UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

For the Fiscal Year Ended December 31, 2005

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

For the Transition Period from      to

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

Securities registered pursuant to Section 12(b) of the Act:¹

Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is listed on the New York Stock Exchange.

	Title of each class
	Common Stock, $5 par value
	Mandatorily redeemable preferred securities, $25 liquidation amount
	7.125% Trust Preferred Securities2

Securities registered pursuant to Section 12(g) of the Act: None

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No  o

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ___No þ

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No  o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

Large accelerated filer þ                      Accelerated filer o                      Non-accelerated filer o

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

     Aggregate market value of The Southern Company’s common stock held by non-affiliates of The Southern Company at June 30, 2005: $25.9 billion. The number of outstanding shares of The Southern Company’s common stock, Par Value $5 Per Share, at January 31, 2006 was 741,738,001 shares.

     Documents incorporated by reference: specified portions of The Southern Company’s Proxy Statement relating to the 2006 Annual Meeting of Stockholders are incorporated by reference into PART III.

 

 

On February 27, 2006, The Southern Company (Southern Company) and its registrant subsidiaries, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Savannah Electric and Power Company and Southern Power Company, filed combined Annual Reports on Form 10-K for the year ended December 31, 2005 (Form 10-K). Subsequent to the filing, an omission was identified in a table entitled “Contractual Obligations” located in 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. The principal amount of long-term debt for years “After 2010” was inadvertently omitted from the first line of the table. This amount should have been “$10,065 (in millions)” resulting in total Long-term debt - Principal of “$13,766 (in millions)” and a total amount of all Contractual Obligations “After 2010” of “$25,567 (in millions)” and total Contractual Obligations of “$56,199 (in millions).” The corrected table is set forth on page II-36 of Item 7, MANAGEMENT’S DISCUSSION AND ANALYSIS, which is included in its entirety in this Form 10-K/A. Except as discussed in this Explanatory Note, no other changes have been made to the Form 10-K. The omission does not affect any individual registrant subsidiary information and this Form 10-K/A for Southern Company does not amend the Form 10-K of any individual registrant subsidiary.

ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2005 Annual Report

OVERVIEW

Business Activities

The primary business of Southern Company (the Company) is 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 constructs, owns, and manages Southern Company’s competitive generation assets and sells electricity at market-based rates in the wholesale market.

     Many factors affect the opportunities, challenges, and risks of Southern Company’s electricity business. 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 rising costs. These costs include those related to growing demand, increasingly stringent environmental standards, fuel prices, and storm restoration following multiple hurricanes. Since the beginning of 2004, each of the retail operating companies completed successful retail rate proceedings. These regulatory actions are expected to benefit future earnings stability and enable the recovery of substantial capital investments to facilitate the continued reliability of the transmission and distribution network and to continue environmental improvements at the generating plants. Appropriately balancing environmental expenditures with customer prices will continue to challenge the Company for the foreseeable future. In addition, Georgia Power, Gulf Power, and Mississippi Power expect further rate proceedings in 2006 as necessary to address fuel and storm damage cost recovery.

     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. Southern Power continued executing its regional strategy in 2005 by signing several wholesale contracts with major utilities, as well as with cooperatives and municipal suppliers in the Southeast. However, the Company continues to face regulatory challenges related to transmission and market power issues at the national level.

     Southern Company’s other business activities include investments in synthetic fuel producing entities, which claim federal income tax credits that offset their operating losses, leveraged lease projects, telecommunications, and energy-related services. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions and dispositions accordingly. In January 2006, the sale of the Company’s natural gas marketing business was completed.

Key Performance Indicators

In striving to maximize shareholder value while providing cost-effective energy to more than 4 million customers, Southern Company continues to focus on several key indicators. These indicators include customer satisfaction, plant availability, system reliability, and earnings per share (EPS). Southern Company’s financial success is directly tied to the satisfaction of its customers. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the Company’s results.

     Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. Peak Season EFOR performance excludes the impact of hurricanes and certain outage events caused by manufacturer defects. The 2005 Peak Season EFOR performance was slightly below target (as shown in the chart below) primarily due to an outage event at a combined cycle unit. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance, expected weather conditions, and expected capital expenditures. The 2005 performance was above target on these reliability measures. EPS is the measure for Southern Company’s efforts to increase returns to shareholders through average long-term earnings per share growth of 5 percent.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

     Southern Company’s 2005 results compared with its targets for some of these key indicators are reflected in the following chart:

	Key Performance			2005 Target			2005 Actual
	Indicator			Performance			Performance
	Customer Satisfaction			Top quartile in customer surveys			Top quartile
	Peak Season EFOR			2.75% or less			2.83%
	EPS			$2.04 - $2.09			$2.14

     See RESULTS OF OPERATIONS herein for additional information on the Company’s financial performance. The strong financial performance achieved in 2005 reflects the continued emphasis that management places on these indicators as well as the commitment shown by employees in achieving or exceeding management’s expectations.

Earnings

Southern Company’s financial performance in 2005 remained strong, despite the challenges of rising costs and major hurricanes. Net income was $1.59 billion in 2005, an increase of 3.8 percent over the prior year. Net income was $1.53 billion in 2004 and $1.47 billion in 2003, reflecting increases over the prior year of 4.0 percent and 11.8 percent, respectively. Basic EPS, including discontinued operations, was $2.14 in 2005, $2.07 in 2004, and $2.03 in 2003. Diluted EPS, which factors in additional shares related to stock options, was 1 cent lower than basic EPS each year.

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $1.475 in 2005, $1.415 in 2004, and $1.385 in 2003. In January 2006, Southern Company declared a quarterly dividend of 37.25 cents per share. This is the 233rd consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. The Company’s goal for the dividend payout ratio is to achieve and maintain a payout of approximately 70 percent of net income, excluding earnings from synthetic fuel businesses. For 2005, the actual payout ratio was 73 percent excluding synthetic fuel earnings, and 69 percent overall.

RESULTS OF OPERATIONS

Electricity Businesses

Southern Company’s electric utilities generate and sell electricity to retail and wholesale customers in the Southeast. A condensed income statement for the electricity business is as follows:

						Increase (Decrease)
		Amount				from Prior Year
		2005				2005				2004				2003
		(in millions)
Electric operating revenues		$	13,278			$	1,813			$	718			$	541
Fuel			4,488				1,089				400				213
Purchased power			731				88				170				24
Other operation and maintenance			3,220				215				148				105
Depreciation and amortization			1,137				229				(64	)			(16	)
Taxes other than income taxes			676				52				40				29
Total electric operating expenses			10,252				1,673				694				355
Operating income			3,026				140				24				186
Other income, net			62				38				22				20
Interest expenses			676				62				19				10
Income taxes			899				24				30				68
Net income		$	1,513			$	92			$	(3	)		$	128

Revenues

Details of electric operating revenues are as follows:

		2005				2004				2003
						(in millions)
Retail — prior year		$	9,732			$	8,875			$	8,728
Change in –
Base rates			236				41				75
Sales growth			184				216				104
Weather			34				48				(135	)
Fuel and other cost recovery clauses			979				552				103
Retail current year			11,165				9,732				8,875
Sales — for resale			1,667				1,341				1,358
Other electric operating revenues			446				392				514
Electric operating revenues		$	13,278			$	11,465			$	10,747
Percent change			15.8	%			6.7	%			5.3	%

     Retail revenues increased $1.4 billion in 2005, $857 million in 2004, and $147 million in 2003. The

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

significant factors driving these changes are shown in the preceding table. The increase in base rates in 2005 is primarily due to approval by the Georgia Public Service Commission (PSC) of retail base rate increases at Georgia Power and Savannah Electric. Electric rates for the retail operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased energy costs. Under these provisions, fuel revenues generally equal fuel expenses, including the fuel component of purchased energy, and do not affect net income. Certain of the retail operating companies also have clauses to recover other costs, such as environmental, storm damage, new plants, and/or purchased power agreements (PPAs).

     Sales for resale revenues increased $326 million in 2005, decreased $17 million in 2004, and increased $190 million in 2003. In 2005, sales for resale revenues increased primarily due to a 26.5 percent increase in the average cost of fuel per net kilowatt-hour (KWH) generated. In addition, Southern Company entered into new PPAs with 30 electric membership cooperatives (EMCs) and Flint EMC, both beginning in January 2005, and in June 2005, in connection with the acquisition of Plant Oleander, assumed two PPAs. In 2004, coal and gas prices increased, resulting in a lower marginal price differential that reduced demand. Mild summer weather throughout the Southeast also reduced demand. In 2003, Southern Company entered into several new PPAs with neighboring utilities. In addition, milder weather in Southern Company’s service territory, compared with the rest of the Southeast and combined with higher gas prices, resulted in increases in both customer demand and available generation.

     Southern Company’s average wholesale contract now extends more than 11 years, and as a result, the Company has significantly limited its remarketing risk. Capacity revenues under unit power sales contracts, principally sales to Florida utilities, reflect the recovery of fixed costs and a return on investment, and energy is generally sold at variable cost. Unit power energy sales increased 1.7 percent, 1.9 percent, and 4.0 percent in 2005, 2004, and 2003, respectively. Fluctuations in oil and natural gas prices, which are the primary fuel sources for unit power sales customers, influence changes in these sales. However, because the energy is generally sold at variable cost, these fluctuations have a minimal effect on earnings. The capacity and energy components of the unit power contract revenues were as follows:

		2005				2004				2003
						(in millions)
Unit power –
Capacity		$	201			$	185			$	182
Energy			237				213				211
Total		$	438			$	398			$	393

     Short-term opportunity energy sales are also included in sales for resale. These opportunity sales are made at market-based rates that generally provide a margin above the Company’s variable cost to produce the energy. Revenues associated with opportunity sales and PPAs were as follows:

		2005				2004				2003
						(in millions)
Other power sales –
Capacity and other		$	430			$	308			$	298
Energy			799				635				667
Total		$	1,229			$	943			$	965

     In May 2003, Mississippi Power and Southern Power entered into agreements with Dynegy, Inc. (Dynegy) that terminated all capacity sales contracts with subsidiaries of Dynegy. The termination payments from Dynegy resulted in an increase in other electric revenues of $135 million in 2003.

Energy Sales

Changes in revenues are influenced heavily by the volume of energy sold each year. KWH sales for 2005 and the percent change by year were as follows:

		Amount				Percent Change
(billions of KWH)		2005				2005				2004				2003
Residential			51.1				2.8	%			3.9	%			(1.9	)%
Commercial			51.9				3.6				3.4				0.3
Industrial			55.1				(2.2	)			3.6				1.0
Other			1.0				(0.9	)			0.8				(0.2	)
Total retail			159.1				1.2				3.6				(0.2	)
Sales for resale			37.8				7.3				(13.0	)			24.5
Total			196.9				2.3				0.1				4.2

     Energy sales in 2005 increased 4.5 billion KWH as a result of sustained economic growth and customer growth of 1.2 percent. Hurricane Katrina dampened customer growth from previous years and was the primary contributor to the decrease in industrial sales in 2005. In addition, in 2005, some Georgia Power industrial customers were reclassified from industrial to commercial to be

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies Annual Report

consistent with the rate structure approved by the Georgia PSC resulting in higher commercial sales and lower industrial sales in 2005 when compared with 2004. Energy sales in 2004 were strong across all retail customer classes as a result of an improved economy in the Southeast and customer growth of 1.5 percent. Residential energy sales in 2003 reflected a decrease in customer demand as a result of very mild weather, partially offset by customer growth of 1.6 percent. In 2003, commercial sales continued to show steady growth while industrial sales increased somewhat over the depressed results of previous years. Energy sales to retail customers are projected to increase at a compound average annual rate of 1.9 percent during the period 2006 through 2011, assuming normal weather conditions.

     Energy sales for resale increased by 2.6 billion KWH in 2005, decreased 5.3 billion KWH in 2004, and increased by 8.0 billion KWH in 2003. The increase in sales in 2005 is related primarily to the new PPAs discussed above. The decrease in 2004 as compared with 2003 is due to the increased availability of coal-fired generation in 2003 resulting from weather-related lower retail demand coupled with higher natural gas prices, which increased the wholesale market demand for opportunity sales.

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. The amount and sources of generation, the average cost of fuel per net kilowatt-hour generated, and the average cost of purchased power were as follows:

		2005				2004				2003
Total generation (billions of KWH)			196				188				189
Sources of generation (percent) —
Coal			71				69				71
Nuclear			15				16				16
Gas			11				12				9
Hydro			3				3				4
Average cost of fuel per net KWH generated (cents)			2.39				1.89				1.67
Average cost of purchased power per net KWH (cents)			7.14				4.48				3.86

     In 2005, fuel and purchased power expenses were $5.2 billion, an increase of $1.2 billion or 29.1 percent above the prior year costs. An additional 7.8 billion KWH were generated in 2005 at a 26.5 percent higher average cost per net KWH generated; however, this lowered requirements to purchase even more expensive electricity from non-affiliates.

     Fuel and purchased power expenses were $4.0 billion in 2004, an increase of $570 million or 16.4 percent above 2003 costs. This increase was the result of a 13.2 percent increase in the average cost per net KWH generated and a 16.1 percent increase in the average cost per KWH purchased.

     Fuel and purchased power expenses were $3.5 billion in 2003, an increase of $237 million or 7.3 percent above the prior year costs. This increase was primarily attributed to higher average unit fuel cost and increased customer demand.

     A significant upward trend in the cost of coal and natural gas has emerged since 2003, and volatility in these markets is expected to continue. Increased coal prices have been influenced by a worldwide increase in demand as a result of rapid economic growth in China, as well as by increases in mining costs. Higher natural gas prices in the United States are the result of increased demand and slightly lower gas supplies despite increased drilling activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes result in an immediate market response; however, the long-term impact of this price volatility may be reduced by imports of natural gas and liquefied natural gas. Fuel expenses generally do not affect net income, since they are offset by fuel revenues under the retail operating companies’ fuel cost recovery provisions. Likewise, Southern Power’s PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel.

Other Operation and Maintenance Expenses

Other operation and maintenance expenses were $3.2 billion, $3.0 billion, and $2.9 billion, increasing $215 million, $148 million, and $105 million in 2005, 2004, and 2003, respectively. Other production expenses increased $58 million and $53 million in 2005 and 2004, respectively, and decreased $27 million in 2003. Production expenses fluctuate from year to year due to variations in outage schedules, flexible spending projects, and normal increases in costs.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies Annual Report

     Administrative and general expenses increased $73 million in 2005 related to a $33 million increase in employee benefits, a $22 million increase in shared services expenses, and a $9 million increase in property insurance. Administrative and general expenses increased $106 million in 2004 primarily related to $41 million, $23 million, and $13 million increases in employee benefits, shared services expenses, primarily nuclear security, and property insurance, respectively. In 2003, administrative and general expenses increased $46 million, due primarily to a $19 million increase in property insurance, a $9 million increase in employee benefits, and $9 million of business development costs at Southern Power.

     Transmission and distribution expenses increased $60 million in 2005, $49 million in 2004, and $23 million in 2003. Transmission and distribution expenses increased in 2005 primarily as a result of $48 million of expenses recorded by Alabama Power in accordance with an accounting order approved by the Alabama PSC primarily 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 income taxes to its retail customers; therefore, the combined effect of the accounting order had no impact on net income. See Note 3 to the financial statements under “Storm Damage Cost Recovery” for additional information. Transmission and distribution expenses also fluctuate from year to year due to variations in maintenance schedules, flexible spending projects, and normal increases in costs, and are the primary basis for the 2004 and 2003 increases.

     The 2003 increase in other operation and maintenance expenses also reflects the establishment of a $60 million regulatory liability related to Plant Daniel that was expensed in 2003.

Depreciation and Amortization Expenses

Depreciation and amortization expenses increased $229 million in 2005 as a result of additional plant in service and from the expiration in 2004 of certain provisions in Georgia Power’s retail rate plan for the three years ended 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 over the three years ended December 31, 2004. See Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for additional information.

     Depreciation and amortization expenses declined by $64 million in 2004, primarily as a result of amortization of the Plant Daniel regulatory liability and a Georgia Power regulatory liability related to the levelization of certain purchased power costs that reduced amortization expense by $17 million and $90 million, respectively, from the prior year. See FUTURE EARNINGS POTENTIAL — “PSC Matters — Mississippi Power” herein and Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for more information on these regulatory adjustments. These reductions were partially offset by a higher depreciable plant base.

     The $16 million decrease in depreciation and amortization expenses in 2003 was primarily due to a $49 million reduction in amortization of the previously discussed Georgia Power purchased power regulatory liability and was partially offset by a higher depreciable plant base.

Taxes Other Than Income Taxes

Taxes other than income taxes increased by $52 million in 2005 primarily as a result of increases in franchise and municipal gross receipts taxes associated with increases in revenues from energy sales. In 2004, taxes other than income taxes increased $40 million as a result of additional plant in service and a higher property tax base. Taxes other than income taxes increased $29 million in 2003 as a result of additional generating facilities, as well as higher property tax valuations on existing facilities.

Electric Other Income and (Expense)

Total interest charges and other financing costs increased by $62 million in 2005 associated with an additional $863 million in debt outstanding at December 31, 2005 as compared to December 31, 2004 and an increase in average interest rates on variable rate debt. Variable rates on pollution control bonds are highly correlated with the Bond Market Association Municipal Swap Index which averaged 2.5 percent in 2005 and 1.2 percent in 2004. Variable rates on commercial paper and senior notes are highly correlated with the one-month London Interbank Offer Rate (LIBOR), which averaged 3.4 percent in 2005 and 1.5 percent in 2004. An additional $17 million increase in 2005 was the result of a lower percentage of interest costs

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies Annual Report

capitalized as construction projects reached completion. The $19 million increase in interest charges and other financing costs in 2004 was also the result of a lower percentage of interest costs capitalized as construction projects reached completion.

Other Business Activities

Southern Company’s other business activities include the parent company (which does not allocate operating expenses to business units), investments in synthetic fuels and leveraged lease projects, telecommunications, energy-related services, and natural gas marketing. These businesses are classified in general categories and may comprise one or more of the following subsidiaries: Southern Company Holdings invests in various energy-related projects, including synthetic fuels and leveraged lease projects that receive tax benefits, which contribute significantly to the economic results of these investments; SouthernLINC Wireless provides digital wireless communications services to the retail operating companies and also markets these services to the public within the Southeast; Southern Telecom provides fiber optics services in the Southeast; and Southern Company Gas was a retail gas marketer serving customers in the State of Georgia. On January 4, 2006, Southern Company Gas completed the sale of substantially all of its assets and is reflected in the condensed income statement below as discontinued operations. See Note 3 to the financial statements under “Southern Company Gas Sale” for additional information.

     A condensed income statement for Southern Company’s other business activities follows:

						Increase (Decrease)
		Amount				from Prior Year
		2005				2005				2004				2003
						(in millions)
Operating revenues		$	276			$	12			$	(7	)		$	30
Operation and maintenance			297				12				28				(23	)
Depreciation and amortization			39				(2	)			(9	)			(7	)
Taxes other than income taxes			4				1				1				—
Total operating expenses			340				11				20				(30	)
Operating income			(64	)			1				(27	)			60
Equity in losses of unconsolidated subsidiaries			(123	)			(26	)			3				(8	)
Leveraged lease income			74				4				4				8
Other income, net			(12	)			(5	)			(15	)			9
Interest expenses			101				18				(21	)			6
Income taxes			(304	)			(14	)			(63	)			23
Discontinued operations, net of tax			—				(3	)			12				(12	)
Net income		$	78			$	(33	)		$	61			$	28

     Southern Company’s non-electric operating revenues increased $12 million in 2005 primarily as the result of higher production and increased fees in the synthetic fuel business. The $7 million decrease in 2004 was primarily due to lower operating revenues in the energy-related services business, partially offset by an increase in SouthernLINC Wireless revenues as a result of increased wireless subscribers. The $30 million increase in revenues in 2003 was primarily due to increased sales in the energy-related services business. Revenues from a subsidiary that primarily provides fuel transportation services related to synthetic fuel products were $123 million in 2005, increasing by $17 million, $21 million, and $37 million in 2005, 2004, and 2003, respectively, as a result of increased production at the synthetic fuel facilities and annual increases in rates. Most of these service revenues are ultimately included in the cost of the synthetic fuel purchased by Alabama Power and Georgia Power and, therefore, have no significant effect on Southern Company’s consolidated revenues. See Note 1 to the financial statements under “Related Party Transactions” for additional information.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies Annual Report

     Operation and maintenance expenses for these other businesses increased by $12 million in 2005 as a result of $9 million of higher losses for property damage, $2 million in higher network costs at SouthernLINC Wireless, and a $11 million increase in shared services expenses, offset by the 2004 $12.5 million bad debt reserve discussed below. Operation and maintenance expenses increased $28 million in 2004 primarily due to a $3 million increase in advertising, a $5 million increase in shared services expenses, and a $12.5 million bad debt reserve related to additional federal income taxes and interest Southern Company paid on behalf of Mirant Corporation (Mirant). See FUTURE EARNINGS POTENTIAL — “Mirant Bankruptcy Matters” herein and Note 3 to the financial statements under “Mirant Matters — Mirant Bankruptcy” for additional information. Operation and maintenance expenses decreased by $23 million in 2003 primarily due to a $6 million decrease in shared services expenses and a $3 million decrease in losses for property damage at the parent company; a $4 million decrease in bad debt expense and a $3 million decrease in network costs at SouthernLINC Wireless; and a $2 million decrease in salaries in the energy-related services business.

     Depreciation and amortization expenses decreased $9 million and $7 million in 2004 and 2003, respectively. These reductions are primarily the result of $10 million of expenses associated with the repurchase of debt at Southern Holdings recorded in 2003 and a $16 million charge recorded in 2002 related to the impairment of assets under certain customer contracts for energy-related services.

     The increases in equity in losses of unconsolidated subsidiaries in 2005 and 2003 reflect the results of additional production expenses in the synthetic fuel partnerships. These partnerships also claim federal income tax credits that offset their operating losses and make the businesses profitable. These credits totaled $177 million in 2005, $146 million in 2004, and $120 million in 2003. In 2004, a $37 million reserve related to these tax credits was reversed following the settlement of an Internal Revenue Service (IRS) audit. See FUTURE EARNINGS POTENTIAL — “Income Tax Matters” herein for additional information.

     The decrease in other income in 2004 as compared with 2003 reflects a $15 million gain for a Southern Telecom contract settlement during 2003. The gain in 2003 was partially offset by an increase of $7 million in charitable contributions made by the parent company.

     Total interest charges and other financing costs increased by $18 million in 2005 associated with an additional $283 million in debt outstanding and a 164 basis point increase in average interest rates on variable rate debt. Interest expense decreased $21 million in 2004 as a result of the parent company’s redemption of preferred securities in 2003. This decrease was partially offset by an increase in outstanding long-term debt in 2004.

Effects of Inflation

The retail operating companies and Southern Power are subject to rate regulation and party to long-term contracts, respectively, that are generally based on the recovery of historical costs. In addition, the income tax laws are based on historical costs. Therefore, inflation creates an economic loss because Southern Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on Southern Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed in the retail operating companies’ approved electric rates.

FUTURE EARNINGS POTENTIAL

General

The retail operating companies operate as vertically integrated companies providing electricity to customers within their service areas in the southeastern United States. Prices for electricity provided to retail customers are set by state PSCs under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Company’s wholesale business continues to focus on long-term capacity contracts, optimized by limited energy trading activities. The level of future earnings depends on numerous factors including the FERC’s market-based rate investigation, creditworthiness of customers, total generating capacity available in the Southeast, and the successful remarketing of capacity as current contracts expire. See ACCOUNTING POLICIES — “Application of Critical Accounting Policies and

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Southern Company and Subsidiary Companies Annual Report

Estimates — Electric Utility Regulation” herein and Note 3 to the financial statements for additional information about these and other regulatory matters.

     The results of operations for the past three years are not necessarily indicative of 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 that continues to allow for the recovery of all prudently incurred costs. 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.

     Southern Company system generating capacity increased 1,880 megawatts in 2005 with the completion of Plant McIntosh units 10 and 11 by Georgia Power and Savannah Electric and the acquisition by Southern Power of Plant Oleander. In general, Southern Company has constructed or acquired new generating capacity only after entering into long-term capacity contracts for the new facilities or to meet requirements of Southern Company’s regulated retail markets, both of which are optimized by limited energy trading activities.

     To adapt to a less regulated, more competitive environment, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, acquisitions involving other utility or non-utility businesses or properties, internal restructuring, disposition of certain assets, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations and financial condition of Southern Company.

Environmental Matters

New Source Review Actions

In November 1999, the Environmental Protection Agency (EPA) brought a civil action in the U.S. District Court for the Northern District of Georgia against certain Southern Company subsidiaries, including Alabama Power and Georgia Power, alleging that these subsidiaries had violated the New Source Review (NSR) provisions of the Clean Air Act and related state laws at certain coal-fired generating facilities. Through subsequent amendments and other legal procedures, the EPA added Savannah Electric as a defendant to the original action and filed a separate action against Alabama Power in the U.S. District Court for the Northern District of Alabama after it was dismissed from the original action. In these lawsuits, the EPA alleges that NSR violations occurred at eight coal-fired generating facilities operated by Alabama Power, Georgia Power, and Savannah Electric. The civil actions request penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. On June 3, 2005, the U.S. District Court for the Northern District of Alabama issued a decision in favor of Alabama Power on two primary legal issues in the case; however, the decision does not resolve the case, nor does it address other legal issues associated with the EPA’s allegations. In accordance with a separate court order, Alabama Power and the EPA are currently participating in mediation with respect to the EPA’s claims. The action against Georgia Power and Savannah Electric has been administratively closed since the spring of 2001, and none of the parties has sought to reopen the case. See Note 3 to the financial statements under “Environmental Matters — New Source Review Actions.”

     Southern Company believes that the retail operating companies complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $32,500 per day, per violation at each generating unit, depending on the date of the alleged violation. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and financial

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condition if such costs are not recovered through regulated rates.

     In December 2002 and October 2003, the EPA issued final revisions to its NSR regulations under the Clean Air Act. A coalition of states and environmental organizations filed petitions for review of these regulations. 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. The October 2003 revisions, which clarified the scope of the existing Routine Maintenance, Repair and Replacement exclusion, have been stayed by the Court of Appeals pending its review of the rules. On October 20, 2005, the EPA also published a proposed rule clarifying the test for determining when an emissions increase subject to the NSR requirements has occurred. The impact of these revisions and 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

In July 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under common law public and private nuisance theories, the plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining global warming and (2) requiring each of the defendants to cap its emissions of carbon dioxide and then reduce those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Company’s and the other defendants’ motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit on October 19, 2005. The ultimate outcome of these matters cannot be determined at this time.

Plant Wansley Environmental Litigation

In December 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forestwatch, and one individual filed a civil suit in the U.S. District Court for the Northern District of Georgia against Georgia Power for alleged violations of the Clean Air Act at four of the units at Plant Wansley. The civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project, and attorneys’ fees. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. The liability phase of the case has concluded with the court ruling in favor of Georgia Power in part and the plaintiffs in part. In March 2005, the U.S. Court of Appeals for the Eleventh Circuit accepted Georgia Power’s petition for review of the district court’s order, and oral arguments were held on January 24, 2006. The district court case has been administratively closed pending that appeal. If necessary, the district court will hold a separate trial, which will address civil penalties and possible injunctive relief requested by the plaintiffs.

     The ultimate outcome of this matter cannot currently be determined; however, an adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require the payment of substantial penalties. This could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Environmental Statutes and Regulations

General

Southern Company’s operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; and the Endangered Species Act. Compliance with these environmental requirements

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Southern Company and Subsidiary Companies 2005 Annual Report

involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2005, Southern Company had invested approximately $2.4 billion in capital projects to comply with these requirements, with annual totals of $423 million, $300 million, and $256 million for 2005, 2004, and 2003, respectively. Over the next decade, the Company expects that capital expenditures to assure compliance with existing and new regulations could exceed an additional $7.5 billion, including $0.8 billion, $1.3 billion, and $1.1 billion for 2006, 2007, and 2008, respectively. Because the Company’s compliance strategy is impacted by changes to existing environmental laws and regulations, the cost, availability, and existing inventory of emission allowances, and the Company’s fuel mix, the ultimate outcome cannot be determined at this time. Environmental costs that are known and estimable at this time are included in capital expenditures discussed under FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” herein.

     Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, or other environmental and health concerns could also significantly affect Southern Company. New environmental legislation or regulations, or changes to existing statutes or regulations, could affect many areas of Southern Company’s operations; however, the full impact of any such changes cannot be determined at this time.

Air Quality

Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for Southern Company. Through 2005, the Company had spent approximately $1.6 billion in reducing sulfur dioxide (SO₂) and nitrogen oxide (NO_x) emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been announced and are currently being installed at several plants to further reduce SO₂ and NO_x emissions, maintain compliance with existing regulations, and to meet new requirements.

     Approximately $1.3 billion of these expenditures related to reducing NO_x emissions pursuant to state and federal requirements in connection with the EPA’s one-hour ozone standard and the 1998 regional NO_x reduction rules. In 2004, the regional NO_x reduction rules were implemented for the northern two-thirds of Alabama. Although the State of Georgia was originally included in the states subject to the regional NO_x rules, the EPA, in August 2005, stayed compliance with these requirements and initiated rulemakings to address issues raised in a petition for reconsideration filed by a coalition of Georgia industries. The impact of the 1998 regional NO_x reduction rules for the State of Georgia will depend on the outcome of the petition for reconsideration and/or any subsequent development and approval of its state implementation plan.

     In addition, in 2005, Gulf Power substantially completed the terms of a 2002 agreement with the State of Florida to help ensure attainment of the ozone standard in the Pensacola, Florida area. The conditions of the agreement, which required installing additional controls on certain units and retiring three older units at a plant near Pensacola, will be fully implemented in 2006 at a cost of approximately $134.4 million, of which $4.3 million remains to be spent. Gulf Power’s costs have been approved under its environmental cost recovery clause. See Note 1 to the financial statements under “Environmental Cost Recovery” for additional information.

     In 2005, the EPA revoked the one-hour ozone standard and published the final set of rules for implementation of the new, more stringent eight-hour ozone standard. Areas within Southern Company’s service area that have been designated as nonattainment under the eight-hour ozone standard include Birmingham (Alabama), Macon (Georgia), and a 20-county area within metropolitan Atlanta. State implementation plans, including new emission control regulations necessary to bring those areas into attainment, are required for most areas by June 2007. These state implementation plans could require further reductions in NO_x emissions from power plants.

     In November 2005, the State of Alabama, through the Alabama Department of Environmental Management, submitted a request to the EPA to redesignate the Birmingham eight-hour ozone non-attainment area to attainment for the standard. On January 25, 2006, the EPA published a proposal in the Federal Register to approve the redesignation request. If ultimately approved by the EPA, the area would be designated to be in attainment. The final outcome of this matter cannot now be determined.

     During 2005, the EPA’s fine particulate matter nonattainment designations became effective for several areas within Southern Company’s service area in Alabama and Georgia, and the EPA proposed

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a rule for the implementation of the fine particulate matter standard. The EPA plans to finalize the proposed implementation rule in 2006. State plans for addressing the nonattainment designations are required by April 2008 and could require further reductions in SO₂ and NO_x emissions from power plants. The EPA has also published proposed revisions to lower the levels of particulate matter currently allowed.

     The EPA issued the final Clean Air Interstate Rule on March 10, 2005. This cap-and-trade rule addresses power plant SO₂ and NO_x emissions that were found to contribute to nonattainment of the eight-hour ozone and fine particulate matter standards in downwind states. Twenty-eight eastern states, including each of the states within Southern Company’s service area, are subject to the requirements of the rule. The rule calls for additional reductions of NO_x and/or SO₂ to be achieved in two phases, 2009/2010 and 2015. These reductions will be accomplished by the installation of additional emission controls at Southern Company’s coal-fired facilities or by the purchase of emission allowances from a cap-and-trade program.

     The Clean Air Visibility Rule (formerly called the Regional Haze Rule) was finalized on July 6, 2005. The goal of this rule is to restore natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of Best Available Retrofit Technology (BART) requirements and a review each decade, beginning in 2018, of progress toward the goal. BART requires that sources that contribute to visibility impairment implement additional emission reductions, if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean Air Visibility Rule allows states to determine that the Clean Air Interstate Rule satisfies BART requirements for SO₂ and NO_x. However, additional requirements could be imposed. By December 17, 2007, states must submit implementation plans that contain emission reduction strategies for implementing BART requirements and for achieving sufficient and reasonable progress toward the goal.

     On March 15, 2005, the EPA announced the final Clean Air Mercury Rule, a cap-and-trade program for the reduction of mercury emissions from coal-fired power plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and provides for an emission allowance trading market. The Company anticipates that emission controls installed to achieve compliance with the Clean Air Interstate Rule and the eight-hour ozone and fine-particulate standards will also result in mercury emission reductions. However, the long-term capability of emission control equipment to reduce mercury emissions is still being evaluated, and the installation of additional control technologies may be required.

     The impacts of the eight-hour ozone standard, the fine particulate matter nonattainment designations, the Clean Air Interstate Rule, the Clean Air Visibility Rule, and the Clean Air Mercury Rule on the Company will depend on the development and implementation of rules at the state level. States implementing the Clean Air Mercury Rule and the Clean Air Interstate Rule, in particular, have the option not to participate in the national cap-and-trade programs and could require reductions greater than those mandated by the federal rules. Such impacts will also depend on resolution of pending legal challenges to the Clean Air Interstate Rule, the Clean Air Mercury Rule and a related petition from the State of North Carolina under Section 126 of the Clean Air Act, also related to the interstate transport of air pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at this time. The Company has developed and continually updates a comprehensive environmental compliance strategy to comply with the continuing and new environmental requirements discussed above. As part of this strategy, the Company plans to install additional SO₂, NO_x, and mercury emission controls within the next several years to assure continued compliance with applicable air quality requirements.

Water Quality

In July 2004, the EPA published final rules under the Clean Water Act for the purpose of reducing impingement and entrainment of fish and fish larvae at power plants’ cooling water intake structures. The new rules require baseline biological information and, perhaps, installation of fish protection technology near some intake structures at existing power plants.

     Georgia Power is installing cooling towers at additional facilities under the Clean Water Act to cool water prior to discharge. Near Atlanta, a cooling tower for one plant was completed in 2004 and two others are scheduled for completion in 2008. The total estimated cost of these projects is $173 million, with $85 million remaining to be spent.

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Georgia Power is also conducting a study of the aquatic environment at another facility to determine if further thermal controls are necessary at that plant.

     The full impact of these new rules will depend on the results of studies and analyses performed as part of the rules’ implementation and the actual requirements established by state regulatory agencies, and therefore, cannot now be determined.

Environmental Remediation

Southern Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and release of hazardous substances. Under these various laws and regulations, the retail operating companies could incur substantial costs to clean up properties. The retail operating companies conduct studies to determine the extent of any required cleanup and have recognized in their respective financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The retail operating companies may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under “Environmental Matters — Environmental Remediation” for additional information.

Global Climate Issues

Domestic efforts to limit greenhouse gas emissions have been spurred by international discussions surrounding the Framework Convention on Climate Change and specifically the Kyoto Protocol, which proposes constraints on the emissions of greenhouse gases for a group of industrialized countries. The Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other mandatory carbon dioxide reduction legislation; however, in 2002, it did announce a goal to reduce the greenhouse gas intensity of the U.S., the ratio of greenhouse gas emissions to the value of U.S. economic output, by 18 percent by 2012. A year later, the Department of Energy (DOE) announced the Climate VISION program to support this goal. Energy-intensive industries, including electricity generation, are the initial focus of this program. Southern Company is involved in the development of a voluntary electric utility sector climate change initiative in partnership with the government. In a memorandum of understanding signed in December 2004 with the DOE under Climate VISION, the utility sector pledged to reduce its greenhouse gas emissions rate by 3 percent to 5 percent by 2010- 2012. The Company is continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is analyzing voluntary programs to support the industry initiative.

FERC Matters

Market-Based Rate Authority

Each of the retail operating companies and Southern Power has authorization from the Federal Energy Regulatory Commission (FERC) to sell power to non-affiliates at market-based prices. 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.

     In December 2004, the FERC initiated a proceeding to assess Southern Company’s generation dominance within its retail service territory. The ability to charge market-based rates in other markets is not an issue in that proceeding. In February 2005, Southern Company submitted responsive information. In February 2006, the FERC suspended the proceeding to allow the parties to conduct settlement discussions. Any new market-based rate transactions in its retail service territory entered into after February 27, 2005 are subject to refund to the level of the default cost-based rates, pending the outcome of the proceeding. The impact of such sales through December 31, 2005 is not expected to exceed $16 million. The refund period covers 15 months. In the event that the FERC’s default mitigation measures for entities that are found to have market power 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 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.

     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

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expanded investigation. Any and all new market-based rate transactions both inside and outside Southern Company’s retail service territory 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 15-month refund period beginning July 19, 2005. The impact of such sales through December 31, 2005 is not expected to exceed $31 million, of which $11 million relates to sales inside the retail service territory discussed above. The FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Intercompany Interchange Contract (IIC) discussed below.

     Southern Company and its subsidiaries believe that there is no meritorious basis for this proceeding and are vigorously defending themselves in this matter. 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

The Company’s generation fleet in its retail service territory is operated under the IIC, as approved by the FERC. In May 2005, the FERC initiated a new proceeding to examine (1) the provisions of the IIC among 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 proceeding involving approval of PPAs between Southern Power and 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. Hearings are scheduled for September 2006. Effective July 19, 2005, revenues from transactions under the IIC involving any Southern Company subsidiaries are 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 this proceeding and are vigorously defending themselves in this matter. 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.

Generation Interconnection Agreements

In July 2003, the FERC issued its final rule on the standardization of generation interconnection agreements and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from the generator to the transmission provider. 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. These proceedings are still pending at the FERC. Southern Company has also received similar requests from other entities totaling approximately $14 million. Southern Company has opposed all such requests. 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.

Transmission

In December 1999, the FERC issued its final rule on Regional Transmission Organizations (RTOs). Since that time, there have been a number of additional proceedings at the FERC designed to encourage further voluntary formation of RTOs or to mandate their formation. However, at the current time, there are no active proceedings that would require Southern Company to participate in an RTO. Current FERC efforts that may potentially change the regulatory and/or operational structure of transmission include rules related to the standardization of generation interconnection, as well as an inquiry into, among other things, market power by vertically integrated utilities. See “Market-Based Rate Authority” and “Generation Interconnection Agreements” above for additional

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Southern Company and Subsidiary Companies 2005 Annual Report

information. The final outcome of these proceedings cannot now be determined. However, Southern Company’s financial condition, results of operations, and cash flows could be adversely affected by future changes in the federal regulatory or operational structure of transmission.

PSC Matters

Alabama Power

In October 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 approximately 1 percent in both January 2005 and 2006. In conjunction with the Alabama PSC’s approval of this rate mechanism, Alabama Power agreed to a moratorium until 2007 on any retail rate increase under its previously approved Rate Stabilization and Equalization Plan (Rate RSE).

     On October 4, 2005, the Alabama PSC approved a revision to Rate RSE requested by Alabama Power. Effective January 2007, Rate RSE adjustments 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 percent per year and any annual adjustment is limited to 5 percent. Rates will remain unchanged if the return on equity (ROE) is between 13 percent and 14.5 percent. If Alabama Power’s actual retail ROE 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.

     See Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” for further information.

Georgia Power

In December 2004, the Georgia PSC approved the December 2004 three-year retail rate plan ending December 31, 2007 (2004 Retail Rate Plan) for Georgia Power. Under the terms of the 2004 Retail Rate Plan, earnings will be evaluated against a retail ROE range of 10.25 percent to 12.25 percent. Two-thirds of any earnings above 12.25 percent will be applied to rate refunds, with the remaining one-third retained by Georgia Power. Retail rates and customer fees were increased by approximately $203 million in January 2005 to cover the higher costs of purchased power, operation and maintenance expenses, environmental compliance, and continued investment in new generation, transmission, and distribution facilities to support growth and ensure reliability.

     Georgia Power is required to file a general rate case on or about July 1, 2007, in response to which the Georgia PSC would be expected to determine whether the 2004 Retail Rate Plan should be continued, modified, or discontinued. Until then, Georgia Power may not file for a general base rate increase unless its projected retail return on common equity falls below 10.25 percent. See Note 3 to the financial statements under “Georgia Power Retail Regulatory Matters” for additional information.

     On December 13, 2005, Georgia Power and Savannah Electric entered into a merger agreement. Savannah Electric will merge into Georgia Power, with Georgia Power continuing as the surviving corporation. Pending regulatory approvals, the merger is expected to occur by July 2006. See “Fuel Cost Recovery” herein and Note 3 to the financial statements under “Merger of Georgia Power and Savannah Electric” for additional information.

Mississippi Power

On December 1, 2005, Mississippi Power submitted its annual Performance Evaluation Plan (PEP) filing to the Mississippi PSC. Ordinarily, PEP limits annual rate increases to 4 percent; however, Mississippi Power has requested that the Mississippi PSC approve a temporary change to allow it to exceed this cap as a result of the ongoing effects of Hurricane Katrina. Mississippi Power has requested a 5 percent, or $32 million, retail base rate increase to become effective in April 2006 if approved. Hearings are scheduled for March 2, 2006.

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     In May 2004, the Mississippi PSC approved Mississippi Power’s request to reclassify to jurisdictional cost of service the 266 megawatts of Plant Daniel unit 3 and 4 capacity, effective January 1, 2004. The Mississippi PSC authorized Mississippi Power to include the related costs and revenue credits in jurisdictional rate base, cost of service, and revenue requirement calculations for purposes of retail rate recovery. Mississippi Power is amortizing the regulatory liability established pursuant to the Mississippi PSC’s interim December 2003 order, as approved in May 2004, to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006, and $5.7 million in 2007, resulting in expense reductions in each of those years.

Fuel Cost Recovery

The retail operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Over the past year, the retail operating companies have continued to experience higher than expected fuel costs for coal and natural gas. These higher fuel costs have increased the under recovered fuel costs included in the balance sheets. The retail operating companies continuously monitor the under recovered fuel cost balance in light of these higher fuel costs. Each of the retail operating companies received approval in 2005 to increase their fuel cost recovery factors to recover existing under recovered amounts as well as projected future costs.

     Alabama Power fuel costs are recovered under Rate ECR (Energy Cost Recovery), which provides for the addition of a fuel and energy cost factor to base rates. In December 2005, the Alabama PSC approved an increase that allows for the recovery of approximately $227 million in existing under recovered fuel costs over a two-year period.

     In May 2005, the Georgia PSC approved Georgia Power’s request to increase customer fuel rates by approximately 9.5 percent to recover under recovered fuel costs of approximately $508 million existing as of May 31, 2005 over a four-year period that began June 1, 2005. Under recovered fuel amounts for the period subsequent to June 1, 2005 totaled $327.5 million through December 31, 2005. The Georgia PSC’s order instructs that such amounts be reviewed semi-annually beginning February 2006. If the amount under or over recovered exceeds $50 million at the evaluation date, Georgia Power would be required to file for a temporary fuel rate change. In addition, Savannah Electric’s under recovered fuel costs totaled $77.7 million at December 31, 2005. In accordance with a Georgia PSC order, Savannah Electric was scheduled to file an additional request for a fuel cost recovery increase in January 2006. In connection with the proposed merger, Georgia Power has agreed with a Georgia PSC staff recommendation to forego the temporary fuel rate process, and Savannah Electric has postponed its scheduled filing. Instead, Georgia Power and Savannah Electric will file a combined request in March 2006 to increase its fuel cost recovery rate.

     The case will seek approval of a fuel cost recovery rate based upon future fuel cost projections for the combined Georgia Power and Savannah Electric generating fleet as well as the under recovered balances existing at June 30, 2006. The new fuel cost recovery rate would be billed beginning in July 2006 to all Georgia Power customers, including the existing Savannah Electric customers. Under recovered amounts as of the date of the merger will be paid by the appropriate customer groups.

     In August 2005, the Georgia PSC initiated an investigation of Savannah Electric’s fuel practices. In February 2006, an investigation of Georgia Power’s fuel practices was initiated. Georgia Power and Savannah Electric are responding to data requests and cooperating in the investigations. The final outcome of these matters cannot now be determined.

     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 the Company’s revenues or net income, but would increase annual cash flow. Based on their respective state PSC orders, a portion of the under recovered regulatory clause revenues for Alabama Power, Georgia Power, and Savannah Electric was reclassified from current assets to deferred charges and other assets in the balance sheet. See Note 1 to the financial statements under “Revenues” and Note 3 to the financial statements under “Alabama Power Retail Regulatory Matters” and “Georgia Power Retail Regulatory Matters” for additional information.

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Storm Damage Cost Recovery

Each retail operating company maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution facilities and the cost of uninsured damages to its generation facilities and other property. In September 2004, Hurricane Ivan hit the Gulf Coast of Florida and Alabama and continued north through Southern Company’s service territory causing substantial damage.

     At Gulf Power, the related costs charged to its property damage reserve as of December 31, 2004 were $93.5 million. Prior to Hurricane Ivan, Gulf Power’s reserve balance was approximately $28 million. Gulf Power’s current annual accrual to the property damage reserve, as approved by the Florida PSC, is $3.5 million. The Florida PSC has also approved additional accrual amounts at Gulf Power’s discretion; Gulf Power accrued an additional $6 million and $15 million in 2005 and 2004, respectively. In February 2005, Gulf Power, the Office of Public Counsel for the State of Florida, and the Florida Industrial Power Users Group filed a Stipulation and Settlement with the Florida PSC, which the Florida PSC subsequently approved, allowing Gulf Power to recover the retail portion of $51.7 million of these costs, plus interest and revenue taxes, from customers over a 24-month period that 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.

     At Alabama Power, operation and maintenance expenses associated with repairing the damage to its facilities and restoring service to customers as a result of Hurricane Ivan were $57.8 million for 2004. The balance in Alabama Power’s natural disaster reserve prior to the storm was $14.6 million. In October 2004, Alabama Power received approval from the Alabama PSC to defer the negative balance for recovery in future periods. Alabama Power is allowed to accrue $250,000 per month until a maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below $22.4 million. During 2004, Alabama Power accrued an additional $6.9 million.

     In February and December 2005, Alabama Power requested and received Alabama PSC approval of accounting orders that allowed Alabama Power to immediately return certain regulatory liabilities to the retail customers. These orders also allowed Alabama Power to simultaneously recover from customers accruals of approximately $48 million primarily to offset the costs of Hurricane Ivan and restore a positive balance in the natural disaster reserve. The combined effect of these orders had no impact on net income in 2005.

     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 the service areas of Alabama Power, Gulf Power, and Mississippi Power. The total incremental cost of repairing the damages to Mississippi Power’s facilities and restoring service to customers is currently estimated to be approximately $277 million net of approximately $68 million of insurance proceeds. Prior to Hurricane Katrina, Mississippi Power had a balance of approximately $3 million in its property reserve. Incremental costs incurred through December 31, 2005 were $210 million net of insurance proceeds of $68 million, of which $8 million has been received. These costs include approximately $149 million of capital additions and $133 million of operation and maintenance expenditures. 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 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 December 31, 2005, the deficit balance in Southern Company’s storm damage reserve accounts totaled approximately $366 million, of which approximately $70 million and $296 million, respectively, is included in the balance sheets herein under Other Current Assets and Other Regulatory Assets. The recovery of these deferred

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

costs is subject to the approval of the respective state PSCs.

     In December 2005, the Alabama PSC approved a separate rate rider to recover Alabama Power’s $51 million of deferred Hurricane Dennis and Katrina operation and maintenance costs over a two-year period and to replenish its reserve to a target balance of $75 million over a five-year period.

     In October 2005, the Mississippi PSC issued an Interim Accounting Order requiring Mississippi Power to recognize a regulatory asset in an amount equal to the retail portion of the recorded Hurricane Katrina restoration costs, including both operation and maintenance expenditures and capital additions. In December 2005, Mississippi Power filed with the Mississippi PSC a detailed review of all Hurricane Katrina restoration costs as required in the Interim Accounting Order. Mississippi Power is currently working with the Mississippi PSC to establish a method to recover all such prudently incurred costs upon resolution of uncertainties related to federal grant assistance and proposed state legislation to allow securitized financing.

     In 2005, the Florida Legislature authorized securitized financing for hurricane costs. On February 22, 2006, Gulf Power filed a petition with the Florida PSC under this legislative authority requesting permission to issue $87.2 million in securitized storm-recovery bonds. The bonds would be repaid over 8 years from revenues to be received from storm-recovery charges implemented under the securitization plan and billed to customers. If approved as proposed, the plan would resolve Gulf Power’s remaining deferred costs, by refinancing, net of taxes, the remaining balance of storm damage costs currently being recovered from customers related to Hurricane Ivan and financing, net of taxes, restoration costs associated with Hurricanes Dennis and Katrina of approximately $54 million. It would also replenish Gulf Power’s property damage reserve with an additional $70 million. A decision on the plan is expected prior to the end of the second quarter of 2006. Since Gulf Power will recognize expenses equal to the revenues billed to customers, the securitization plan would have no impact on net income, but would increase cash flow.

     See Notes 1 and 3 to the financial statements under “Storm Damage Reserves” and “Storm Damage Cost Recovery,” respectively, for additional information on these reserves. The final outcome of these matters cannot now be determined.

Mirant Bankruptcy Matters

Mirant is an energy company with businesses that include independent power projects and energy trading and risk management companies in the U.S. and selected other countries. It was a wholly-owned subsidiary of Southern Company until its initial public offering in October 2000. In April 2001, Southern Company completed a spin-off to its shareholders of its remaining ownership and Mirant became an independent corporate entity.

     In July 2003, Mirant filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code. In January 2006, Mirant’s plan of reorganization became effective, and Mirant emerged from bankruptcy. As part of the plan, Mirant transferred substantially all of its assets and its restructured debt to a new corporation that adopted the name Mirant Corporation (Reorganized Mirant). Southern Company has certain contingent liabilities associated with guarantees of contractual commitments made by Mirant’s subsidiaries discussed in Note 7 to the financial statements under “Guarantees.”

     In December 2004, as a result of concluding an IRS audit for the tax years 2000 and 2001, Southern Company paid $39 million in additional tax and interest for issues related to Mirant tax items. Under the terms of the separation agreements entered into in connection with the spin-off, Mirant agreed to indemnify Southern Company for costs associated with these tax items and additional IRS assessments. However, as a result of Mirant’s bankruptcy, Southern Company sought reimbursement as an unsecured creditor in the Chapter 11 proceeding. Based on management’s assessment of the collectibility of this receivable, Southern Company has reserved approximately $12.5 million. If Southern Company is ultimately required to make any additional payments, Mirant’s indemnification obligation to Southern Company for these additional payments would constitute unsecured claims against Mirant, entitled to stock in Reorganized Mirant, the value of which is uncertain. See Note 3 to the financial statements under “Mirant Matters – Mirant Bankruptcy.”

     In June 2005, Mirant, as a debtor in possession, and The Official Committee of Unsecured Creditors of Mirant Corporation filed a complaint against

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

Southern Company in the U.S. Bankruptcy Court for the Northern District of Texas, which was amended in July 2005 and February 2006. The complaint alleges that Southern Company caused Mirant to engage in certain fraudulent transfers and to pay illegal dividends to Southern Company prior to the spin-off. The 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 and that Southern Company caused Mirant to breach its fiduciary duties to 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 relate to reimbursement under the separation agreements of payments such as income taxes, interest, legal fees, and other guarantees described in Note 7 to the financial statements) and seeks equitable subordination of Southern Company’s claims to the claims of all other creditors. Southern Company served an answer to the second amended complaint in February 2006. Also in February 2006, the Company’s motion to transfer the case to the U.S. District Court for the Northern District of Georgia was granted. Southern Company believes there is no meritorious basis for the claims in the complaint and is vigorously defending itself in this action. See Note 3 to the financial statements under “Mirant Matters – Mirant Bankruptcy Litigation” for additional information. The ultimate outcome of these matters cannot be determined at this time.

Income Tax Matters

Leveraged Lease Transactions

Southern Company undergoes audits by the IRS for each of its tax years. The IRS has completed its audits of Southern Company’s consolidated federal income tax returns for all years through 2001. Southern Company participates in four international leveraged lease transactions and receives federal income tax deductions for depreciation and amortization, as well as interest on related debt. The IRS proposed to disallow the tax losses for one of these leases (a lease-in-lease-out, or LILO) in connection with its audit of 1996 through 2001. In October 2004, Southern Company submitted the issue to the IRS appeals division and in February 2005 reached a negotiated settlement with the IRS, which is subject to final approval.

     In connection with its audit of 2000 and 2001, the IRS also challenged Southern Company’s deductions related to three other international lease (sale-in-lease-out, or SILO) transactions. If the IRS is ultimately successful in disallowing the tax deductions related to these three transactions, beginning with the 2000 tax year, Southern Company would be subject to additional interest charges of up to $34 million. The IRS has also proposed a penalty of approximately $16 million. 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 and expects to litigate the issue if necessary. Although the payment of the tax liability, exclusive of interest, would not affect Southern Company’s results of operations under current accounting standards, it could have a material impact on cash flow. Through December 31, 2005, Southern Company has claimed $241 million in tax benefits related to these SILO transactions challenged by the IRS. See Note 1 to the financial statements under “Leveraged Leases” for additional information.

     Under current accounting rules, the settlement of the LILO transaction will not have a material impact on Southern Company’s financial statements; however, the Financial Accounting Standards Board (FASB) has proposed changes to the accounting for leveraged leases that are expected to become effective in 2006. If approved as proposed, these changes could require Southern Company to reflect the tax deductions that the IRS is challenging as currently payable in the balance sheet and to change the timing of income recognized for the leases, including a cumulative effect upon adoption of the change. For the LILO transaction settled with the IRS in February 2005, Southern Company estimates such cumulative effect would reduce Southern Company’s net income by up to $16 million. The impact of these proposed changes related to the SILO transactions would be dependent on the resolution of these matters 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

Southern Company has investments in two entities that produce synthetic fuel and receive tax credits under Section 45K (formerly Section 29) of the Internal Revenue Code of 1986, as amended

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

(Internal Revenue Code). In accordance with Section 45K of the Internal Revenue Code, 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 result in an impairment of these investments, which total approximately $19.5 million at December 31, 2005, by Southern Company.

Construction Projects

Integrated Coal Gasification Combined Cycle

In December 2005, Southern Power and the Orlando Utilities Commission (OUC) executed definitive agreements for development of an integrated coal gasification combined cycle (IGCC) 283-megawatt project in Orlando, Florida. The definitive agreements provide that Southern Power will own at least 65 percent of the gasifier portion of the IGCC project. OUC will own the remainder of the gasifier portion and 100 percent of the combined cycle portion of the IGCC project. OUC will purchase all of the gasifier capacity from Southern Power once the plant is in commercial operation. Southern Power will construct the project and manage its operation after construction is completed. In February 2006, Southern Power signed a cooperative agreement with the DOE that provides up to $235 million in grant funding for the gasification portion of this project. The IGCC project is subject to National Environmental Policy Act review as well as state environmental review, requires certain regulatory approvals, and is expected to begin commercial operation in 2010. Southern Power’s total cost related to the IGCC project is estimated at approximately $121 million.

Plant Franklin Unit 3

In August 2004, Southern Power completed limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project. Final completion is not anticipated until the 2008-2011 period. See Note 3 to the financial statements under “Plant Franklin Construction Project” for additional information. The final outcome of this matter cannot now be determined.

Nuclear

As part of a potential expansion of Plant Vogtle, Georgia Power and Southern Nuclear have notified the Nuclear Regulatory Commission (NRC) of their intent to apply for an early site permit (ESP) this year and a combined construction and operating license (COL) in 2008. In addition, a reactor design from Westinghouse Electric Company has been selected and a purchase agreement is being negotiated. Participation agreements have been reached with each of the existing Plant Vogtle co-owners. See Note 4 to the financial statements for additional information on these co-owners. At this point, no final decision has been made regarding actual construction. The NRC’s streamlined licensing process for new nuclear units allows utilities to seek regulatory approval at various stages. These stages include design certification, which is obtained by the reactor vendor, and the ESP and COL, which are each obtained by the owner-operators of the units. An ESP indicates site approval is obtained before a company decides to build and the COL provides regulatory approval for building and operating the plant. In addition, any new Georgia Power generation must be certified by the Georgia PSC.

     Southern Company also is participating in NuStart Energy Development, LLC (NuStart Energy), a broad-based nuclear industry consortium formed to share the cost of developing a COL and the related NRC review. NuStart Energy plans to complete detailed engineering design work and to prepare COL applications for two advanced reactor designs, then to choose one of the applications and file it for NRC review and approval. The COL ultimately is expected to be transferred to one or more of the consortium companies; however, at this time, none of them have committed to build a new nuclear plant.

     Southern Company is also exploring other possibilities relating to nuclear power projects, both on its own or in partnership with other utilities.

Other Matters

In accordance with FASB Statement No. 87, Employers’ Accounting for Pensions, Southern Company recorded non-cash pre-tax pension income/(expense) of approximately $(2) million, $44 million, and $99 million in 2005, 2004, and 2003, respectively. Postretirement benefit costs for Southern Company were $118 million, $106 million, and $101 million in 2005, 2004, and 2003, respectively. Both pension and postretirement costs are expected to continue to trend upward. Such amounts are dependent on several factors including

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. For the retail operating companies, pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, see Note 2 to the financial statements.

     Southern Company is involved in various other matters being litigated, regulatory matters, and certain tax-related issues that could affect future earnings. See Note 3 to the financial statements for information regarding material issues.

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. 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. Senior management has discussed the development and selection of the critical accounting policies and estimates described below with the Audit Committee of Southern Company’s Board of Directors.

Electric Utility Regulation

Southern Company’s retail operating companies, which comprise approximately 88 percent of Southern Company’s total earnings for 2005, are subject to retail regulation by their respective state PSCs and wholesale regulation by the FERC. These regulatory agencies set the rates the retail operating companies are permitted to charge customers based on allowable costs. As a result, the retail operating companies apply FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71), which requires the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on the Company’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the retail operating companies; therefore, the accounting estimates inherent in specific costs such as depreciation, nuclear decommissioning, and pension and postretirement benefits have less of a direct impact on the Company’s results of operations than they would on a non-regulated company.

     As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines and accounting principles generally accepted in the United States. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company’s financial statements.

Contingent Obligations

Southern Company and its subsidiaries are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject them to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and records reserves for those matters where a loss is considered probable and reasonably estimable in accordance with generally accepted accounting principles. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company’s financial statements. These events or conditions include the following:

•

Changes in existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances, hazardous and solid wastes, and other environmental matters.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

•		Changes in existing income tax regulations or changes in IRS interpretations of existing regulations.
•		Identification of additional sites that require environmental remediation or the filing of other complaints in which Southern Company or its subsidiaries may be asserted to be a potentially responsible party.
•		Identification and evaluation of other potential lawsuits or complaints in which Southern Company or its subsidiaries may be named as a defendant.
•		Resolution or progression of existing matters through the legislative process, the court systems, the IRS, or the EPA.

Unbilled Revenues

Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, and power delivery volume and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company’s results of operations.

New Accounting Standards

Income Taxes

In December 2004, the FASB issued FASB Staff Position 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 (FSP 109-1), which requires that the generation deduction 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.

Conditional Asset Retirement Obligations

Effective December 31, 2005, Southern Company adopted the provision of FASB Interpretation No. 47 (FIN 47), Conditional Asset Retirement Obligations, which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, Southern Company did not recognize asset retirement obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers because the timing of their retirements was dependent on future events. For additional information, see Note 1 to the financial statements under “Asset Retirement Obligations and Other Costs of Removal.” At December 31, 2005, Southern Company recorded additional asset retirement obligations (and assets) of approximately $153 million. The adoption of FIN 47 did not have any effect on Southern Company’s income statement.

Stock Options

On January 1, 2006, Southern Company adopted FASB Statement No. 123R, Share-Based Payment, on a modified prospective basis. 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 or liability instruments issued. Although the compensation expense required under the revised statement differs slightly, the impacts on the Company’s financial statements are similar to the pro forma disclosures included in Note 1 to the financial statements under “Stock Options.”

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company’s financial condition continued to be stable at December 31, 2005. Net cash flow from operating activities totaled $2.5 billion, $2.7 billion, and $3.1 billion for 2005, 2004, and 2003, respectively. The $165 million decrease for 2005 resulted primarily from higher fuel costs at the retail operating companies, partially offset by increases in base rates and fuel recovery rates. The $376 million decrease from 2003 to 2004 also resulted primarily from higher fuel costs at the retail operating companies. Fuel costs are recoverable in future periods and are reflected in the balance sheets as under recovered regulatory clause revenues. See

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

FUTURE EARNINGS POTENTIAL — “PSC Matters — Fuel Cost Recovery” herein for additional information.

     Significant balance sheet changes include a $0.4 billion increase in long-term debt and preferred stock for 2005 due to an increase of $1.1 billion in property, plant, and equipment. The majority of funds needed for property additions were provided from operating activities.

     At the close of 2005, the closing price of Southern Company’s common stock was $34.53 per share, compared with book value of $14.42 per share. The market-to-book value ratio was 240 percent at the end of 2005, compared with 242 percent at year-end 2004.

     Each of the retail operating companies, Southern Power, and SCS have received investment grade ratings from the major rating agencies.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of the Company’s stock plans, private placements, or public offerings. The amount and timing of additional equity capital to be raised in 2006, as well as in subsequent years, will be contingent on Southern Company’s investment opportunities. The Company does not currently anticipate any equity offerings in 2006 outside of its existing stock option plan.

     The retail operating companies 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. Gulf Power and Mississippi Power are considering other financing options for storm recovery costs. However, the type and timing of any financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by the retail operating companies is generally subject to the approval of the applicable state PSC. In addition, the issuance of all securities by Mississippi Power and Southern Power and short-term securities by Georgia Power and Savannah Electric is generally subject to regulatory approval by the FERC following the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), on February 8, 2006. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the Securities and Exchange Commission under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the amounts registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

     Southern Power plans to use operating cash flows, external funds, and equity capital from Southern Company to finance its capital expenditures. External funds are expected to be obtained from the issuance of unsecured senior debt and commercial paper or through credit arrangements from banks.

     Southern Company and each retail operating company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under “Bank Credit Arrangements” for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company.

     Southern Company’s current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs as well as scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, Southern Company has various sources of liquidity. In addition, Southern Company has substantial cash flow from operating activities and access to the capital markets, including commercial paper programs, to meet liquidity needs.

     At December 31, 2005, Southern Company and its subsidiaries had approximately $202 million of cash and cash equivalents and $3.3 billion of unused credit arrangements with banks, of which $810 million expire in 2006 and $2.5 billion expire in 2007 and beyond. Approximately $228 million of the credit facilities expiring in 2006 allow for the execution of term loans for an additional two-year period, and $311 million allow for the execution of one-year term loans. Most of these arrangements contain covenants that limit debt levels and typically contain cross default provisions that are restricted only to the indebtedness of the individual company. Southern Company and its subsidiaries are currently in compliance with all such covenants. See Note 6

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

to the financial statements under “Bank Credit Arrangements” for additional information.

Financing Activities

During 2005, Southern Company and its subsidiaries issued $1.6 billion of long-term debt and $55 million of preference stock. The security issuances were used to redeem $1.3 billion of long-term debt, to fund Southern Company’s ongoing construction program, and for general corporate purposes. In addition, Southern Company issued 10.1 million new shares of common stock through the Company’s stock plans and realized proceeds of $213 million. In a program designed primarily to offset these issuances, Southern Company also repurchased 10.1 million shares of common stock at a total cost of $352 million. The repurchase program was discontinued in early January 2006.

     Subsequent to December 31, 2005, Alabama Power issued $600 million of long-term senior notes to reduce short-term debt and for other general corporate purposes. In conjunction with these transactions, Alabama Power terminated $600 million notional amount of interest rate swaps at a gain of $18 million. The gain will be amortized to interest expense over a 10-year period. In addition, Southern Company redeemed $72 million in long-term debt payable to affiliated trusts following the repurchase of the underlying capital securities.

Off-Balance Sheet Financing Arrangements

In 2001, Mississippi Power began the initial 10-year term of a lease agreement for a combined cycle generating facility built at Plant Daniel for approximately $370 million. In 2003, the generating facility was acquired by Juniper Capital L.P. (Juniper), a limited partnership whose investors are unaffiliated with Mississippi Power. Simultaneously, Juniper entered into a restructured lease agreement with Mississippi Power. Juniper has also entered into leases with other parties unrelated to Mississippi Power. The assets leased by Mississippi Power comprise less than 50 percent of Juniper’s assets. Mississippi Power is not required to consolidate the leased assets and related liabilities, and the lease with Juniper is considered an operating lease. The lease also provides for a residual value guarantee, approximately 73 percent of the acquisition cost, by Mississippi Power that is due upon termination of the lease in the event that Mississippi Power does not renew the lease or purchase the assets and that the fair market value is less than the unamortized cost of the assets. See Note 7 to the financial statements under “Operating Leases” for additional information.

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 December 31, 2005, the maximum potential collateral requirements at a BBB- or Baa3 rating were approximately $196.4 million. The maximum potential collateral requirements at a rating below BBB- or Baa3 were approximately $602.3 million. Generally, collateral may be provided 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 December 31, 2005, Southern Company and its subsidiaries had no material exposure under these contracts.

     Subsequent to December 31, 2005, the Company has entered into additional physical electricity purchases and sales contracts adding $9 million to the maximum potential collateral requirements at a credit rating of BBB and Baa2 and $17 million at BBB- or Baa3 and below.

Market Price Risk

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

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

     To mitigate future exposure to change in interest rates, the Company has entered into forward starting interest rate swaps that have been designated as hedges. These swaps have a notional amount of $930 million and are related to anticipated debt issuances over the next two years. The weighted average interest rate on $1.5 billion of long-term variable interest rate exposure that has not been hedged at January 1, 2006 was 4.37 percent. If Southern Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the change would affect annualized interest expense by approximately $15.4 million at January 1, 2006. For further information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

     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 natural gas purchases. The retail operating companies have implemented fuel-hedging programs at the instruction of their respective state PSCs. Southern Company Gas also utilized a risk management program to substantially mitigate its exposure to price volatility for its natural gas purchases.

     The changes in fair value of energy-related derivative contracts and year-end valuations were as follows at December 31:

		Changes in Fair Value
		2005				2004
		(in millions)
Contracts beginning of year		$	10.5			$	15.8
Contracts realized or settled			(106.1	)			(58.7	)
New contracts at inception			—				—
Changes in valuation techniques			—				—
Current period changes (a)			196.1				53.4
Contracts end of year		$	100.5			$	10.5

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

Source of 2005 Year-End Valuation Prices
		Total				Maturity
		Fair Value				2006				2007-2008
		(in millions)
Actively quoted		$	101.6			$	67.6			$	34.0
External sources			(1.1	)			(1.1	)			—
Models and other			—				—				—
Contracts end of year		$	100.5			$	66.5			$	34.0

     Unrealized gains and losses from mark-to-market adjustments on derivative contracts related to the retail operating companies’ fuel hedging programs are recorded as regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are recovered through the retail operating companies’ fuel cost recovery clauses. In addition, unrealized gains and losses on energy-related derivatives used by Southern Power to hedge anticipated purchases and sales are deferred in other comprehensive income. Gains and losses on derivative contracts that are not designated as hedges are recognized in the income statement as incurred. At December 31, 2005, the fair value of derivative energy contracts was reflected in the financial statements as follows:

		Amounts
		(in millions)
Regulatory liabilities, net		$	103.4
Other comprehensive income			(0.3	)
Net income			(2.6	)
Total fair value		$	100.5

     Unrealized pre-tax gains and losses recognized in income were not material for any year presented.

     Southern Company is exposed to market price risk in the event of nonperformance by counterparties to the derivative energy contracts. Southern Company’s policy is to enter into agreements with counterparties that have investment grade credit ratings by Moody’s and Standard & Poor’s or with counterparties who have posted collateral to cover potential credit exposure. Therefore, Southern Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Notes 1 and 6 to the financial statements under “Financial Instruments.”

Capital Requirements and Contractual Obligations

The construction program of Southern Company is currently estimated to be $2.8 billion for 2006, $3.6

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

billion for 2007, and $3.1 billion for 2008. Environmental expenditures included in these amounts are $0.8 billion, $1.3 billion, and $1.1 billion for 2006, 2007, and 2008, respectively. Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

     As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under “Nuclear Decommissioning.” Also, as discussed in Note 1 to the financial statements under “Nuclear Fuel Disposal Costs,” in 1993 the DOE implemented a special assessment over a 15-year period on utilities with nuclear plants, to be used for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The final installment is scheduled to occur in 2006.

     In addition, as discussed in Note 2 to the financial statements, Southern Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the retail operating companies’ respective regulatory commissions.

     Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, and other purchase commitments are as follows. See Notes 1, 6, and 7 to the financial statements for additional information.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

Contractual Obligations

						2007-				2009-				After
		2006				2008				2010				2010				Total
		(in millions)
Long-term debt(a) –
Principal		$	901			$	1,966			$	834			$	10,065			$	13,766
Interest			688				1,246				1,108				9,752				12,794
Other derivative obligations(b) –
Commodity			32				—				—				—				32
Preferred and preference stock dividends(c)			33				65				65				—				163
Operating leases			123				205				156				259				743
Purchase commitments(d) –
Capital(e)			2,772				6,673				—				—				9,445
Coal			3,129				3,959				1,558				364				9,010
Nuclear fuel			63				62				34				89				248
Natural gas(f)			1,495				1,286				740				3,046				6,567
Purchased power			175				356				305				541				1,377
Long-term service agreements			71				175				180				1,334				1,760
Trusts –
Nuclear decommissioning			7				14				14				117				152
Postretirement benefits(g)			45				88				—				—				133
DOE			9				—				—				—				9
Total		$	9,543			$	16,095			$	4,994			$	25,567			$	56,199

(a)		All amounts are reflected based on final maturity dates. Southern Company and its subsidiaries plan to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2006, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.
(b)		For additional information, see Notes 1 and 6 to the financial statements.
(c)		Preferred and preference stock do not mature; therefore, amounts are provided for the next five years only.
(d)		Southern Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for 2005, 2004, and 2003 were $3.5 billion, $3.3 billion, and $3.2 billion, respectively.
(e)		Southern Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.
(f)		Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2005.
(g)		Southern Company forecasts postretirement trust contributions over a three-year period. No contributions related to Southern Company’s pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from Southern Company’s corporate assets.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2005 Annual Report

Cautionary Statement Regarding Forward-Looking Statements

Southern Company’s 2005 Annual Report 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, earnings growth, dividend payout ratios, the Company’s projections for postretirement benefit trust contributions, financing activities, access to sources of capital, the proposed merger of Savannah Electric and Georgia Power, impacts of the adoption of new accounting rules, completion of construction projects, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•		the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, 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 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, including rate cases relating to fuel cost recovery;
•		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 (including the Form 10-K) filed by Southern Company from time to time with the Securities and Exchange Commission.

Southern Company expressly disclaims any obligation to update any forward-looking statements.

EXHIBIT INDEX

(24) Power of Attorney and Resolution

		(a)		-		Power of Attorney and Resolution (Designated in the Form 10-K for the year ended December 31, 2005, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference).

(31) Section 302 Certifications

		(a)1		-		Certificate of Southern Company’s Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		(a)2		-		Certificate of Southern Company’s Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

(32) Section 906 Certifications

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

THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

	THE SOUTHERN COMPANY
	By:		David M. Ratcliffe
			Chairman, President and
			Chief Executive Officer
	By:		/s/ Wayne Boston
			(Wayne Boston, Attorney-in-fact)
	Date:	March 2, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

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

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

W. Dean Hudson
Comptroller and Chief Accounting Officer
(Principal Accounting Officer)

               Directors:

Juanita P. Baranco       Zack T. Pate
Dorrit J. Bern                J. Neal Purcell
Francis S. Blake            William G. Smith, Jr.
Thomas F. Chapman     Gerald J. St. Pé
Donald M. James

By:   /s/ Wayne Boston

(Wayne Boston, Attorney-in-fact)

Date: March 2, 2006