georgia PSC voted to allow Georgia Power to increase customer fuel rates to recover estimated under-recovered fuel costs of approximately $508 million as of May 31, 2005 over the period from June 1, 2005 through May 31, 2009, as well as future projected fuel costs based on a June 2005 through May 2006 test period. The new fuel rate became effective June 1, 2005 and represents an average annual increase in customer billings of approximately 9.5%, or approximately $473 million. Based on the order, a portion of the under-recovered regulatory clause revenues was reclassified from current assets to deferred charges and other assets on the balance sheet. Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $198.3 million through September 30, 2005. In accordance with the Georgia PSC’s order, such amounts will be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power will be required to file for a temporary fuel rate change. However, Georgia Power has agreed with a Georgia PSC staff recommendation to suspend the temporary fuel rate provision and, instead, will file a request no later than April 2006 to increase its fuel cost recovery rate. 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 increase in the billing factor will have no significant effect on Georgia Power’s revenues or net income, but will increase annual cash flow.

	(K)		See Note 3 to the financial statements of Southern Company and Gulf Power under “Gulf Power and Alabama Power Storm Damage Recovery” and “Retail Regulatory Matters,” respectively, in Item 8 of the Form 10-K for information on a Stipulation and Settlement filed with the Florida PSC to resolve all

139

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

matters regarding the effects of Hurricane Ivan on Gulf Power’s reserve for property damage. The Florida PSC approved the Stipulation and Settlement as filed in March 2005 and Gulf Power began billing customers accordingly in April 2005. In connection with the Stipulation, Gulf Power has agreed that it will not seek any additional increase in its base rates and charges to become effective on or before March 1, 2007.

See Note 1 to the financial statements of Gulf Power under “Provision for Property Damage” in Item 8 of the Form 10-K for information on Gulf Power’s accrual to cover the cost of damages to its transmission and distribution lines from major storms and the cost of uninsured damages to its generation facilities and other property. Hurricanes Dennis and Katrina hit the Gulf Coast of Florida in July 2005 and August 2005, respectively, causing damage to the service area of Gulf Power. Hurricanes Dennis and Katrina restoration costs for Gulf Power were approximately $65 million and $5 million, respectively. As of September 30, 2005, Gulf Power’s accumulated provision for property damage had a deficit balance of approximately $57.7 million, and is included in the balance sheet under “Property Damage” and “Other Regulatory Assets.” The established policy of the Florida PSC, as recently reaffirmed by its decisions following the 2004 hurricane experience of Florida’s investor owned electric utilities, provides for recovery of these costs through the mechanism of the property insurance reserve and, where necessary, through a special recovery surcharge. In 2005, the Florida legislature authorized securitized financing as an additional mechanism available to the Florida PSC and electric utilities in Florida for addressing the extraordinary costs associated with hurricanes. Gulf Power is evaluating this option, along with other alternatives, for recovery of these costs.

(L)

On June 30, 2005, Mississippi Power issued $30 million of Series G 5.40% Senior Notes due July 1, 2035. The proceeds from the sale were used for the legal defeasance of $30 million principal amount of its First Mortgage Bonds, 6 7/8% Series due December 1, 2025. An irrevocable trust agreement was executed by Mississippi Power and the trustee for the bond holders under which the bonds will be redeemed in December 2005. As a result of this legal defeasance, there are no longer any first mortgage bond liens on Mississippi Power’s property and Mississippi Power no longer has to comply with the covenants and restrictions of the first mortgage bond indenture. The liability associated with the first mortgage bonds has been extinguished on Mississippi Power’s balance sheet since Mississippi Power has been legally released from being the primary obligor.

See Note 1 to the financial statements of Southern Company and Mississippi Power under “Storm Damage Reserves” and “Provision for Property Damage,” respectively, in Item 8 of the Form 10-K for

140

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

information on how Mississippi Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generation facilities and other property. At August 31, 2005, the balance in the accumulated provision for property damage was $5.6 million. Mississippi Power’s current annual accrual to the provision for property damage, as approved by the Mississippi PSC, is $1.5 million to $4.6 million.

Hurricane Katrina hit the coast of Florida, Alabama, Mississippi, and Louisiana on August 29, 2005, causing substantial damage. Immediately following the storm, all of Mississippi Power’s 195,000 customers were without electrical service. Mississippi Power sustained significant damage to its distribution and transmission facilities, as well as Plant Watson. Plant Watson has six generating units, including three gas-fired units totaling 262 MW, two coal-fired units totaling 750 MW, and a 40 MW gas turbine. One of the coal-fired units at the plant has been returned to service and Mississippi Power currently expects the second coal-fired unit to be returned to service by the end of 2005. The gas units operate primarily to serve summer peak loads. Their condition is currently being evaluated, with repairs expected to be completed before the summer of 2006.

As of September 30, 2005, approximately 19,200 of Mississippi Power’s customers remained unable to receive service. Mississippi Power currently estimates the total incremental cost of repairing the damages to its facilities and restoring service to customers will be approximately $245 million to $295 million. It is estimated that approximately $59 million of this cost will be covered through external insurance. Business and government authorities are still reviewing redevelopment plans for portions of the severely damaged areas along the Mississippi shoreline. Until such plans are complete, Mississippi Power cannot determine the related electric power needs and has excluded these areas from its current cost estimates. The ultimate impact of the redevelopment plans in these areas on Mississippi Power’s cost estimates cannot now be determined. Mississippi Power estimates approximately $176 million of the total incremental restoration costs were incurred as of September 30, 2005. These estimates include environmental costs of approximately $10 million associated with Plant Watson and certain distribution facilities.

141

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(M)

On May 17, 2005, the Georgia PSC approved a new three-year retail rate plan for Savannah Electric ending May 31, 2008 (2005 Plan). Under the terms of the 2005 Plan, earnings will be evaluated against a retail return on common equity range of 9.75% to 11.75%. Two-thirds of any earnings above 11.75% will be applied to rate refunds with the remaining one-third retained by Savannah Electric. Retail base revenues were increased by approximately $9.6 million, or 5.1%, on an annual basis effective in June 2005. Savannah Electric will not file for a general base rate increase unless its projected retail return on common equity falls below 9.75%. Savannah Electric is required to file a general rate case on November 30, 2007, in response to which the Georgia PSC would be expected to determine whether the rate plan should be continued, modified, or discontinued.

Effective in May 2001, the Georgia PSC approved an order allowing Savannah Electric to implement a natural gas and oil procurement and hedging program. This order allows Savannah Electric to use financial instruments to hedge price and commodity risk associated with these fuels. The order limits the program in terms of time, volume, dollars, and physical amounts hedged. The costs of the program, including any net losses, are recovered as a fuel cost through the fuel cost recovery clause. Annual net financial gains from the hedging program will be shared, with the retail customers receiving 75 percent and Savannah Electric retaining 25 percent of the total net gains. Through September 30, 2005, such net gains totaled $7.1 million, of which Savannah Electric has retained $1.7 million.

(N)

See Notes 9 and 10 to the financial statements of Savannah Electric in Item 8 of the Form 10-K for information regarding Savannah Electric’s restatement of its financial statements for the three-month and nine-month periods ended September 30, 2004 as the result of errors in the estimate of unbilled revenues for the periods. A summary of the effects of those restatement adjustments for the three-month and nine-month periods ended September 30, 2004 is as follows (in thousands):

142

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)


	Three Months Ended				Nine Months Ended
	September 30, 2004				September 30, 2004
	As Originally		As		As Originally		As
	Reported		Restated		Reported		Restated

Retail sales revenues	$	102,312	$	104,822	$	258,772	$	259,847
Total operating revenues		105,379		107,889		270,284		271,359
Operating income		22,306		24,541		45,744		46,544
Earnings before income taxes		19,813		22,323		36,589		37,664
Income taxes		7,262		8,232		13,391		13,806
Net income		12,551		14,091		23,198		23,858
Net income after dividends on preferred stock		11,876		13,416		22,373		23,033
Comprehensive income		11,902		13,442		22,431		23,091

	(O)		On June 7, 2005, Southern Power, through certain of its wholly-owned subsidiaries, acquired all of the outstanding general and limited partnership interests of Oleander Power Project, L.P. (Oleander) from Constellation Power, Inc. and certain other subsidiaries of Constellation Energy Group, Inc. The results of Oleander’s operations have been included in the financial statements since that date. Southern Power’s acquisition of the general and limited partnership interests in Oleander was pursuant to a Purchase and Sale Agreement dated April 8, 2005, for an aggregate purchase price of approximately $206 million, plus approximately $12 million of working capital and other adjustments. Oleander owns a dual-fueled generating plant in Brevard County, Florida with a nominal installed capacity of 680 MW. The entire output of the plant is sold under separate PPAs with Florida Power & Light Company and Seminole Electric Cooperative, Inc. The PPAs expire in 2007 and 2009, respectively.

	(P)		On July 8, 2005, Southern Company GAS signed a letter of intent to negotiate the sale of substantially all of its assets to Cobb Electric Membership Corporation. At September 30, 2005, Southern Company GAS’ assets totaled $78.9 million. The proposed sale is subject to the negotiation of a definitive sale agreement and receipt of necessary regulatory or governmental approvals.

	(Q)		In May 2005, Southern Company completed the purchase from Ormat Nevada, Inc. and subsequent leaseback of the Puna Geothermal Facility, a 25 MW geothermal facility in Hilo, Hawaii. The cost of the facility was approximately $71 million. Southern Company’s net investment in the leveraged lease is approximately $30 million.

	(R)		Southern Company’s reportable business segment is the sale of electricity in the Southeast by the five retail operating companies and Southern Power. 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 synthetic fuels and leveraged lease projects, telecommunications, energy-related services, and natural gas marketing. Southern Power’s revenues from sales to the retail operating companies were $180 million and $402 million for the three months and nine months ended September 30, 2005, respectively, and $128 million and $322 million for the three months and nine months ended September 30, 2004, respectively. All other intersegment revenues are not material. Financial data for business segments and products and services are as follows:

143


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)
	270 Peachtree Street, N.W.
	Atlanta, Georgia 30303
	(404) 506-5000
1-3164	Alabama Power Company	63-0004250
	(An Alabama Corporation)
	600 North 18^th Street
	Birmingham, Alabama 35291
	(205) 257-1000
1-6468	Georgia Power Company	58-0257110
	(A Georgia Corporation)
	241 Ralph McGill Boulevard, N.E.
	Atlanta, Georgia 30308
	(404) 506-6526
0-2429	Gulf Power Company	59-0276810
	(A Florida Corporation)
	One Energy Place
	Pensacola, Florida 32520
	(850) 444-6111
001-11229	Mississippi Power Company	64-0205820
	(A Mississippi Corporation)
	2992 West Beach
	Gulfport, Mississippi 39501
	(228) 864-1211
1-5072	Savannah Electric and Power Company	58-0418070
	(A Georgia Corporation)
	600 East Bay Street
	Savannah, Georgia 31401
	(912) 644-7171
333-98553	Southern Power Company	58-2598670
	(A Delaware Corporation)
	270 Peachtree Street, N.W.
	Atlanta, Georgia 30303
	(404) 506-5000


Registrant	Yes	No
The Southern Company	x
Alabama Power Company		x
Georgia Power Company		x
Gulf Power Company		x
Mississippi Power Company		x
Savannah Electric and Power Company		x
Southern Power Company		x


	Description of	Shares Outstanding
Registrant	Common Stock	at September 30, 2005
The Southern Company	Par Value $5 Per Share		741,495,041
Alabama Power Company	Par Value $40 Per Share		9,250,000
Georgia Power Company	Without Par Value		7,761,500
Gulf Power Company	Without Par Value		992,717
Mississippi Power Company	Without Par Value		1,121,000
Savannah Electric and Power Company	Par Value $5 Per Share		10,844,635
Southern Power Company	Par Value $0.01 Per Share		1,000


	Page
	Number
PART II — OTHER INFORMATION

Item 1. Legal Proceedings		145
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		145
Item 3. Defaults Upon Senior Securities	Inapplicable
Item 4. Submission of Matters to a Vote of Security Holders	Inapplicable
Item 5. Other Information	Inapplicable
Item 6. Exhibits		146
Signatures		150


TERM		MEANING
Alabama Power		Alabama Power Company
AFUDC		Allowance for funds used during construction
BMA		Bond Market Association
Clean Air Act		Clean Air Act Amendments of 1990
DOE		U.S. Department of Energy
ECO Plan		Environmental Compliance Overview Plan
EPA		U.S. Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Form 10-K		Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Savannah Electric, and Southern Power for the year ended December 31, 2004
Georgia Power		Georgia Power Company
Gulf Power		Gulf Power Company
IIC		Intercompany Interchange Contract
IRC		Internal Revenue Code of 1986, as amended
IRS		Internal Revenue Service
LIBOR		London Interbank Offered Rate
Mirant		Mirant Corporation
Mississippi Power		Mississippi Power Company
Moody’s		Moody’s Investors Service, Inc
MW		Megawatts
NRC		Nuclear Regulatory Commission
PEP		Performance Evaluation Plan
PPA		Purchase Power Agreement
PSC		Public Service Commission
PUHCA		Public Utility Holding Company Act of 1935, as amended
retail operating companies		Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Savannah Electric
RTO		Regional Transmission Organization
S&P		Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
Savannah Electric		Savannah Electric and Power Company
SCS		Southern Company Services, Inc.
SEC		Securities and Exchange Commission
Southern Company		The Southern Company
Southern Company GAS		Southern Company Gas LLC
Southern Company system		Southern Company, the retail operating companies, Southern Power, and other subsidiaries
Southern Power		Southern Power Company
Super Southeast		Southern Company’s traditional service territory, Alabama, Florida, Georgia, and Mississippi, plus the surrounding states of Kentucky, Louisiana, North Carolina, South Carolina, Tennessee, and Virginia


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


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


	Page
	Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		6

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		8
Condensed Consolidated Statements of Cash Flows		9
Condensed Consolidated Balance Sheets		10
Condensed Consolidated Statements of Comprehensive Income		12
Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
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		50
Condensed Statements of Comprehensive Income		50
Condensed Statements of Cash Flows		51
Condensed Balance Sheets		52
Management’s Discussion and Analysis of Financial Condition and Results of Operations		54
Gulf Power Company
Condensed Statements of Income		67
Condensed Statements of Comprehensive Income		67
Condensed Statements of Cash Flows		68
Condensed Balance Sheets		69
Management’s Discussion and Analysis of Financial Condition and Results of Operations		71
Mississippi Power Company
Condensed Statements of Income		83
Condensed Statements of Comprehensive Income		83
Condensed Statements of Cash Flows		84
Condensed Balance Sheets		85
Management’s Discussion and Analysis of Financial Condition and Results of Operations		87
Savannah Electric and Power Company
Condensed Statements of Income		100
Condensed Statements of Comprehensive Income		100
Condensed Statements of Cash Flows		101
Condensed Balance Sheets		102
Management’s Discussion and Analysis of Financial Condition and Results of Operations		104
Southern Power Company
Condensed Statements of Income		116
Condensed Statements of Comprehensive Income		116
Condensed Statements of Cash Flows		117
Condensed Balance Sheets		118
Management’s Discussion and Analysis of Financial Condition and Results of Operations		120
Notes to the Condensed Financial Statements		127
Item 3. Quantitative and Qualitative Disclosures about Market Risk		30
Item 4. Controls and Procedures		30


	At September 30,			At December 31,
Assets	2005			2004
	(in thousands)
Current Assets:
Cash and cash equivalents	$	416,339		$	373,199
Receivables —
Customer accounts receivable		1,077,806			755,436
Unbilled revenues		384,597			304,479
Under recovered regulatory clause revenues		709,441			530,898
Other accounts and notes receivable		385,417			310,971
Accumulated provision for uncollectible accounts		(40,673	)		(46,100	)
Fossil fuel stock, at average cost		365,995			325,370
Vacation pay		105,771			105,437
Materials and supplies, at average cost		637,229			601,820
Assets from risk management activities		219,557			39,268
Prepaid expenses		130,067			126,059
Other		60,642			44,397

Total current assets		4,452,188			3,471,234

Property, Plant, and Equipment:
In service		42,990,278			41,437,517
Less accumulated depreciation		15,503,878			14,950,939

		27,486,400			26,486,578
Nuclear fuel, at amortized cost		237,124			218,133
Construction work in progress		1,349,294			1,656,772

Total property, plant, and equipment		29,072,818			28,361,483

Other Property and Investments:
Nuclear decommissioning trusts, at fair value		939,795			904,828
Leveraged leases		1,060,496			976,000
Other		359,077			380,904

Total other property and investments		2,359,368			2,261,732

Deferred Charges and Other Assets:
Deferred charges related to income taxes		873,903			864,477
Prepaid pension costs		1,012,742			985,633
Unamortized debt issuance expense		160,202			153,351
Unamortized loss on reacquired debt		315,295			323,394
Deferred under recovered regulatory clause revenues		325,545			—
Other regulatory assets		435,959			246,644
Other		375,683			294,138

Total deferred charges and other assets		3,499,329			2,867,637


Total Assets	$	39,383,703		$	36,962,086


	At September 30,			At December 31,
Liabilities and Stockholders’ Equity	2005			2004
	(in thousands)
Current Liabilities:
Securities due within one year	$	918,887		$	983,282
Notes payable		853,008			426,394
Accounts payable		1,150,594			884,240
Customer deposits		213,356			200,454
Accrued taxes —
Income taxes		290,302			47,237
Other		365,950			243,200
Accrued interest		188,014			179,301
Accrued vacation pay		137,678			137,452
Accrued compensation		340,499			431,023
Other		485,657			278,477

Total current liabilities		4,943,945			3,811,060

Long-term Debt		10,894,264			10,488,076

Long-term Debt Payable to Affiliated Trusts		1,960,644			1,960,644

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		5,522,385			5,237,162
Deferred credits related to income taxes		319,072			372,528
Accumulated deferred investment tax credits		533,209			552,108
Employee benefit obligations		927,140			864,216
Asset retirement obligations		947,066			903,385
Other cost of removal obligations		1,318,226			1,295,871
Miscellaneous regulatory liabilities		360,150			327,710
Other		280,866			311,167

Total deferred credits and other liabilities		10,208,114			9,864,147

Total Liabilities		28,006,967			26,123,927

Preferred Stock of Subsidiaries		560,442			560,472

Common Stockholders’ Equity:
Common stock, par value $5 per share —
Authorized — 1 billion shares
Issued — September 30, 2005: 751,519,616 Shares;
— December 31, 2004: 741,734,998 Shares
Treasury — September 30, 2005: 10,024,575 Shares;
— December 31, 2004: 240,425 Shares
Par value		3,757,598			3,708,675
Paid-in capital		1,077,724			868,747
Treasury, at cost		(347,172	)		(5,557	)
Retained earnings		6,449,477			5,838,986
Accumulated other comprehensive loss		(121,333	)		(133,164	)

Total Common Stockholders’ Equity		10,816,294			10,277,687

Total Liabilities and Stockholders’ Equity	$	39,383,703		$	36,962,086


	At September 30,			At December 31,
Liabilities and Stockholder’s Equity	2005			2004
	(in thousands)
Current Liabilities:
Securities due within one year	$	421,505		$	225,005
Accounts payable —
Affiliated		158,822			141,096
Other		188,432			198,834
Customer deposits		54,137			49,598
Accrued taxes —
Income taxes		126,969			28,498
Other		91,677			29,688
Accrued interest		62,743			40,029
Accrued vacation pay		36,494			36,494
Accrued compensation		77,907			76,858
Other		101,865			34,290

Total current liabilities		1,320,551			860,390

Long-term Debt		3,910,121			3,855,257

Long-term Debt Payable to Affiliated Trusts		309,279			309,279

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		1,923,123			1,885,120
Deferred credits related to income taxes		108,509			148,395
Accumulated deferred investment tax credits		198,595			205,353
Employee benefit obligations		209,224			194,837
Asset retirement obligations		402,812			383,621
Asset retirement obligation regulatory liability		155,202			159,230
Other cost of removal obligations		602,585			597,147
Other regulatory liabilities		71,446			47,535
Other		31,086			62,044

Total deferred credits and other liabilities		3,702,582			3,683,282

Total Liabilities		9,242,533			8,708,208

Preferred Stock		465,046			465,047

Common Stockholder’s Equity:
Common stock, par value $40 per share —
Authorized - 15,000,000 shares
Outstanding — September 30, 2005: 9,250,000 shares
— December 31, 2004: 8,250,000 shares		370,000			330,000
Paid-in capital		1,971,668			1,955,183
Retained earnings		1,484,706			1,341,049
Accumulated other comprehensive loss		(11,607	)		(16,028	)

Total common stockholder’s equity		3,814,767			3,610,204

Total Liabilities and Stockholder’s Equity	$	13,522,346		$	12,783,459


Registrant		Applicable Notes
Southern Company		A, B, C, D, E, F, G, H, I, J, K, L, P, Q, R

Alabama Power		A, B, C, D, F, G, H, I

Georgia Power		A, B, C, D, F, G, J

Gulf Power		A, B, C, D, F, G, K

Mississippi Power		A, B, C, D, F, G, L

Savannah Electric		A, B, C, D, F, G, H, M, N

Southern Power		A, B, F, O


	Balance at		Liabilities		Liabilities					Cash Flow			Balance at
	12/31/04		Incurred		Settled			Accretion		Revisions			9/30/05
Alabama Power	$	383.6	$	—	$	—		$	19.6	$	(0.4	)	$	402.8
Georgia Power		504.5		—		(1.0	)		24.8		—			528.3
Gulf Power		5.8		—		—			0.2		—			6.0
Mississippi Power		5.5		—		—			0.3		—			5.8
Savannah Electric		3.9		0.5		(0.5	)		0.1		—			4.0

Southern Company	$	903.3	$	0.5	$	(1.5	)	$	45.1	$	(0.4	)	$	947.0


*		Interest rate collar

**		Series of interest rate caps and collars with variable rate based on one-month LIBOR


	Electric Utilities
	Retail
	Operating		Southern							All		Reconciling
	Companies		Power		Eliminations			Total		Other		Eliminations			Consolidated

					(in millions)
Three Months Ended September 30, 2005:
Operating revenues	$	4,244	$	266	$	(221	)	$	4,289	$	119	$	(30	)	$	4,378
Segment net income (loss)		676		40		—			716		8		(2	)		722
Nine Months Ended September 30, 2005:
Operating revenues	$	9,967	$	568	$	(480	)	$	10,055	$	419		(87	)	$	10,387
Segment net income (loss)		1,274		88		—			1,362		72		(2	)		1,432
Total assets at September 30, 2005	$	35,751	$	2,323	$	(217	)	$	37,857	$	1,921	$	(394	)	$	39,384


Three Months Ended September 30, 2004:
Operating revenues	$	3,322	$	189	$	(153	)	$	3,358	$	110	$	(27	)	$	3,441
Segment net income (loss)		591		37		—			628		16		1			645
Nine Months Ended September 30, 2004:
Operating revenues	$	8,733	$	547	$	(418	)	$	8,862	$	402	$	(82	)	$	9,182
Segment net income (loss)		1,171		87		—			1,258		70		—			1,328
Total assets at December 31, 2004	$	33,524	$	2,067	$	(103	)	$	35,488	$	1,996	$	(522	)	$	36,962


	Electric Utilities Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)

Three Months Ended September 30, 2005	$	3,672	$	506	$	111	$	4,289
Three Months Ended September 30, 2004		2,915		343		100		3,358

Nine Months Ended September 30, 2005	$	8,496	$	1,238	$	321	$	10,055
Nine Months Ended September 30, 2004		7,537		1,038		287		8,862


(c)1	-	By-laws of Georgia Power as amended effective August 17, 2005, and as presently in effect. (Designated in Form 8-K dated August 17, 2005, File No. 1-6468 as Exhibit 3(c)2.)

Gulf Power

(d)1	-	Amended and restated Articles of Incorporation of Gulf Power effective as of November 2, 2005. (Designated in Form 8-K dated October 27, 2005, File No. 0-2429 as Exhibit 3.1.)

(d)2	-	By-laws of Gulf Power as amended effective as of November 2, 2005, and as presently in effect. (Designated in Form 8-K dated October 27, 2005, File No. 0-2429 as Exhibit 3.2.)

(4) Instruments Describing Rights of Security Holders, Including Indentures

Gulf Power

(d)1	-	Twelfth Supplemental Indenture dated as of August 30, 2005 to Senior Note Indenture dated as of January 1, 1998 between Gulf Power and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee. (Designated in Form 8-K dated August 11, 2005, File No. 0-2429 as Exhibit 4.1.)

(10) Material Contracts

Mississippi Power

(e)1	-	Credit Agreement, dated as of October 20, 2005, by and among Mississippi Power and the Lenders named therein. (Designated in Form 8-K dated October 20, 2005, File No. 001-11229 as Exhibit 10.1.)

(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, 2004, 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, 2004, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)

Georgia Power

(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2004, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)

(c)2	-	Power of Attorney for Cliff S. Thrasher. (Designated in the Form 10-Q for the quarter ended March 31, 2005, File No. 1-6468 as Exhibit 24(c)2 and incorporated herein by reference.)


(c)2	-	Certificate of Georgia Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Gulf Power

(d)1	-	Certificate of Gulf Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(d)2	-	Certificate of Gulf Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Mississippi Power

(e)1	-	Certificate of Mississippi Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(e)2	-	Certificate of Mississippi Power’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Savannah Electric

(f)1	-	Certificate of Savannah Electric’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(f)2	-	Certificate of Savannah Electric’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

Southern Power

(g)1	-	Certificate of Southern Power’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(g)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.


(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.

Savannah Electric

(f)	-	Certificate of Savannah Electric’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Southern Power

(g)	-	Certificate of Southern Power’s Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.


		THE SOUTHERN COMPANY

By		David M. Ratcliffe
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

By		Thomas A. Fanning
		Executive Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

By		/s/ Wayne Boston

		(Wayne Boston, Attorney-in-fact)


		ALABAMA POWER COMPANY

By		Charles D. McCrary
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Art P. Beattie
		Executive Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

By		/s/ Wayne Boston

		(Wayne Boston, Attorney-in-fact)


		GEORGIA POWER COMPANY

By		Michael D. Garrett
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Cliff S. Thrasher
		Executive Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

By		/s/ Wayne Boston

		(Wayne Boston, Attorney-in-fact)


		GULF POWER COMPANY

By		Susan N. Story
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Ronnie R. Labrato
		Vice President, Chief Financial Officer and Comptroller
		(Principal Financial and Accounting Officer)

By		/s/ Wayne Boston

		(Wayne Boston, Attorney-in-fact)


		MISSISSIPPI POWER COMPANY

By		Anthony J. Topazi
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Frances V. Turnage
		Vice President, Treasurer and Chief Financial Officer
		(Principal Financial Officer)

By		/s/ Wayne Boston

		(Wayne Boston, Attorney-in-fact)


		SAVANNAH ELECTRIC AND POWER COMPANY

By		A. R. James
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Kirby R. Willis
		Vice President, Treasurer, Chief Financial
		Officer and Assistant Corporate Secretary
		(Principal Financial and Accounting Officer)

By		/s/ Wayne Boston

		(Wayne Boston, Attorney-in-fact)


		SOUTHERN POWER COMPANY

By		Ronnie L. Bates
		President and Chief Executive Officer
		(Principal Executive Officer)

By		Michael W. Southern
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)
By		/s/ Wayne Boston

		(Wayne Boston, Attorney-in-fact)