ML041210080

Annual Submission Reports, (Includes 2003 Annual Report, Unaudited Financial Statements for Quarter Ended 03/31/2004, & Cash Flow Projections for 2004)

ML041210080
Person / Time
Site:	Farley
Issue date:	04/22/2004
From:	Derieux J Southern Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML041210080 (53)

Text

J. Randy DeRieux 600 North 18th Street Assistant Treasurer and Post Office Box 2641 General Manager- Birmingham, Alabama 35291-0030 Corporate Finance and Planning Tel 205.257.2454 Fax 205.257.1023 April 22, 2004 ALABAMAANE. 4 POWER A SOUTHERN COMPANY U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555-0001 Joseph M. Farley Nuclear Plant Annual Submission Reports Re: Docket Nos.: 50-348 50-364 Ladies & Gentlemen:

Enclosed is the annual submission of Alabama Power Company with respect to the retrospective premium guarantee required under the Price Anderson Act, as amended, applicable to its Joseph M. Farley Nuclear Plant. We have elected to satisfy this guarantee requirement by submitting annual certified financial statements and cash projections, showing that a cash flow can be generated and would be available for payment of retrospective premiums up to $20,000,000 within three months after submission of the statement. In this connection, enclosed are the following:

1. 2003 Annual Report which includes financial statements for the calendar year 2003, together with the report on such statements by Deloitte & Touche LLP, independent public accountants;

2. Unaudited Financial Statements for the quarter ended March 31, 2004;

3. Cash Flow Projections for the period January 1, 2004 through December 31, 2004, showing that cash flow of $20,000,000 can be generated and would be available for payment of retrospective premiums within three months after submission of the statement.

Please acknowledge receipt of the enclosures by signing and returning the enclosed copy of this letter.

Very truly yours,

',1' (6e4 JRD:lw Enclosures cc: w/attachments Southern Nuclear Operating Company Mr. D. E. Grissette, General Manager- Plant Farley U. S. Nuclear Regulatory Commission, Washington, D.C.

Mr. F. Rinald, Licensing Project Manager - Farley U. S. Nuclear Regulatory Commission, Region II Mr. L. A. Reyes, Regional Administrator Mr. T. P. Johnson, Senior Resident Inspector- Farley 7 C)j 8

This statement reflects the usual ALABAMA POWER COMPANY accounting practices of the Company BALANCE SHEET on the basis of interim figures and CONSOLIDATED WITH ALABAMA POWER CAPITAL TRUSTS IV & V is subject to audit and end of year (Stated in Thousands of Dollars) adjustments.

At At ASSETS March 31, 2004 March 31, 2003 UTILITY PLANT:

Plant in service, at original cost............................................................................. $ $ 14,299,320 $ 13,632,475 Less - Accumulated provision for depreciation and amortization......................... 5,546,464 5,299,183

$ 8,752,856 $ 8,333,292 Nuclear fuel, at amortized cost.............................................................................. $ 86,907 96,660 Construction work in progress............................................................................... $ 411,088 529,786

$ 9,250,851 $ 8,959,738 OTHER PROPERTY AND INVESTMENTS:

Equity investm ents in subsidiaries......................................................................... $ 47,895 45,468 Nuclear decom missioning trusts............................................................................ $ 396,379 288,181 Miscellaneous...................................................................................................... $ 21,218 16,782

$ 465,492 $ 350,431 CURRENT ASSETS:

Cash...................................................................................................................... $ 22,398 40,356 Special Deposits.................................................................................................. $ 0 Tem porary cash investments................................................................................. $ 138,000 218,000 Investment securities............................................................................................ $ 0 Receivables -

Custom er accounts receivable........................................................................... $ 335,655 325,018 Other accounts and notes receivable............................................................... $ 39,994 86,930 Affiliated com panies............................................................................................ $ 57,148 60,424 Accumulated provision for uncollectible accounts...................................... $ (5,868) (5,039)

Refundable incom e taxes...................................................................................... $ 10,346 Fossil fuel stock, at average cost.......................................................................... $ 77,950 72,695 M aterials and supplies, at average cost................................................................ $ 185,977 161,284 Allowance Inventory.............................................................................................. $ 29,161 28,506 Prepayments -

Incom e taxes....................................................................................................... 0 Other................................................................................................................... $ 88,118 104,035 Other current assets - SFAS 133....................... ........................ $ 27,797 58,981 Vacation pay deferred............................................................................................ $ 35,530 33,901

$ 1,031,860 $ 1,195,437 Debt expense, being amortized............................................................................. $ 24,209 9,813 Debt redem ption expense, being am ortized.......................................................... 5 108,886 107,768 Nuclear decontamination and decommissioning fund.......................................... $ 13,092 17,144 Prepaid pension cost............................................................................................. $ 456,669 398,452 Regulatory assets.................................................................................................. $ 628,213 594,951 Miscellaneous........................................................................................................ $ 86,950 102,892

$ 1,318,019 $ 1,231,020 TOTAL ASSETS................................................... ............................................... $ $ 12,066,222 $ $ 11,736,626 4/1 6/2004 +

This statement reflects the usual ALABAMA POWER COMPANY accounting practices of the Company BALANCE SHEET on the basis of interim figures and CONSOLIDATED WITH ALABAMA POWER CAPITAL TRUSTS IV & V is subject to audit and end of year (Stated in Thousands of Dollars) adjustments.

At At CAPITALIZATION AND LIABILITIES March 31, 2004 March 31, 2003 CAPITALIZATION:

Com m on stock equity............................................................................................ $ 3,504,079 $ 3,336,487 Preferred stock.................................................................................................... $ 472,512 372,512 Company obligated mandatorily redeemable preferred securities ...................... $ 300,000 300,000 Long-term debt...................................................................................................... $ 3,376,165 3,075,930

$ 7,652,756 $ 7,084,929 CURRENT LIABILITIES:

Preferred stock due or to be redeemed within one year........................................ $ 0 Long-term debt due or to be redeemed within one year........................................ $ 725,011 1,124,151 Notes payable to banks......................................................................................... $ 0 Com m ercial paper................................................................................................. $ 0 Accounts payable -

Affiliated com panies............................................................................................ $ 143,551 87,292 Other................................................................................................................. $ 93,117 46,708 Custom er deposits................................................................................................. $ 48,513 45,027 Taxes accrued -

Federal and state income................................................................................... $ 73,773 113,025 Other................................................................................................................... $ 44,140 33,280 Interest accrued..................................................................................................... $ 48,424 54,050 Distributions accrued............................................................................................. $ 8,164 6,765 Vacation pay accrued............................................................................................ $ 35,530 33,901 Miscellaneous....................................................................................................... $ 71,539 240,819

$ 1,291,762 $ 1,785,018 DEFERRED CREDITS AND OTHER LIABILITIES:

Accum ulated deferred income taxes..................................................................... $ 1,626,767 1,462,633 Accum ulated deferred investment tax credits........................................................ $ 213,570 225,443 A sset Retirement Obligations................................................................................ $ 364,775 304,423 Prepaid capacity revenues, net............................................................................. $ 21,455 32,367 Regulatory liabilities............................................................................................... $ 158,555 173,619 Nuclear decontamination and decommissioning fund.......................................... $ 8,728 12,858 Natural disaster reserve......................................................................................... $ 13,338 12,301 M iscellaneous....................................................................................................... $ 714,516 643,035

$ 3,121,704 $ 2,866,679 TOTAL CAPITALIZATION AND LIABILITIES .......................................................... $ $ 12,066,222 $ $ 11,736,626

• Substantially all assets of Alabama Power Capital Trust IV & V are junior subordinate notes issued by the company. Upon redemption of such notes, the Trust securities will be mandatorily redeemable. See Note 7 to the financial statements of Alabama Power Company of the 2002 Form 10-K for further details.

4116/2004 +

ALABAMA POWER COMPANY STATEMENT OF INCOME (THOUSANDS OF DOLLARS) 3 Months Ended 3/31/2004 OPERATING REVENUES:

Revenues $ 959,687 OPERATING EXPENSES:

Operation --

Fuel 254,551 Purchased & interchange power, net 103,993 Other 147,663 Maintenance 80,387 Depreciation & amortization 105,353 Taxes other than income taxes 64,447 Federal and State income taxes 57,605 Total Operating Expenses 813,999 OPERATING INCOME 145,688 OTHER INCOME (EXPENSES):

Allowance for equity funds used during construction 4,110 Income from subsidiary 882 Other, net (719)

INCOME BEFORE INTEREST CHARGES 149,961 INTEREST CHARGES:

Interest on long-term debt 47,900 Allowance for debt funds used during construction (1,648)

Amortization of debt discount, premium and expenses, net 3,708 Other interest charges 4,056 Net Interest Charges 54,016 NET INCOME 95,945 DIVIDENDS ON PREFERRED STOCK 4,747 NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 91,198 This statement reflects the usual accounting practices of the Company on the basis of interim figures and is subject to audit and end of year adjustments.

H:\NFINCSTMT.xls

ALABAMA POWER COMPANY Internal Cash Flow for Joseph M. Farley Nuclear Power Station (Thousands of Dollars) 2003 2004 Actual Projections Net Income $ 491,077 $ 496,927 Less Dividends Paid 448,381 456,285 Retained Earnings 42,696 40,642 Adjustments:

Depreciation and Amortization 467,085 499,803 Deferred Income Taxes and Investment Tax Credits 153,154 120,088 Allowance for Equity Used During Construction (12,594) (17,240)

Total Adjustments 607,645 602,651 Internal Cash Flow $ 650,341 $ 643,293 Average Quarterly Cash Flow $ 162,585 $ 160,823 Percentage Ownership in all Operating Nuclear Units:

Joseph M. Farley Units 1 and 2 100%

Maximum Total Contingent Liability $ 20,000 H:\NFCASHFL.xls

2003 Annual Report ALABAMA A POWER A SOUTHERN COMPANY

CONTENTS Alabama Power Company 2003 Annual Report 1

SUMMARY

2 LETTER TO INVESTORS 3 MANAGEMENT'S REPORT 4 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS 5 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION 21 FINANCIAL STATEMENTS 28 NOTES TO FINANCIAL STATEMENTS 44 SELECTED FINANCIAL AND OPERATING DATA 46 DIRECTORS AND OFFICERS 47 CORPORATE INFORMATION

SUMMARY

Percent 2003 2002 Change _

Financial Highlights (in millions):

Operating revenues $3,960 $3,710 6.7 Operating expenses $2,945 $2,688 9.6 Net income after dividends on preferred stock $473 $461 2.5 Operating Data:

Kilowatt-hour sales (in millions):

Retail 52,208 52,073 0.3 Sales for resale - non-affiliates 17,086 15,554 9.9 Sales for resale - affiliates 9,422 8,844 6.5 Total 78,716 76,471 2.9 Customers served at year-end (in thousands) 1,370 1,357 1.0 Peak-hour demand (in megawatts) 10,462 10,910 (4.1)

Capitalization Ratios (percent).

Common stock equity 46.4 49.7 Preferred stock 4.9 3.6 Mandatorily redeemable preferred securities 4.0 4.4 Long-term debt 44.7 42.3 (Excluding long-term debt due within one year)

Return on Average Common Equity (percent) 13.75 13.80 1

LETTER TO INVESTORS Alabama Power Company 2003 Annual Report The year 2003 was a year of great uncertainty as our country went to war and the recovery of our national economy remained in doubt. But at least one thing remained constant - Alabama Power Company continued to produce results for our shareholders, customers and communities.

Our customers know they can count on Alabama Power to provide reliable service and low prices. Our shareholders know they can count on us to make every effort to meet our financial goals. Further, our communities know they can count on us to be environmentally responsible and to help make our state a better place to live for everyone.

Once again, Alabama Power met or surpassed all of its financial goals, enabling us to keep our promises to our shareholders.

Our generating plants far surpassed their goals during the peak usage months, assuring that our customers would have electricity when they needed it, at prices 15 percent below the national average. Likewise, thanks to our excellent transmission and distribution system, electric service was available to our customers 99.97 percent of the time.

We continued to improve our customer value ratings and now rank number one among residential customers and number two overall.

At the same time, we continued our efforts to reduce our impact on the environment we all treasure. In 2003, Alabama Power continued to install state-of-the-art emissions reduction equipment and technology at our generating plants.

We had a successful year and we believe the key to that success will always be the same:

Make every decision with the best interest of your customer, shareholder and employee in mind.

Take every action based upon the highest standards of ethics and integrity. Our business may change but these are beliefs you can count on always.

Solid values, a strong commitment to our customers and sound business strategies allowed us to successfully face the challenges of 2003, and they will allow us to move into the future in a position of strength.

Sincerely, Charles D. McCrary President and Chief Executive Officer March 19, 2004 2

MANAGEMENT'S REPORT Alabama Power Company 2003 Annual Report The management of Alabama Power Company has Southern Company's audit committee of its board of prepared -- and is responsible for -- the financial directors, composed of four independent directors, statements and related information included in this report. provides a broad overview of management's financial These statements were prepared in accordance with reporting and control functions. Additionally, the controls accounting principles generally accepted in the United and compliance committee of Alabama Power's board of States and necessarily include amounts that are based on directors, composed of three outside directors, meets the best estimates and judgments of management. periodically with management, the internal auditors, and Financial information throughout this annual report is the independent public accountants to discuss auditing, consistent with the financial statements. internal controls, and compliance matters. The internal auditors and independent public accountants have access The Company maintains a system of internal to the members of these committees at any time.

accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records Management believes that its policies and procedures reflect only authorized transactions of the Company. provide reasonable assurance that the Company's Limitations exist in any system of internal controls, operations are conducted according to a high standard of however, based on a recognition that the cost of the business ethics.

system should not exceed its benefits. The Company believes its system of internal accounting controls In management's opinion, the financial statements maintains an appropriate cost/benefit relationship. present fairly, in all material respects, the financial position, results of operations and cash flows of Alabama The Company's internal accounting controls are Power Company in conformity with accounting principles evaluated on an ongoing basis by the Company's internal generally accepted in the United States.

audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.

a eJo.1,S/

Charles D. McCrary William B. Hutchins, III President Executive Vice President, and Chief Executive Officer Chief Financial Officer, and Treasurer March 1, 2004 3

INDEPENDENT AUDITORS' REPORT Alabama Power Company:

We have audited the accompanying balance sheets and misstatement. An audit includes examining, on a test statements of capitalization of Alabama Power Company basis, evidence supporting the amounts and disclosures in (a wholly owned subsidiary of Southern Company) as of the financial statements. An audit also includes assessing December 31, 2003 and 2002, and the related statements the accounting principles used and significant estimates of income, comprehensive income, common stockholder's made by management, as well as evaluating the overall equity, and cash flows for the years then ended. These financial statement presentation. We believe that our financial statements are the responsibility of Alabama audits provide a reasonable basis for our opinion.

Power Company's management. Our responsibility is to In our opinion, the financial statements (pages 21 to express an opinion on these financial statements based on our audits. The financial statements of Alabama Power 43) present fairly, in all material respects, the financial Company for the year ended December 31, 2001 were position of Alabama Power Company at December 31, audited by other auditors who have ceased operations. 2003 and 2002, and the results of its operations and its Those auditors expressed an unqualified opinion on those cash flows for the years then ended in conformity with financial statements and included an explanatory accounting principles generally accepted in the United paragraph that described a change in the method of States of America.

accounting for derivative instruments and hedging As discussed in Note 1 to the financial statements, in activities in their report dated February 13, 2002. 2003 Alabama Power Company changed its method of We conducted our audits in accordance with auditing accounting for asset retirement obligations.

standards generally accepted in the United States of America. Those standards require that we plan and I4 1-L-P perform the audit to obtain reasonable assurance about Birmingham, Alabama whether the financial statements are free of material March 1, 2004 THE FOLLOWING REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS IS A COPY OF THE REPORT PREVIOUSLY ISSUED IN CONNECTION WITH THE COMPANY'S 2001 ANNUAL REPORT AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

To Alabama Power Company:

We have audited the accompanying balance sheets and presentation. We believe that our audits provide a statements of capitalization of Alabama Power Company reasonable basis for our opinion.

(an Alabama corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2001 and 2000, In our opinion, the financial statements (pages 15-33) and the related statements of income, common referred to above present fairly, in all material respects, stockholder's equity, and cash flows for each of the three the financial position of Alabama Power Company as of years in the period ended December 31, 2001. These December 31, 2001 and 2000, and the results of its financial statements are the responsibility of the Company's operations and its cash flows for each of the three years in management. Our responsibility is to express an opinion on the period ended December 31, 2001, in conformity with these financial statements based on our audits. accounting principles generally accepted in the United States.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those As explained in Note 1 to the financial statements, standards require that we plan and perform the audit to effective January 1, 2001, Alabama Power Company obtain reasonable assurance about whether the financial changed its method of accounting for derivative statements are free of material misstatement. An audit instruments and hedging activities.

includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles used and significant estimates made by management, as Birmingham, Alabama well as evaluating the overall financial statement February 13, 2002 4

MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 2003 Annual Report OVERVIEW OF EARNINGS AND BUSINESS RESULTS OF OPERATIONS ACTIVITIES A condensed income statement is as follows:

Earnings Increase (Decrease)

Alabama Power Company's 2003 net income after Amount From Prior Year dividends on preferred stock was $473 million, 2003 2003 2002 2001 representing a $12 million (2.5 percent) increase from the (in millions) prior year. This improvement is due primarily to higher Operating revenues $3,960 $250 $124 $(81) sales for resale, increases in other revenues, and lower Fuel 1,068 98 (31) 38 interest expense, partially offset by higher non-fuel Purchased power 315 66 (44) (56) operating expenses. Other operation and maintenance 921 67 71 (56)

In 2002, earnings were $461 million, representing a 19.3 Depreciation percent increase from the prior year. This improvement and amortization 413 15 15 19 was primarily attributable to increased territorial energy Taxes other than sales and higher retail rates when compared to the prior income taxes 228 11 2 5 year. More favorable weather conditions in 2002 as Total operating compared to the unusually mild weather experienced in expenses 2,945 257 13 (50) 2001 contributed to the increases in territorial sales. The Operating income 1,015 (7) 111 (31) increases in revenues were partially offset by increased Other income non-fuel operating expenses. Earnings in 2001 were $387 (expense), net (252) 17 7 (15) million, representing a 7.9 percent decrease from the prior Less --

year. This decline was primarily attributable to a decrease Income taxes 290 (2) 44 (13) in territorial energy sales as a result of an economic Net Income $ 473 $ 12 $ 74 $(33) downturn and milder temperatures.

The return on average common equity for 2003 was Revenues 13.75 percent compared to 13.80 percent in 2002 and Operating revenues for 2003 were nearly $4.0 billion, 11.89 percent in 2001. reflecting a $250 million increase from 2002. The following table summarizes the principal factors that have Business Activities affected operating revenues for the past three years:

The Company operates as a vertically integrated utility Amount providing electricity to retail customers within its 2003 2002 2001 traditional service area located within the State of (in millions)

Alabama and to wholesale customers in the Southeast. Retail -- prior year $2,951 $2,748 $2,953 Change in -

Several factors affect the opportunities, challenges, and Base rates 51 76 23 risk of the Company's primary business of selling Sales growth 68 70 (36) electricity. These factors include the ability to maintain a Weather (61) 60 (62) stable regulatory environment, to achieve energy sales Fuel cost recovery growth while containing costs, and to recover costs related and other 42 (3) (130) to growing demand and increasingly stricter Retail -- current year 3,051 2,951 2,748 environmental standards. Future earnings in the near term Sales for resale --

will depend, in part, upon growth in energy sales, which is Non-affiliates 488 474 486 subject to a number of factors. These factors include Affiliates 277 188 245 weather, competition, new energy contracts with Total sales for resale 765 662 731 neighboring utilities, energy conservation practiced by Other operating revenues 144 97 107 customers, the price elasticity of demand, and the rate of Total operating revenues $3,960 $3,710 $3,586 economic growth in the service area.

Percent change 6.7% 3.5% (2.2)%

5

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report Retail revenues in 2003 were $3.1 billion. Revenues Short-term opportunity energy sales are also included in increased $100 million (3.4 percent) from the prior year, sales for resale to non-affiliates. These opportunity sales increased $203 million (7.4 percent) in 2002, and are made at market rates that generally include the decreased $205 million (6.9 percent) in 2001. All sectors recovery of fixed costs and a return, in addition to the of retail revenues increased for the Company in 2003 variable energy cost. Revenues associated with other primarily due to increased fuel revenue and a 2.6 percent power sales to non-affiliates were as follows:

increase in retail base rates which went into effect in July 2003. See Note 3 to the financial statements under "Retail 2003 2002 2001 Rate Adjustment Procedures" for additional information. (in thousands)

Other power sales -

The primary contributors to the increase in revenues in Capacity and other $33,858 $14,613 $ 13,324 2002, shown in the table above, were the positive effect of Variable cost of energy 44,627 61,925 91,608 favorable weather conditions on energy sales and Total $78,485 $76,538 $104,932 increases in retail base rates (0.6 percent increase in July Revenues from sales to affiliated companies within the 2001 and 2 percent increases in both October 2001 and Southern electric system, as well as purchases of energy, April 2002). The Company mitigated the effect of these will vary from year to year depending on demand and the increases to customers with a decrease to the energy cost availability and cost of generating resources at each recovery factor in April 2002.

company. Sales for resale revenues increased $26.6 million in 2003 due to increased capacity payments The revenue decrease in 2001 was primarily due to the received in accordance with the affiliated company negative impact of milder temperatures on energy sales interchange agreements as a result of increased capacity.

and an economic downturn in the Company's service Excluding the capacity revenues, these transactions do not territory.

have a significant impact on earnings since the energy is generally sold at marginal cost and energy purchases are Fuel rates billed to customers are designed to fully generally offset by energy revenues through the recover fluctuating fuel costs over a period of time. At Company's energy cost recovery clause.

December 31, 2003, the Company had no unrecovered fuel costs. Fuel revenues have no effect on net income Other operating revenues in 2003 increased $47 million because they represent the recording of revenues to offset (48.6 percent) from 2002 due to an increase of $19.4 fuel expenses. million in revenues from gas-fueled co-generation steam facilities -- primarily as a result of higher gas prices -- and Sales for resale to non-affiliates are predominantly unit a $14.8 million increase in revenues from Alabama Public power sales under long-term contracts to Florida utilities. Service Commission (Alabama PSC) approved fees Revenues from power sales contracts have both capacity charged to customers for connection, reconnection, and and energy components. Capacity revenues reflect the collection when compared to the same period in 2002.

recovery of fixed costs and a return on investment under Since co-generation steam revenues are generally offset the contracts. Energy is generally sold at variable cost. by fuel expenses, these revenues did not have a significant These capacity and energy components of the unit power impact on earnings.

contracts were as follows:

The $11 million (9.9 percent) decrease in other 2003 2002 2001 operating revenues in 2002 resulted primarily from a $7.0 (in thousands) million decrease in revenues from gas-fueled co-Unit power -

generation steam facilities due to lower gas prices and Capacity $130,022 $119,193 $124,720 lower demand. The $21 million (23.9 percent) increase in Energy 145,342 134,051 134,006 2001 was primarily attributed to a $6.4 million increase in Total $275,364 $253,244 $258,726 steam sales in conjunction with the operation of the There are no significant scheduled declines in unit Company's co-generation facilities, a $5.3 million power sales capacity until the termination of the unit increase in fuel sales, and a $5.1 million increase in rent power sales contracts in 2010. from electric property.

6

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report Energy Sales Expenses Changes in revenues are influenced heavily by the volume The total operating expenses in 2003 were approximately of energy sold each year. Kilowatt-hour (KWH) sales for $3.0 billion, an increase of $257 million (9.6 percent) over 2003 and the percent change by year were as follows: the previous year. This increase is mainly due to a $98 million increase in fuel expense primarily related to an KWH Fpercent Change increase in the average cost of natural gas and coal. In 2003 2003 2002 2001 addition, purchased power expenses increased a total of $66 (millions) million, maintenance expense increased $30 million primarily related to transmission and distribution overhead Residential 16,960 (2.5)% 9.6% (5.3)% lines, and depreciation and amortization expense increased Commercial 13,452 0.7 4.4 (1.5) $15 million.

Industrial 21,593 2.3 3.1 (7.4)

Other 203 (1.1) 3.7 In 2002, total operating expenses of $2.7 billion (3.9)

Total retail 52,208 0.3 5.5 (5.2) increased by $13 million (0.5 percent) over the previous Sales for resale - year. This slight increase was mainly due to a $35 million Non-affiliates 17,086 9.9 1.8 2.9 increase in administrative and general expenses primarily Affiliates 9,422 6.5 - 64.7 related to employee salaries, insurance expense, and Total 78,716 2.9 4.1 1.6 accrued expenses for liability insurance, litigation and workers compensation, a $19 million increase in production Residential energy sales for 2003 experienced a 2.5 expenses related to boiler plant maintenance, and a $15 percent decrease over the prior year and total retail energy million increase in depreciation and amortization expenses sales grew by 0.3 percent primarily as a result of milder- due to an increase in depreciable property. These increases than-normal summer temperatures compared to the were offset by a $43 million decrease in purchased power previous year. Although retail sales to industrial expenses and a $14 million decrease in fuel expenses customers increased 2.3 percent in 2003 and 3.1 percent in related to lower coal prices.

2002, overall sales to industrial customers remained depressed due to the continuing effect of sluggish In 2001, total operating expenses of $2.7 billion were economic conditions. down $50 million (1.8 percent) compared with 2000. This decline was mainly due to an $18 million net decrease in Residential energy sales for 2002 experienced a 9.6 fuel and purchased power costs related to lower fuel prices, percent increase over the prior year and total retail energy increased hydro generation and added capacity. The sales grew by 5.5 percent primarily as a result of warmer Company also had a $56 million decrease in non-summer temperatures and colder winter weather production operation and maintenance expense related to conditions compared to the previous year. settlements received in connection with the Company's insurance program, lower costs related to services provided The decrease in 2001 retail energy sales was primarily by Southern Company Services (SCS) and Southern due to milder temperatures and an economic downturn in Nuclear Operating Company, and a reduction to the natural the Company's service area. This was offset by an disaster reserve accrual. These decreases in expense were increase in sales for resale to affiliates. Increased partially offset by a $19 million increase in depreciation and operation of the Company's combined cycle facilities due amortization due to an increase in depreciable property.

to lower natural gas prices and an increase in the Company's combined cycle capacity contributed to the Fuel costs constitute the single largest expense for the increase in sales for resale. Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit Assuming normal weather, sales to retail customers are cost of fuel consumed, and the availability of fossil and projected to grow approximately 1.7 percent annually on nuclear generating units and hydro generation. The average during 2004 through 2008. amount and sources of generation and the average cost of fuel per net KWH generated and the average cost of purchased power were as follows:

7

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report 2003 2002 2001 Depreciation and amortization expense increased 3.6 Total generation percent in 2003, 3.9 percent in 2002, and 5.2 percent in (billions of KWHs) 72 71 68 2001. These increases reflect additions to property, plant, Sources of generation and equipment.

(percent) --

Coal 64 62 64 Allowance for Equity Funds Used During Construction Nuclear 19 19 18 (AFUDC) increased $1.4 million (12.8 percent) in 2003 Hydro 8 6 6 due to an increase in the applicable AFUDC rate.

Gas 9 13 12 AFUDC increased $4 million (57.5 percent) in 2002 due Average cost of fuel per net to an increase in the amount of construction work in kilowatt-hour generated progress over the prior year. AFUDC decreased $16 (cents) 1.67 1.47 1.56 million (68.9 percent) in 2001 due to completing Average cost of purchased construction of Plant Barry Unit 7 and placing it in service power per net kilowatt-hour in May 2001.

(cents) 3.56 2.91 3.28 Interest expense, net of amounts capitalized, of $214 In 2003, total fuel and purchased power expenses of $1.4 million in 2003 decreased $11.4 million (5.1 percent) from billion increased $164 million (13.4 percent) over 2002 due 2002, which had decreased $21 million (8.4 percent) from to a 58.3 percent increase in average gas prices and a 2.2 2001. Both years reflect a decrease in interest rates on percent increase in average coal prices. Fuel and purchased long-term debt due to refinancing activities. Interest power expenses in 2002 of $1.2 billion decreased $75 expense increased $11 million (4.7 percent) in 2001 million (5.8 percent) due primarily to lower average fuel compared to 2000.

cost, while total energy sales increased 3.0 billion kilowatt hours (4.1 percent) compared with the amounts recorded in Effects of Inflation 2001. Fuel and purchased power expenses in 2001 The Company is subject to rate regulation that is based on decreased $18 million (1.4 percent) compared to 2000 the recovery of historical costs. In addition, the income because of reduced generation due to milder temperatures tax laws are also based on historical costs. Therefore, in 2001. Fuel expenses, including purchased power, are inflation creates an economic loss because the Company is offset by fuel revenues through the Company's energy cost recovering its costs of investments in dollars that have less recovery clause and have no effect on net income.

purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an Purchased power consists of purchases from affiliates adverse effect on the Company because of the large in the Southern electric system and non-affiliated investment in utility plant with long economic lives.

companies. Purchased power transactions among the Conventional accounting for historical cost does not Company and its affiliates will vary from period to period recognize this economic loss nor the partially offsetting depending on demand, the availability, and the variable gain that arises through financing facilities with fixed-production cost of generating resources at each company.

money obligations, such as long-term debt and preferred In 2003, purchased power from non-affiliates increased securities. Any recognition of inflation by regulatory

$20 million (22 percent) due to a 19.3 percent increase in authorities is reflected in the rate of return allowed.

price and a 9.5 percent increase in energy purchased when compared to 2002. During 2002, purchased power Future Earnings Potential transactions from non-affiliates decreased $54 million (37 percent) due to the addition in May 2001 of a combined General cycle unit which generated 6.1 billion kilowatt hours in 2002, an 18.4 percent increase over the previous year. The results of operations for the past three years are not Purchased power transactions from non-affiliates also necessarily indicative of future earnings potential. The declined in 2001 because of the addition of the combined level of the Company's future earnings depends on cycle unit and an increase in hydro generation resulting in numerous factors. Major factors include the ability of the a $20 million (12 percent) decline from the year 2000. Company to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly 8

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report stricter environmental standards. Growth in energy sales exited or drastically reduced all energy marketing and is subject to a number of factors. These factors include trading activities and sold foreign and domestic electric weather, competition, new energy contracts with infrastructure assets. The Company has not experienced neighboring utilities, energy conservation practiced by any material adverse financial impact regarding its limited customers, the price elasticity of demand, and the rate of energy trading operations through SCS.

economic growth in the Company's service area.

Continuing to be a low-cost producer could provide Industry Restructuring opportunities to increase the size and profitability in markets that evolve with changing regulation and The Company operates as a vertically integrated utility competition. Conversely, future regulatory changes could providing electricity to customers within its traditional adversely affect the Company's growth, and if the service area located in the State of Alabama and to Company does not remain a low-cost producer and wholesale customers in the Southeast. provide quality service, then energy sales growth could be limited, and this could significantly erode earnings.

The electric utility industry in the United States is continuing to evolve as a result of regulatory and EnvironmentalMatters competitive factors. Among the early primary agents of change was the Energy Policy Act of 1992 (Energy Act). New Source Review Actions The Energy Act allowed independent power producers to access a utility's transmission network and sell electricity In November 1999, the Environmental Protection Agency to other utilities. (EPA) brought a civil action against the Company alleging that the Company had violated the New Source Review Although the Energy Act does not provide for retail (NSR) provisions of the Clean Air Act with respect to customer access, it was a major catalyst for restructuring coal-fired generating facilities at the Company's Plants and consolidations that took place within the utility Miller, Barry, and Gorgas. The civil action requests industry. Numerous federal and state initiatives that penalties and injunctive relief, including an order promote wholesale and retail competition are in varying requiring the installation of the best available control stages. Among other things, these initiatives allow retail technology at the affected units. The action against the customers in some states to choose their electricity Company has been stayed since the spring of 2001 during provider. Some states have approved initiatives that result the appeal of a very similar NSR action against the in a separation of the ownership and/or operation of Tennessee Valley Authority before the U.S. Court of generating facilities from the ownership and/or operation Appeals for the Eleventh Circuit. The Eleventh Circuit of transmission and distribution facilities. While various appeal was decided on September 16, 2003, and, on restructuring and competition initiatives have been February 13, 2004, the EPA petitioned the U.S. Supreme discussed in Alabama, none have been enacted. In Court to review the Eleventh Circuit's decision. The EPA October 2000, the Alabama PSC completed a two-year also filed a motion to lift the stay in the action against the study of electric industry restructuring, concluding that (i) Company. See Note 3 to the financial statements under restructuring of the electric utility industry in Alabama "New Source Review Actions" for additional information.

was not in the public interest and (ii) the Alabama PSC itself could not mandate retail competition or electric In December 2002 and October 2003, the EPA issued industry restructuring without enabling state legislation. final revisions to its NSR regulations under the Clean Air Electric utility restructuring could require numerous issues Act. The December 2002 revisions included changes to to be resolved, including significant ones relating to the regulatory exclusions and the methods of calculating recovery of any stranded investments, full cost recovery of emissions increases. The October 2003 regulations energy produced, and other issues related to the energy clarified the scope of the existing Routine Maintenance, crisis that occurred in California as well as the August Repair, and Replacement exclusion. A coalition of states 2003 power outage in the Northeast. and environmental organizations filed petitions for review of these revisions with the U.S. Court of Appeals for the Since 2001, merchant energy companies and traditional District of Columbia Circuit. On December 24, 2003, the electric utilities with significant energy marketing and Court of Appeals granted a stay of the October 2003 trading activities have come under severe financial revisions pending its review of the rules and ordered that pressures. Many of these companies have completely 9

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report its review be conducted on an expedited basis. In January December 2000, the Alabama Department of 2004, the Bush Administration announced that it would Environmental Management (ADEM) adopted revisions to continue to enforce the existing rules until the courts the State Implementation Plan (SIP) for meeting the one-resolve legal challenges to the EPA's revised NSR hour ozone standard. These revisions required additional regulations. In any event, the final regulations must be nitrogen oxide emission reductions from May through adopted by the State of Alabama in order to apply to the September of each year at plants in and/or near those Company's facilities. The effect of these final regulations nonattainment areas. Two plants in the Birmingham area and the related legal challenges cannot be determined at are currently subject to those requirements, the most recent this time. of which went into effect in 2003. Construction expenditures for compliance with the nitrogen oxide The Company believes that it complied with applicable emission reduction requirements are estimated to be laws and the EPA's regulations and interpretations in effect at approximately $249 million.

the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per To help ozone nonattainment areas attain the one-hour violation at each generating unit. Prior to January 30, ozone standard, the EPA issued regional nitrogen oxide 1997, the penalty was $25,000 per day. An adverse reduction rules in 1998. Those rules required 21 states, outcome in this matter could require substantial capital including Alabama, to reduce and cap nitrogen oxide expenditures that cannot be determined at this time and emissions from power plants and other large industrial could possibly require payment of substantial penalties. sources. Affected sources, including five of the This could affect future results of operations, cash flows, Company's coal-fired plants, must comply with the and possibly financial condition if such costs are not reduction requirements by May 31, 2004. Additional recovered through regulated rates. construction expenditures for compliance with these rules are currently estimated at approximately $361 million, of EnvironmentalStatutes and Regulations which $317 million remains to be spent.

The Company's operations are subject to extensive In July 1997, the EPA revised the national ambient air regulation by state and federal environmental agencies quality standards for ozone and particulate matter. These under a variety of statutes and regulations governing revisions made the standards significantly more stringent.

environmental media, including air, water, and land In the subsequent litigation of these standards, the U.S.

resources. Compliance with these environmental Supreme Court found the EPA's implementation program requirements will involve significant costs -- both capital for the new eight-hour ozone standard unlawful and and operating -- a major portion of which is expected to be remanded it to the EPA for further rulemaking. During recovered through existing ratemaking provisions. 2003, the EPA proposed implementation rules designed to Environmental costs that are known and estimable at this address the court's concerns. The EPA plans to designate time are included in capital expenditures discussed under areas as attainment or nonattainment with the new eight-

"Capital Requirements and Contractual Obligations." hour ozone standard in April 2004 and with the new fine There is no assurance, however, that all such costs will, in particulate matter standard by the end of 2004. These fact, be recovered. designations will be based on air quality data for 2001 through 2003. Several areas within the Company's service Compliance with the federal Clean Air Act and area are likely to be designated nonattainment under these resulting regulations has been and will continue to be a standards. SIPs, including new emission control significant focus for the Company. The Title IV acid rain regulations necessary to bring those areas into attainment, provisions of the Clean Air Act, for example, required could be required as early as 2007. These SIPs could significant reductions in sulfur dioxide and nitrogen oxide require reductions in sulfur dioxide emissions and could emissions. Title IV compliance, effective in 2000, and require further reductions in nitrogen oxide emissions from associated construction expenditures totaled approximately power plants. If so, reductions could be required

$88 million. Some of these expenditures also assisted the sometime after 2007. The impact of any new standards Company in complying with nitrogen oxide emission will depend on the development and implementation of reduction requirements under Title I of the Clean Air Act, applicable regulations and cannot be determined at this which were designed to address one-hour ozone time.

nonattainment problems in Birmingham, Alabama. In 10

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama I'ower Company 2003 Annual Report In January 2004, the EPA issued a proposed Interstate approaches for the new regulations - a Maximum Air Quality Rule to address interstate transport of ozone Achievable Control Technology approach and a cap-and-and fine particles. This proposed rule would require trade approach. Either approach would require significant additional year-round sulfur dioxide and nitrogen oxide reductions in mercury emissions from Company facilities.

emission reductions from power plants in the eastern The regulations are scheduled to be finalized by the end of United States in two phases - in 2010 and 2015. The EPA 2004, and compliance could be required as early as 2007.

currently plans to finalize this rule by 2005. If finalized, Because the regulations have not been finalized, the the rule could modify or supplant other SIP requirements impact on the Company cannot be determined at this time.

for attainment of the fine particulate matter standard and the eight-hour ozone standard. The impact of this rule on Several major bills to amend the Clean Air Act to the Company will depend upon the specific requirements impose more stringent emissions limitations on power of the final rule and cannot be determined at this time. plants have been proposed by Congress. Three of these, the Bush Administration's Clear Skies Act, the Clean Further reductions in sulfur dioxide and nitrogen oxides Power Act of 2003, and the Clean Air Planning Act of could also be required under the EPA' s Regional Haze 2003, propose to further limit power plant emissions of rules. The Regional Haze rules require states to establish sulfur dioxide, nitrogen oxides, and mercury. The latter Best Available Retrofit Technology (BART) standards for two bills also propose to limit emissions of carbon certain sources that contribute to regional haze. The dioxide. The cost impacts of such legislation would Company has a number of plants that could be subject to depend upon the specific requirements enacted and cannot these rules. The EPA's Regional Haze program calls for be determined at this time.

states to submit SIPs in 2007. The SIPs must contain emission reduction strategies for implementing BART and Domestic efforts to limit greenhouse gas emissions, achieving progress toward the Clean Air Act's visibility have been spurred by international discussions improvement goal. In 2002, however, the U.S. Court of surrounding the Framework Convention on Climate Appeals for the District of Columbia Circuit vacated and Change and, specifically, the Kyoto Protocol, which remanded the BART provisions of the federal Regional proposes international constraints on the emissions of Haze rules to the EPA for further rulemaking. The EPA greenhouse gases. The Bush Administration does not has entered into an agreement that requires proposed support U.S. ratification of the Kyoto Protocol or other revised rules in April 2004 and final rules in 2005. mandatory carbon dioxide reduction legislation and has Because new BART rules have not been developed and instead announced a new voluntary climate initiative, state visibility assessments for progress are only known as Climate VISION, which seeks an 18 percent beginning, it is not possible to determine the effect of these reduction by 2012 in the rate of greenhouse gas emissions rules on the Company at this time. relative to the dollar value of the U.S. economy. The Company is involved in a voluntary electric utility The EPA's Compliance Assurance Monitoring (CAM) industry sector climate change initiative in partnership regulations under Title V of the Clean Air Act require that with the government. The electric utility sector has monitoring be performed to ensure compliance with pledged to reduce its greenhouse gas intensity 3 percent to emissions limitations on an ongoing basis. In 2004 and 5 percent over the next decade and is in the process of 2005, a number of the Company's plants will likely developing a memorandum of understanding with the become subject to CAM requirements for at least one Department of Energy (DOE) tb cover this voluntary pollutant, in most cases particulate matter. The Company program.

is in the process of developing CAM plans. Because the plans are still under development, the Company cannot The Company must comply with other environmental determine the costs associated with implementation of the laws and regulations that cover the handling and disposal CAM regulations. Actual ongoing monitoring costs are of waste and releases of hazardous substances. Under expensed as incurred and are not material for any year these various laws and regulations, the Company could presented. incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any In January 2004, the EPA issued proposed rules required cleanup and will recognize in its financial regulating mercury emissions from electric utility boilers. statements costs to clean up known sites. Amounts for The proposal solicits comments on two possible cleanup and ongoing monitoring costs were not material 11

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report for any new year presented. The Company may be liable FERC Matters for some or all required cleanup costs for additional sites that may require environmental remediation. The Transmission Company has not incurred any significant cleanup costs to date. In December 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule (Order 2000) on Under the Clean Water Act, the EPA has been Regional Transmission Organizations (RTOs). Order developing new rules aimed at reducing impingement and 2000 encouraged utilities owning transmission systems to entrainment of fish and fish larvae at power plants' form RTOs on a voluntary basis. Through Southern cooling water intake structures. On February 16, 2004, Company, the Company worked with a number of utilities the EPA finalized these rules. These rules will require in the Southeast to develop a for-profit RTO known as biological studies and, perhaps, retrofits to some intake SeTrans. In 2002, the sponsors of SeTrans established a structures at existing power plants. The impact of these Stakeholder Advisory Committee to provide input into the new rules will depend on the results of studies and development of the RTO from other sectors of the electric analyses performed as part of the rules' implementation. industry, as well as consumers. During the development of SeTrans, state regulatory authorities expressed concern In addition, under the Clean Water Act, the EPA and over certain aspects of the FERC' s policies regarding the ADEM are developing total maximum daily loads RTOs. In December 2003, the SeTrans sponsors (TMDLs) for certain impaired waters. Establishment of announced that they would suspend work on SeTrans maximum loads by the EPA or the ADEM may result in because the regulated utility participants, including lowering permit limits for various pollutants and a Southern Company's retail operating companies, had requirement to take additional measures to control non- determined that it was highly unlikely to obtain support of point source pollution (e.g., storm water runoff) at both federal and state regulatory authorities. Any impact facilities that discharge into waters for which TMDLs are of the FERC's rule on the Company will depend on the established. Because the effect on the Company will regulatory reaction to the suspension of SeTrans and depend on the actual TMDLs and permit limitations future developments, which cannot now be determined.

established by the implementing agency, it is not possible to determine the effect on the Company at this time. In July 2002, the FERC issued a notice of proposed rulemaking regarding open access transmission service Several major pieces of environmental legislation are and standard electricity market design. The proposal, if periodically considered for reauthorization or amendment adopted, would among other things: (1) require by Congress. These include: the Clean Air Act; the Clean transmission assets of jurisdictional utilities to be operated Water Act; the Comprehensive Environmental Response, by an independent entity; (2) establish a standard market Compensation, and Liability Act; the Resource design; (3) establish a single type of transmission service Conservation and Recovery Act; the Toxic Substances that applies to all customers; (4) assert jurisdiction over Control Act; the Emergency Planning & Community the transmission component of bundled retail service; (5)

Right-to-Know Act; and the Endangered Species Act. establish a generation reserve margin; (6) establish bid caps for day ahead and spot energy markets; and (7) revise Compliance with possible additional federal or state the FERC policy on the pricing of transmission legislation or regulations related to global climate change, expansions. Comments on the proposal were submitted electromagnetic fields, or other environmental and health by many interested parties, including Southern Company concerns could also significantly affect the Company. The and the Company, and the FERC has indicated that it has impact of any new legislation, changes to existing revised certain aspects of the proposal in response to legislation, or environmental regulations could affect many public comments. Proposed energy legislation would areas of the Company's operations. The full impact of any prohibit the FERC from issuing the final rule before such changes cannot, however, be determined at this time. October 31, 2006, and from making any final rule effective before December 31, 2006. That legislation has been approved by the House of Representatives but remains pending before the Senate. Passage of the legislation now appears in doubt. It is uncertain whether in the absence of legislation the FERC will move forward 12

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report with any part or all of the proposed rule. Any impact of outcome of this matter will depend on the form in which this proposal on the Company will depend on the form in the SMA test and mitigation measures rules may be which the final rule may be ultimately adopted. However, ultimately adopted and cannot be determined at this time.

the Company's financial statements could be adversely affected by changes in the transmission regulatory Other Matters structure in its regional power market.

In accordance with Financial Accounting Standards Board Hydro Relicensing (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash pension In 2002, the Company initiated the relicensing process income, before tax, of approximately $52 million, $56 for the Company's seven hydroelectric projects on the million, and $57 million in 2003, 2002, and 2001, Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, respectively. Future pension income is dependent on Jordan, and Bouldin) and the Smith and Bankhead several factors including trust earnings and changes to the Projects on the Warrior River. The FERC licenses for all plan. The decline in pension income is expected to of these nine projects expire in 2007. Upon or after the continue and become an expense as early as 2011.

expiration of each license, the United States Government, Postretirement benefit costs for the Company were $23 by act of Congress, may take over the project or the FERC million, $23 million, and $21 million in 2003, 2002, and may relicense the project either to the original licensee or 2001, respectively, and are expected to continue to trend to a new licensee. The FERC may grant relicenses subject upward. A portion of pension income and postretirement to certain requirements that could result in additional costs to the Company. benefit costs is capitalized based on construction-related labor charges. Pension income or expense and Market-Based Rate Authority postretirement benefit costs are a component of the regulated rates and generally do not have a long-term The Company has obtained FERC approval to sell power effect on net income. For more information regarding to nonaffiliates at market-based prices under specific pension and postretirement benefits, see Note 2 to the contracts. Through SCS, as agent, the Company also has financial statements.

FERC authority to make short-term opportunity sales at market rates. Specific FERC approval must be obtained Prices for electricity provided by the Company to retail with respect to a market-based contract with an affiliate. customers are set by the Alabama PSC under cost-based In November 2001, the FERC modified the test it uses to regulatory principles. Rates for the Company can be consider utilities' applications to charge market-based adjusted periodically within certain limitations based on rates and adopted a new test called the Supply Margin earned retail rate of return compared with an allowed Assessment (SMA). The FERC applied the SMA to return range. Increases in retail rates of 2 percent were several utilities, including Southern Company's retail effective in both April 2002 and October 2001 in operating companies, and found them to be "pivotal accordance with the Rate Stabilization Equalization plan.

suppliers" in their service areas and ordered the implementation of several mitigation measures. SCS, on The rates also provide for adjustments to recognize the behalf of the retail operating companies, sought rehearing placing of new generating facilities into retail service and of the FERC order, and the FERC delayed the the recovery of retail costs associated with certificated implementation of certain mitigation measures. SCS, on purchased power agreements (PPAs) under Rate CNP behalf of the retail operating companies, submitted (Certificated New Plant). Effective July 2001, the comments to the FERC in 2002 regarding these issues. In Company's retail rates were adjusted by 0.6 percent under December 2003, the FERC issued a staff paper discussing Rate CNP to recover costs for Plant Barry Unit 7, which alternatives and held a technical conference in January was placed into commercial operation on May 1, 2001.

2004. The Company anticipates that the FERC will Effective July 2003, the Company's retail rates were address the requests for rehearing in the near future. adjusted by approximately 2.6% under Rate CNP as a Regardless of the outcome of the SMA proposal, the result of two new certificated PPAs that began in June FERC retains the ability to modify or withdraw the 2003. See Note 3 to the financial statements under "Retail authorization for any seller to sell at market-based rates, if Rate Adjustment Procedures" for additional information.

it determines that the underlying conditions for having such authority are no longer applicable. The final 13

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report On December 8, 2003, President Bush signed into law ACCOUNTING POLICIES the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). The Application of Critical Accounting Policies and Medicare Act introduces a prescription drug benefit for Estimates Medicare-eligible retirees starting in 2006, as well as a federal subsidy to plan sponsors like the Company that The Company prepares its financial statements in provide prescription drug benefits. In accordance with accordance with accounting principles generally FASB Staff Position No. 106-1, the Company has elected accepted in the United States. Significant accounting to defer recognizing the effects of the Medicare Act for its policies are described in Note 1 to the financial postretirement plans under FASB Statement No. 106, statements. In the application of these policies, certain estimates are made that may have a material impact on Employers' Accounting for Postretirement Benefits Other the Company's results of operations and related than Pension until authoritative guidance on accounting disclosures. Different assumptions and measurements for the federal subsidy is issued or until a significant event could produce estimates that are significantly different occurs that would require remeasurement of the plans' from those recorded in the financial statements. Senior assets and obligations. The Company anticipates that the management has discussed the development and benefits it pays after 2006 will be lower as a result of the selection of the critical accounting policies and Medicare Act; however, the retiree medical obligations estimates described below with the Controls and and costs reported in Note 2 to the financial statements do Compliance Committee of the Company's Board of not reflect these changes. The final accounting guidance Directors and the Audit Committee of Southern could require changes to previously reported information. Company's Board of Directors.

Nuclear security legislation was recently introduced and Electric Utility Regulation considered in Congress both as a free-standing bill in the Senate and as a part of comprehensive energy legislation The Company is subject to retail regulation by the in a House-Senate Conference Report. Neither of the Alabama PSC and wholesale regulation by the FERC.

proposals has been enacted. The Nuclear Regulatory These regulatory agencies set the rates the Company is Commission (NRC) also ordered additional security permitted to charge customers based on allowable measures for licensees in 2003. The Company is in the costs. As a result, the Company applies FASB Statement No. 71, Accounting for the Effects of Certain process of implementation and must be in full compliance Types of Regulation. Through the ratemaking process, with these orders by October 29, 2004. The requirements the regulators may require the inclusion of costs or of the latest orders will have an impact on the Company's revenues in periods different than when they would be Plant Farley and will result in increased operation and recognized by a non-regulated company. This maintenance expenses as well as additional capital treatment may result in the deferral of expenses and the expenditures. The precise impact of the new requirements recording of related regulatory assets based on will depend upon the details of the implementation of the anticipated future recovery through rates or the deferral new requirements, which have not been finalized. of gains or creation of liabilities and the recording of related regulatory liabilities. The application of The Company filed an application with the NRC in Statement No. 71 has a further effect on the Company's September 2003 to extend the operating license for Plant financial statements as a result of the estimates of Farley for an additional 20 years. If approved by the allowable costs used in the ratemaking process. These NRC, the Company's depreciation and amortization estimates may differ from those actually incurred by the expense could be reduced pending approval by the Company; therefore, the accounting estimates inherent Alabama PSC. in specific costs such as depreciation, nuclear decommissioning, and pension and post-retirement The Company is involved in various matters being benefits have less of a direct impact on the Company's litigated and regulatory matters that could affect future results of operations than they would on a non-earnings. See Note 3 to the financial statements for regulated company.

information regarding material issues.

As reflected in Note 1 to the financial statements under "Regulatory Assets and Liabilities," significant regulatory assets and liabilities have been recorded.

Management reviews the ultimate recoverability of 14

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report these regulatory assets and liabilities based on retirement is recorded in the period in which the applicable regulatory guidelines. However, adverse liability is incurred. The costs are capitalized as part of legislation and judicial or regulatory actions could the related long-lived asset and depreciated over the materially impact the amounts of such regulatory assets asset's useful life. Additionally, non-regulated and liabilities and could adversely impact the companies are no longer permitted to continue accruing Company's financial statements. future retirement costs for long-lived assets that they do not have a legal obligation to retire. For more Contingent Obligations information regarding the impact of adopting this standard effective January 1, 2003, see Note I to the The Company is subject to a number of federal and state financial statements under "Asset Retirement laws and regulations, as well as other factors and conditions that potentially subject it to environmental, Obligations and Other Costs of Removal."

litigation, income tax, and other risks. See "Future Earnings Potential" and Note 3 to the financial FASB Statement No. 149, Amendment of Statement statements for more information regarding certain of 133 on Derivative Instruments and Hedging Activities, these contingencies. The Company periodically which further amends and clarifies the accounting and evaluates its exposure to such risks and records reserves reporting for derivative instruments, became effective for those matters where a loss is considered probable and generally for financial instruments entered into or reasonably estimable in accordance with generally modified after June 30, 2003. Current interpretations of accepted accounting principles. The adequacy of Statement No. 149 indicate that certain electricity forward reserves can be significantly affected by external events transactions subject to unplanned netting -- including or conditions that can be unpredictable; thus, the those typically referred to as "book outs" -- may only ultimate outcome of such matters could materially affect qualify as cash flow hedges if an entity can demonstrate the Company's financial statements. These events or that physical delivery or receipt of power occurred. The conditions include the following: Company's forward electricity contracts continue to be exempt from fair value accounting requirements or to

• Changes in existing state or federal regulation by qualify as cash flow hedges, with the related gains and governmental authorities having jurisdiction over air losses deferred in other comprehensive income. The quality, water quality, control of toxic substances, implementation of Statement No, 149 did not have a hazardous and solid wastes, and other environmental matters. material effect on the Company's financial statements.

• Changes in existing income tax regulations or changes in Internal Revenue Service interpretations of In July 2003, the Emerging Issues Task Force (EITF) existing regulations. of FASB issued EITF No. 03-1 1, which became effective

• Identification of sites that require environmental on October 1, 2003. The standard addresses the reporting remediation or the filing of other complaints in which of realized gains and losses on derivative instruments and the Company may be asserted to be a potentially is being interpreted to require book outs to be recorded on responsible party. a net basis in operating revenues. Adoption of this

• Identification and evaluation of other potential standard did not have a material impact on the Company's lawsuits or complaints in which the Company may be financial statements.

named as a defendant.

• Resolution or progression of existing matters through FASB Interpretation No. 46, Consolidation of Variable the legislative process, the court systems, or the EPA. Interest Entities, which was originally issued in January 2003, requires the primary beneficiary of a variable New Accounting Standards interest entity to consolidate the related assets and liabilities. In December 2003, the FASB revised Prior to January 2003, the Company accrued for the Interpretation No. 46 and deferred the effective date until ultimate cost of retiring most long-lived assets over the March 31, 2004 for interests held in variable interest life of the related asset through depreciation expense. entities other than special purpose entities.

FASB Statement No. 143, Accounting for Asset Retirement Obligations established new accounting and Current analysis indicates that the trusts established by reporting standards for legal obligations associated with the Company to issue preferred securities are variable the ultimate cost of retiring long-lived assets. The interest entities under Interpretation No. 46, and that the present value of the ultimate costs of an asset's future 15

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report Company is not the primary beneficiary of these trusts. If 2001. See Note 6 to the financial statements for additional this conclusion is finalized, effective March 31, 2004, the information.

trust assets and liabilities -- including the preferred securities issued by the trusts -- will be deconsolidated. Sources of Capital The investments in the trusts and the loans from the trusts The Company plans to obtain the funds required for to the Company will be reflected as equity method construction and other purposes from sources similar to investments and as long-term notes payable to affiliates, those used in the past, which were primarily from respectively, on the Balance Sheets. Based on December operating cash flows. However, the type and timing of 31, 2003 values, this treatment would result in an increase any financings -- if needed -- will depend on market of approximately $9 million to both total assets and total conditions and regulatory approval. In recent years, liabilities. See Note 6 to the financial statements under financings primarily have utilized unsecured debt and "Mandatorily Redeemable Preferred Securities" for preferred securities.

additional information.

The Company obtains financing separately without In May 2003, the FASB issued Statement No. 150, credit support from any affiliate. The Southern Company Accounting for Certain Financial Instruments with system does not maintain a centralized cash or money Characteristics of Both Liabilities and Equity, which pool. Therefore, funds of the Company are not requires classification of certain financial instruments commingled with funds of any other company. In within its scope, including shares that are mandatorily accordance with the Public Utility Holding Company Act, redeemable, as liabilities. Statement No. 150 was most loans between affiliated companies must be effective for financial instruments entered into or modified approved in advance by the Securities and Exchange after May 31, 2003, and otherwise on July 1, 2003. In Commission (SEC).

accordance with Statement No. 150, mandatorily redeemable preferred securities are reflected in the The Company's current liabilities exceed current assets Balance Sheets as liabilities. The adoption of Statement because of securities due within one year. The Company No. 150 had no impact on the Statements of Income and intends to refinance debt that comes due during 2004.

Cash Flows.

To meet short-term cash needs and contingencies, the FINANCIAL CONDITION AND LIQUIDITY Company has various internal and external sources of liquidity. At the beginning of 2004, the Company had Overview approximately $43 million of cash and cash equivalents and

$865 million of unused credit arrangements with banks, as Over the last several years, the Company's financial shown in the following table. In addition, the Company condition has remained stable with emphasis on cost has substantial cash flow from operating activities and control measures combined with significantly lower cost access to the capital markets, including commercial paper of capital, achieved through the refinancing and/or programs, to meet liquidity needs. Cash flows from redemption of higher-cost long-term debt and preferred operating activities were $1,118 million in 2003, $973 stock. The Company operated at high levels of reliability million in 2002, and $843 million in 2001.

while achieving industry-leading customer satisfaction levels and continuing to have retail prices below the At the beginning of 2004, bank credit arrangements are national average. as follows:

The Company had gross property additions of $649 Expires million in 2003. The majority of funds needed for gross 2005 property additions for the last several years have been Total Unused 2004 & Beyond (in millions) provided from operating activities. The Statements of

$865 $865 $865 Cash Flows provide additional details.

Approximately $450 million of the credit facilities The Company's ratio of common equity to total expiring in 2004 allow for the execution of term loans for capitalization -- including short-term debt -- was 43.3 an additional two-year period and $245 million allow for percent in 2003, 42.6 percent in 2002, and 42.8 percent in the execution for a one-year period. See Note 6 to the 16

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report financial statements under "Bank Credit Arrangements" accelerated payment -- in the event of a credit rating for additional information. change to below investment grade. These contracts are primarily for physical electricity purchases and sales, The Company may also meet short-term cash needs fixed-price physical gas purchases, and agreements through a Southern Company subsidiary organized to covering interest rate swaps. At December 31, 2003, the issue and sell commercial paper and extendible maximum potential collateral requirements under the commercial notes at the request and for the benefit of the electricity purchase and sale contracts were approximately Company and the other Southern Company retail $26.7 million. Generally, collateral may be provided for operating companies. Proceeds from such issuances for by a Company guaranty, a letter of credit, or cash. At the benefit of the Company are loaned directly to the December 31, 2003, there were no material collateral Company and are not commingled with proceeds from requirements for the gas purchase contracts or other such issuances for the benefit of any other operating financial instrument agreements.

company. The obligations of each company under these Market Price Risk arrangements are several; there is no cross affiliate credit support. At December 31, 2003, the Company had no Due to cost-based rate regulations, the Company has commercial paper outstanding. limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To Financing Activities manage the volatility attributable to these exposures, the In 2003, the Company's financing costs decreased due to Company nets the exposures to take advantage of natural lower interest rates despite the issuance of an increased offsets and enters into various derivative transactions for amount of senior securities during the year. New issues the remaining exposures pursuant to the Company's during 2001 through 2003 totaled $3.3 billion and policies in areas such as counterparty exposure and retirement or repayment of higher-cost securities totaled hedging practices. Company policy is that derivatives are

$2.8 billion. to be used primarily for hedging purposes. Derivative positions are monitored using techniques that include Composite financing rates for long-term debt, market valuation and sensitivity analysis.

preferred stock, and preferred securities for the years 2001 through 2003, as of year-end, were as follows: To mitigate exposure to interest rates, the Company has entered into interest rate swaps that have been designated 2003 2002 2001 as hedges. The weighted average interest rate on Long-term debt interest outstanding variable long-term debt, that has not been rate 4.42% 5.05% 5.72% hedged at December 31, 2003 was 1.38 percent. If the Preferred securities Company sustained a 100 basis point change in interest rates for all unhedged variable rate long-term debt, the distribution rate 5.25 5.25 6.96 change would affect annualized interest expense by Preferred stock dividend approximately $0.5 million at December 31, 2003. The rate 5.10 5.17 4.79 Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.

Subsequent to December 31, 2003, the Company has For further information, see Notes I and 6 to the financial entered into interest rate hedging transactions related to the statements under "Financial Instruments."

anticipated refinancing of $470 million of securities due within one year. Also, an additional $300 million of To mitigate residual risks relative to movements in securities have been issued for other general corporate electricity prices, the Company enters into fixed price purposes including repayment of outstanding short-term contracts for the purchase and sale of electricity through indebtedness and the funding of the Company's the wholesale electricity market, and, to a lesser extent, continuous construction program. into similar contracts for gas purchases.

Credit Rating Risk In addition, in October 2001, the Alabama PSC approved a revision to the Company's Rate ECR (Energy The Company does not have any credit agreements that would require material changes in payment schedules or Cost Recovery) allowing the recovery of specific costs terminations as a result of a credit rating downgrade. associated with the sales of natural gas that become There are contracts that could require collateral -- but not necessary due to operating considerations at its electric 17

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report generating facilities. This revision also includes the cost Unrealized pre-tax gains (losses) on energy contracts of of financial instruments used for hedging market price risk $(0.1) million, $(2.0) million, and $2.0 million were up to 75 percent of the budgeted annual amount of natural recognized in income in 2003, 2002, and 2001, gas purchases. The Company may not engage in natural respectively. The Company is exposed to market price gas hedging activities that extend beyond a rolling 42- risk in the event of nonperformance by counterparties to month window. Also, the premiums paid for natural gas the derivative energy contracts. The Company's policy is financial options may not exceed 5 percent of the to enter into agreements with counterparties that have Company's natural gas budget for that year. investment grade credit ratings by Moody's and Standard

& Poor's or with counterparties who have posted At December 31, 2003, exposure from these activities collateral to cover potential credit exposure. Therefore, was not material to the Company's financial position, the Company does not anticipate market risk exposure results of operations, or cash flows. The changes in fair from nonperformance by the counterparties. For value of derivative energy contracts and year-end additional information, see Notes I and 6 to the financial valuations were as follows: statements under "Financial Instruments."

Changes in Fair Value 2003 2002 Capital Requirements and Contractual Obligations (in thousands)

Contracts beginning of year $ 21,402 $ 214 The construction program of the Company is currently Contracts realized or settled (38,809) (21,088) estimated to be $791 million for 2004, $863 million for New contracts at inception - - 2005, and $884 million for 2006. Over the next three Changes in valuation techniques - - years, the Company estimates spending $713 million on Current period changes 23,820 42,276 environmental related additions (including $358 million Contracts end of year $ 6,413 $ 21,402 on Selective Catalytic Reduction facilities), $267 million on Plant Farley (including $155 million for nuclear fuel, Source of 2003 Year-End $29 million on cooling towers and $26 million on Valuation Prices replacing reactor vessel heads), $701 million on Total Maturity distribution facilities, and $402 million on transmission Fair Value 2004 2005-2006 additions. See Note 7 to the financial statements under (in thousands) "Construction Program" for additional details.

Actively quoted $6,413 $7,803 $(1,390)

External sources - - Actual construction costs may vary from this estimate Models and other because of changes in such factors as: business methods - - conditions; environmental regulations; nuclear plant Contracts end of Year $6,413 $7,803 $(1,390) regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction Unrealized gains and losses from mark to market labor, equipment, and materials; and the cost of capital. In adjustments on derivative contracts related to the addition, there can be no assurance that costs related to Company's fuel hedging programs are recorded as capital expenditures will be fully recovered.

regulatory assets and liabilities. Realized gains and losses from these programs are included in fuel expense and are In addition to the funds required for the Company's recovered through the Company's fuel cost recovery construction program, approximately $1.5 billion will be clause. Gains and losses on derivative contracts that are required by the end of 2006 for maturities of long-term not designated as hedges are recognized in the income debt. The Company plans to continue, when economically statement as incurred. At December 31, 2003, the fair feasible, to retire higher cost debt, preferred securities, and value of derivative energy contracts was reflected in the preferred stock and replace these obligations with lower-financial statements as follows: cost capital if market conditions permit.

Amounts (in thousands) As a result of requirements by the NRC, the Company Regulatory liabilities, net $6,402 has established external trust funds for the purpose of Net income 11 funding nuclear decommissioning costs. Annual Total fair value $6,413 provisions for nuclear decommissioning are based on an 18

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report annuity method as approved by the Alabama PSC. The fund for postretirement benefits as ordered by the amount expensed in 2003 was $18 million. For additional Alabama PSC. The cumulative effect of funding these information, see Note I to the financial statements under items over a long period will diminish internally funded "Nuclear Decommissioning." Additionally, as discussed capital and may require capital from other sources. For in Note 1 to the financial statements under "Revenues and additional information, see Note 2 to the financial Fuel Costs," in 1993, the DOE implemented a special statements under "Postretirement Benefits."

assessment over a 15-year period on utilities with nuclear plants to be used for the decontamination and The capital requirements, lease obligations, decommissioning of its nuclear fuel enrichment facilities. purchase commitments, and trust requirements -

discussed above and in the financial statements - are In 1994, the Company also established an external trust summarized as follows: (See Notes 1, 6, and 7 to the financial statements for additional information.)

2005- 2007- After 2004 2006 2008 2008 Total (in millions)

Long-term debt and preferred securities(a) --

Principal $ 526.0 $ 940.5 $ 610.0 $2,135.1 $ 4,211.6 Interest and distributions 188.8 302.5 241.9 2,048.0 2,781.2 Preferred stock dividends(b) 19.0 38.0 38.0 95.0 Operating leases 29.7 42.7 13.5 35.2 121.1 Purchase commitments(c) --

Capital(d) 778.0 1,729.1 2,507.1 Coal and nuclear fuel 750.4 951.0 582.7 2,284.1 Natural gas(e) 318.3 338.5 133.1 107.7 897.6 Purchased power 85.0 175.0 178.0 129.0 567.0 Long-term service agreements 18.3 17.8 57.6 119.2 212.9 Trusts --

Nuclear decommissioning 20.3 40.6 40.6 222.5 324.0 Postretirement benefits( 1 4.2 48.5 - - 52.7 DOE assessments 4.4 8.7 - - 13.1 Total $2,742.4 $4,632.9 $1,895.4 $4,796.7 $14,067.4 (a) All amounts are reflected based on final maturity dates. The Company will 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, 2004, as reflected in the Statements of Capitalization.

(b) Preferred stock does not mature; therefore, amounts are provided for the next five years only.

(c) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for the last three years were $921 million, $854 million, and $784 million, respectively.

(d) The 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, 2003, significant purchase commitments were outstanding in connection with the construction program.

(e) 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 future prices at December 31, 2003.

(f) The Company forecasts post-retirement trust contributions over a three-year period. No contributions related to the Company's pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension plan.

19

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2003 Annual Report Cautionary Statement Regarding Forward-Looking Information The Company's 2003 Annual Report includes forward-looking statements in addition to historical information.

Forward-looking information includes, among other things, statements concerning the Company's estimated construction and other expenditures, and the Company's projections for energy sales and its goals for future generating capacity and earnings growth. 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 comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental, tax, and other laws and regulations to which the Company is 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 action against the Company;

• the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;

• the impact of fluctuations in commodity prices, interest rates, and customer demand;

• available sources and costs of fuels;

• ability to control costs;

• investment performance of the Company's employee benefit plans;

• advances in technology;

• state and federal rate regulations and pending and future rate cases and negotiations;

• effects of and changes in political, legal, and economic conditions and developments in the United States, including the current soft economy;

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

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

• the ability of counterparties of the Company to make payments as and when due;

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

• the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 1 1, 2001, or any similar incidents or responses to such incidents;

• financial market conditions and the results of financing efforts, including the Company's credit ratings;

• the ability of the Company to obtain additional generating capacity at competitive prices;

• weather and other natural phenomena;

• the direct or indirect effects on the Company's business resulting from the August 2003 power outage in the Northeast, or any similar incidents;

• 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 from time to time by the Company with the SEC.

20

STATEMENTS OF INCOME For the Years Ended December 31, 2003, 2002, and 2001 Alabama Power Company 2003 Annual Report 2003 2002 2001 (in thousands)

Operating Revenues:

Retail sales $3,051,463 $2,951,217 $2,747,673 Sales for resale --

Non-affiliates 487,456 474,291 485,974 Affiliates 277,287 188,163 245,189 Other revenues 143,955 96,862 107,554 Total operating revenues 3,960,161 3,710,533 3,586,390 Operating Expenses:

Fuel 1,067,821 969,521 1,000,828 Purchased power --

Non-affiliates 110,885 90,998 144,991 Affiliates 204,353 158,121 147,967 Other operations 611,418 574,979 508,264 Maintenance 309,451 279,406 275,510 Depreciation and amortization 412,919 398,428 383,473 Taxes other than income taxes 228,414 216,919 214,665 Total operating expenses 2,945,261 2,688,372 2,675,698 Operating Income 1,014,900 1,022,161 910,692 Other Income and (Expense):

Allowance for equity funds used during construction 12,594 11,168 7,092 Interest income 15,220 13,991 15,101 Interest expense, net of amounts capitalized (214,302) (225,706) (246,436)

Distributions on mandatorily redeemable preferred securities (15,255) (24,599) (24,775)

Other income (expense), net (31,702) (28,785) (11,177)

Total other income and (expense) (233,445) (253,931) (260,195)

Earnings Before Income Taxes 781,455 768,230 650,497 Income taxes 290,378 292,436 248,597 Earnings Before Cumulative Effect of Accounting Change 491,077 475,794 401,900 Cumulative effect of accounting change--

less income taxes of $215 thousand - - 353 Net Income 491,077 475,794 402,253 Dividends on Preferred Stock 18,267 14,439 15,524 Net Income After Dividends on Preferred Stock $ 472.810 $ 461,355 $ 386,729 The accompanying notes are an integral part of these financial statements.

21

BALANCE SHEETS At December 31, 2003 and 2002 Alabama Power Company 2003 Annual Report Assets 2003 2002 (in thousands)

Current Assets:

Cash and cash equivalents $ 42,752 $ 22,685 Receivables --

Customer accounts receivable 240,562 240,052 Unbilled revenues 95,953 89,336 Other accounts and notes receivable 53,547 47,535 Affiliated companies 48,876 74,099 Accumulated provision for uncollectible accounts (4,756) (4,827)

Fossil fuel stock, at average cost 86,993 73,742 Vacation pay 35,530 33,901 Materials and supplies, at average cost 211,690 207,872 Prepaid expenses 44,608 40,411 Other 19,454 27,210 Total current assets 875,209 852,016 Property, Plant, and Equipment:

In service 14,224,117 13,506,170 Less accumulated provision for depreciation 4,905,920 4,658,803 9,318,197 8,847,367 Nuclear fuel, at amortized cost 93,611 103,088 Construction work in progress 321,316 458,375 Total property, plant, and equipment 9,733,124 9,408,830 Other Property and Investments:

Equity investments in unconsolidated subsidiaries 47,811 45,553 Nuclear decommissioning trusts, at fair value 384,574 292,297 Other 16,992 16,477 Total other property and investments 449,377 354,327 Deferred Charges and Other Assets:

Deferred charges related to income taxes 321,077 327,276 Prepaid pension costs 446,256 389,793 Unamortized loss on reacquired debt 110,946 103,819 Department of Energy assessments 13,092 17,144 Other 121,543 138,461 Total deferred charges and other assets 1,012,914 976,493 Total Assets $12,070,624 $11,591,666 The accompanying notes are an integral part of these financial statements.

22

BALANCE SHEETS At December 31, 2003 and 2002 Alabama Power Company 2003 Annual Report Liabilities and Stockholder's Equity 2003 2002 (in thousands)

Current Liabilities:

Securities due within one year $ 526,019 $ 1,117,945 Notes payable - 36,991 Accounts payable --

Affiliated 135,017 109,790 Other 162,314 141,251 Customer deposits 47,507 44,410 Accrued taxes --

Income taxes 83,544 80,438 Other 22,273 20,561 Accrued interest 46,489 36,344 Accrued vacation pay 35,530 33,901 Accrued compensation 75,620 74,099 Other 34,513 49,715 Total current liabilities 1,168,826 1,745,445 Long-term debt (See accompanying statements) 3,377,148 2,872,609 Mandatorily redeemable preferred securities (See accompanying statements) 300,000 300,000 Deferred Credits and Other Liabilities:

Accumulated deferred income taxes 1,571,076 1,436,559 Deferred credits related to income taxes 162,168 177,205 Accumulated deferred investment tax credits 216,309 227,270 Employee benefit obligations 180,960 156,526 Deferred capacity revenues 36,567 46,155 Asset retirement obligations 358,759 Asset retirement obligation regulatory liability 127,346 Other cost of removal obligations 574,445 884,613 Miscellaneous regulatory liabilities 86,323 79,545 Other 37,525 40,487 Total deferred credits and other liabilities 3,351,478 3,048,360 Total liabilities 8,197,452 7,966,414 Cumulative preferred stock (See accompanying statements) 372,512 247,512 Common stockholder's equity (See accompanying statements) 3,500,660 3,377,740 Total Liabilities and Stockholder's Eguitv $12.070,624 $11,591,666 Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

23

STATEMENTS OF CAPITALIZATION At December 31, 2003 and 2002 Alabama Power Company 2003 Annual Report 2003 2002 2003 2002 (in thousands) (percent of total)

Long-Term Debt:

Long-term notes payable --

Variable rate (1.525% at 1/l/03) due 2003 $ - $ 517,000 5.35% to 7.85% due 2003 - 406,200 4.875% to 7.125% due 2004 525,000 525,000 5.49% due November 1, 2005 225,000 225,000 2.65% to 2.80% due 2006 520,000 Floating rate (1.37% at 1/1/04) due 2006 195,000 7.125% due October 1, 2007 200,000 200,000 3.125% to 5.375% due 2008 410,000 160,000 4.70% to 6.75% due 2010-2039 1,275,000 1,408,800 Total long-term notes payable 3,350,000 3,442,000 Other long-term debt --

Pollution control revenue bonds --

Collateralized:

5.50% due 2024 24,400 24,400 Variable rates (1.27% to 1.33% at 1/1/04) due 2015-2017 89,800 89,800 Non-collateralized:

Variable rates (1.23% to 1.45% at 1/1/04) due 2021-2031 445,940 445,940 Total other long-term debt 560,140 560,140 Capitalized lease obligations 1,497 2,439 Unamortized debt premium (discount), net (8,470) (14,025)

Total long-term debt (annual interest requirement -- $173.0 million) 3,903,167 3,990,554 Less amount due within one year 526,019 1,117,945 Long-term debt excluding amount due within one year $3,377,148 $2,872,609 44.7% 42.3%

24

STATEMENTS OF CAPITALIZATION (continued)

At December 31, 2003 and 2002 Alabama Power Company 2003 Annual Report 2003 2002 2003 2002 (in thousands) (percent of total)

Mandatorily Redeemable Preferred Securities:

$1,000 liquidation value due 2042 --

4.75% through 2007* $ 100,000 $ 100,000 5.50% through 2009* 200,000 200,000 Total (annual distribution requirement -- $15.8 million) 300,000 300,000 4.0 4.4 Cumulative Preferred Stock:

$ 100 par or stated value --

4.20% to 4.92% 47,512 47,512

$25 par or stated value --

5.20% to 5.83% 200,000 200,000

$100,000 stated value --

4.95% 125,000 Total (annual dividend requirement -- $19.0 million) 372,512 247,512 4.9 3.6 Common Stockholder's Equity:

Common stock, par value $40 per share --

Authorized - 15,000,000 shares in 2003 and 6,000,000 shares in 2002 Outstanding - 7,250,000 shares in 2003 and 6,000,000 shares in 2002 Par value 290,000 240,000 Paid-in capital 1,926,970 1,900,464 Premium on Preferred Stock 99 99 Retained earnings 1,291,558 1,250,594 Accumulated other comprehensive income (loss) (7,967) (13,417)

Total common stockholder's equity 3,500,660 3,377,740 46.4 49.7 Total Capitalization $7,550,320 $6,797,861 100.0% 100.0%

• The fixed rates thereafter are determined through remarketings for specific periods of varying length or at floating rates determined by reference to 3-month LIBOR plus 2.91% and 3.10%, respectively.

The accompanying notes are an integral part of these financial statements.

25

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2003, 2002, and 2001 Alabama Power Company 2003 Annual Report Premium on Other Common Paid-In Preferred Retained Comprehensive Stock Capital Stock Earnings Income (loss) Total (in thousands)

Balance at December 31, 2000 $224,358 $1,743,363 $99 $1,227,952 $ - $3,195,772 Net income after dividends on preferred stock - - - 386,729 - 386,729 Issuance of common stock 15,642 - - - - 15,642 Capital contributions from parent company - 107,313 - - - 107,313 Cash dividends on common stock - - - (393,900) - (393,900)

Other - - (679) - (679)

Balance at December 31, 2001 240,000 1,850,676 99 1,220,102 - 3,310,877 Net income after dividends on preferred stock - - - 461,355 - 461,355 Capital contributions from parent company - 49,788 - - - 49,788 Other comprehensive income (loss) - - - - (13,417) (13,417)

Cash dividends on common stock - - - (431,000) - (431,000)

Other - - 137 - 137 Balance at December 31, 2002 240,000 1,900,464 99 1,250,594 (13,417) 3,377,740 Net income after dividends on preferred stock - - - 472,810 - 472,810 Issuance of common stock 50,000 - - - - 50,000 Capital contributions from parent company - 26,506 - - - 26,506 Other comprehensive income (loss) - - - 5,450 5,450 Cash dividends on common stock - - (430,200) - (430,200)

Other (1,646) - (1,646)

Balance at December 31. 2003 $290,000 $1,926,970 $99 $1,291,558 $ (7,967) $3,500,660 The accompanying notes are an integral part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2003, 2002, and 2001 Alabama Power Company 2003 Annual Report 2003 2002 2001 (in thousands)

Net income after dividends on preferred stock $472,810 $461,355 $386,729 Other comprehensive income (loss):

Change in additional minimum pension liability, net of tax of

$(2,301) and $(2,536), respectively (3,785) (4,172)

Changes in fair value of qualifying hedges, net of tax of

$1,330 and $(6,430), respectively 2,188 (10,576)

Less: Reclassification adjustment for amounts included in net income, net of tax of $4,285 and $810, respectively 7,047 1,331 Total other comprehensive income (loss) 5,450 (13,417)

Comprehensive Income $478,260 $447,938 $386,729 The accompanying notes are an integral part of these financial statements.

26

STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2003, 2002, and 2001 Alabama Power Company 2003 Annual Report 2003 2002 2001 (in thousands)

Operating Activities:

Net income $491,077 $ 475,794 $ 402,253 Adjustments to reconcile net income to net cash provided from operating activities --

Depreciation and amortization 467,085 442,660 437,490 Deferred income taxes and investment tax credits, net 153,154 48,828 (21,569)

Deferred capacity revenues (9,589) (8,099)

Pension, postretirement, and other employee benefits (32,029) (34,977) (58,118)

Tax benefit of stock options 8,680 6,670 Settlement of interest rate hedges (7,957)

Other, net 11,393 4,663 (64,533)

Changes in certain current assets and liabilities --

Receivables, net 7,134 (50,423) 88,325 Fossil fuel stock (13,251) 25,535 (38,663)

Materials and supplies (4,651) 3,728 (13,025)

Other current assets (953) 1,479 (15,474)

Accounts payable 50,928 1,068 (83,077)

Accrued taxes (33,507) (40,922) 46,187 Energy cost recovery, retail 1,195 84,429 154,320 Other current liabilities 29,385 12,730 3,790 Net cash provided from operating activities 1,118,094 973,163 837,906 Investing Activities:

Gross property additions (648,560) (634,094) (635,540)

Cost of removal net of salvage (35,440) (32,111) (37,304)

Sales of property - - 102,068 Other (13,763) (6,151) 2,533 Net cash used for investing activities (697,763) (672,356) (568,243)

Financing Activities:

Increase (decrease) in notes payable, net (36,991) 26,994 (271,347)

Proceeds --

Pollution control bonds - - 35,000 Senior notes 1,415,000 975,000 442,000 Mandatorily redeemable preferred securities - 300,000 Preferred stock 125,000 Common stock 50,000 - 15,642 Capital contributions from parent company 17,826 43,118 107,313 Redemptions --

First mortgage bonds - (350,000) (138,991)

Pollution control bonds - (15,000)

Senior notes (1,507,000) (415,602) (3,179)

Other long-term debt (943) (883) (842)

Mandatorily redeemable preferred securities - (347,000)

Preferred stock (70,000)

Payment of preferred stock dividends (18,181) (14,176) (14,942)

Payment of common stock dividends (430,200) (431,000) (393,900)

Other (14,775) (30,329) (9,908)

Net cash used for financing activities (400,264) (313,878) (248,154)

Net Change in Cash and Cash Equivalents 20,067 (13,071) 21,509 Cash and Cash Equivalents at Beginning of Period 22,685 35,756 14,247 Cash and Cash Equivalents at End of Period $ 42,752 $ 22,685 $ 35,756 Supplemental Cash Flow Information:

Cash paid during the period for --

Interest (net of $6,367, $6,738, and $11,690 capitalized, $185,272 $230,102 $246,316 respectively)

Income taxes (net of refunds) 161,004 269,043 223,961 The accompanying notes are an integral part of these financial statements.

27

NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2003 Annual Report

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING generally accepted in the United States and complies with POLICIES the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial General statements in conformity with accounting principles generally accepted in the United States requires the use of Alabama Power Company (the Company) is a wholly estimates, and the actual results may differ from those owned subsidiary of Southern Company, which is the estimates.

parent company of five retail operating companies, Southern Power Company (Southern Power), Southern Certain prior years' data presented in the financial Company Services (SCS), Southern Communications statements have been reclassified to conform with current Services (Southern LINC), Southern Company Gas year presentation.

(Southern Company GAS), Southern Company Holdings (Southern Holdings), Southern Nuclear Operating Affiliate Transactions Company (Southern Nuclear), Southern Telecom, and other direct and indirect subsidiaries. The retail operating The Company has an agreement with SCS under which the companies -- the Company, Georgia Power Company, following services are rendered to the Company at direct Gulf Power Company, Mississippi Power Company, and or allocated cost: general and design engineering, Savannah Electric and Power Company -- provide electric purchasing, accounting and statistical analysis, finance and service in four Southeastern states. The Company treasury, tax, information resources, marketing, auditing, operates as a vertically integrated utility providing insurance and pension administration, human resources, electricity to retail customers within its traditional service systems and procedures, and other services with respect to area located within the State of Alabama and to wholesale business and operations and power pool transactions.

customers in the Southeast. Southern Power constructs, Costs for these services amounted to $218 million, $218 owns, and manages Southern Company's competitive million, and $183 million during 2003, 2002, and 2001, generation assets and sells electricity at market-based rates respectively. Cost allocation methodologies used by SCS in the wholesale market. Contracts among the retail are approved by the SEC and management believes they operating companies and Southern Power -- related to are reasonable.

jointly-owned generating facilities, interconnecting The Company has an agreement with Southern Nuclear transmission lines, or the exchange of electric power -- are to operate Plant Farley and provide the following nuclear-regulated by the Federal Energy Regulatory Commission related services at cost: general executive and advisory (FERC) and/or the Securities and Exchange Commission services, general operations, management and technical (SEC). SCS -- the system service company -- provides, at services, administrative services including procurement, cost, specialized services to Southern Company and its accounting, statistical analysis, employee relations, and subsidiary companies. Southern LINC provides digital other services with respect to business and operations.

wireless communications services to the retail operating Costs for these services amounted to $153 million, $154 companies and also markets these services to the public million, and $160 million during 2003, 2002, and 2001, within the Southeast. Southern Telecom provides fiber respectively.

cable services within the Southeast. Southern Company GAS is a competitive retail natural gas marketer serving The Company has an agreement with Mississippi Power customers in Georgia. Southern Holdings is an under which Mississippi Power owns a portion of Plant intermediate holding subsidiary for Southern Company's Greene County. The Company operates Plant Greene investments in synthetic fuels and leveraged leases and an County, and Mississippi Power reimburses the Company energy services business. Southern Nuclear operates and for its proportionate share of expenses which were $6.7 provides services to Southern Company's nuclear power million in 2003, $6.4 million in 2002, and $5.5 million in plants, including the Company's Plant Farley. 2001. See Note 4 for additional information.

Southern Company is registered as a holding company Southern Company holds a 30 percent ownership under the Public Utility Holding Company Act of 1935 interest in Alabama Fuel Products, LLC (AFP), which (PUHCA). Both Southern Company and its subsidiaries produces synthetic fuel. The Company has an agreement are subject to the regulatory provisions of the PUHCA. with an indirect subsidiary of Southern Company that The Company is also subject to regulation by the FERC provides services for AFP. Under this agreement, the and the Alabama Public Service Commission (Alabama Company provides certain accounting functions, including PSC). The Company follows accounting principles 28

NOTES (continued)

Alabama Power Company 2003 Annual Report processing and paying fuel transportation invoices, and the The Company has a diversified base of customers. No Company is reimbursed for its expenses. Amounts billed single customer or industry comprises 10 percent or more under this agreement totaled approximately $27.5 million of revenues. For all periods presented, uncollectible and $34.5 million in 2003 and 2002, respectively. In accounts continued to average less than 1 percent of addition, the Company purchases synthetic fuel from AFP revenues.

for use at several of the Company's plants. Fuel purchases for 2003 and 2002 totaled $209.2 million and Fuel expense includes the amortization of the cost of

$211.0 million, respectively. nuclear fuel and a charge based on nuclear generation for the permanent disposal of spent nuclear fuel. Total In 2001, the Company had under construction a 1,230 charges for nuclear fuel included in fuel expense megawatt combined cycle facility in Autaugaville, amounted to $64 million in 2003, $63 million in 2002, and Alabama (Plant Harris). In June 2001, the Company sold $58 million in 2001. The Company has a contract with this project to Southern Power. Upon the plant becoming the U.S. Department of Energy (DOE) that provides for operational in June 2003, the Company entered into an the permanent disposal of spent nuclear fuel. The DOE agreement with Southern Power to operate and maintain failed to begin disposing of spent fuel in January 1998 as Plant Harris at cost and provide fuel at cost. In 2003, the required by the contract, and the Company is pursuing Company billed Southern Power $0.8 million for operation legal remedies against the government for breach of and maintenance. Purchased power costs from Plant contract. Sufficient pool storage capacity for spent fuel is Harris in 2003 totaled $75.6 million. Additionally, the available at Plant Farley to maintain full-core discharge Company recorded $8.3 million of prepaid capacity capability until the refueling outage scheduled in 2006 for expenses included in Other Deferred Charges and Other Plant Farley Unit 1 and the refueling outage scheduled in Assets on the Balance Sheets at December 31, 2003. See 2008 for Plant Farley Unit 2. Procurement of on-site dry Note 3 under "Retail Rate Adjustment Procedures" and spent fuel storage capacity at Plant Farley is in progress Note 7 under "Purchased Power Commitments" for and scheduled for operation in 2005. See Note 7 under additional information. "Construction Program" for additional information.

Also, see Note 4 for information regarding the Also, the Energy Policy Act of 1992 required the Company's ownership in and purchased power agreement establishment of a Uranium Enrichment Decontamination with Southern Electric Generating Company (SEGCO). and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This The retail operating companies, including the Company, assessment is being paid over a 15-year period, which Southern Power, and Southern Company GAS, jointly began in 1993. This fund will be used by the DOE for the enter into various types of wholesale energy, natural gas, decontamination and decommissioning of its nuclear fuel and certain other contracts, either directly or through SCS enrichment facilities. The law provides that utilities will as agent. Each participating company may be jointly and recover these payments in the same manner as any other severally liable for the obligations incurred under these fuel expense. The Company estimates its remaining agreements. liability under this law to be approximately $13 million at December 31, 2003.

Revenues and Fuel Costs Income Taxes Capacity revenues are generally recognized on a levelized basis over the appropriate contract periods. Energy and The Company uses the liability method of accounting for other revenues are recognized as services are provided. deferred income taxes and provides deferred income taxes Unbilled revenues are accrued at the end of each fiscal for all significant income tax temporary differences.

period. Fuel costs are expensed as the fuel is used. Electric Investment tax credits utilized are deferred and amortized rates for the Company include provisions to adjust billings to income over the average lives of the related property.

for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other Regulatory Assets and Liabilities costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered in The Company is subject to the provisions of Financial current regulated rates. Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future 29

NOTES (continued)

Alabama Power Company 2003 Annual Report revenues associated with certain costs that are expected to write down the assets, if impaired, to their fair values. All be recovered from customers through the ratemaking regulatory assets and liabilities are reflected in rates.

process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are Depreciation and Amortization expected to be credited to customers through the ratemaking process. Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite Regulatory assets and (liabilities) reflected in the straight-line rates, which approximated 3.1 percent in Balance Sheets at December 31 relate to: 2003 and 3.2 percent in each of 2002 and 2001. When property subject to depreciation is retired or otherwise 2003 2002 Note disposed of in the normal course of business, its original (in millions) cost -- together with the cost of removal, less salvage -- is Deferred income tax charges $ 321 $ 327 (a) charged to accumulated depreciation. Minor items of Loss on reacquired debt 111 104 (b) property included in the original cost of the plant are DOE assessments 13 17 (c) retired when the related property unit is retired.

Vacation pay 36 34 (d)

Rate CNP under recovery 17 (e) Asset Retirement Obligations Other assets 13 17 (e) and Other Costs of Removal Asset retirement obligations (127) (a)

Other cost of removal obligations (574) (885) (a) In accordance with regulatory requirements, prior to Deferred income tax credits (162) (177) (a) January 2003, the Company followed the industry Natural disaster reserve (13) (12) (e) practice of accruing for the ultimate costs of retiring Nuclear outage (14) (10) (e) most long-lived assets over the life of the related asset as Deferred purchased power (15) (e) part of the annual depreciation expense provision. In Other liabilities (2) (e) accordance with SEC requirements, such amounts are (5)

Fuel-hedging liabilities (6) (21) reflected on the Balance Sheet as regulatory liabilities.

(f)

Mine reclamation & remediation (33) (35) Effective January 1, 2003, the Company adopted FASB (g)

Total $(438)$(643) Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 establishes new Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: accounting and reporting standards for legal obligations (a) Asset retirement and removal liabilities are recorded, deferred associated with the ultimate costs of retiring long-lived income tax assets are recovered, and deferred tax liabilities are assets. The present value of the ultimate costs of an amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled asset's future retirement must be recorded in the period and trued up following completion of the related activities. in which the liability is incurred. The costs must be (b) Recovered over the remaining life of the original issue which capitalized as part of the related long-lived asset and may range up to 40 years. depreciated over the asset's useful life. Additionally, (c) Assessments for the decontamination and decommissioning of the DOE nuclear fuel enrichment facilities are recorded annually Statement No. 143 does not permit the continued accrual from 1993 through 2008. of future retirement costs for long-lived assets that the (d) Recorded as earned by employees and recovered as paid, Company does not have a legal obligation to retire.

generally within one year. However, the Company has received guidance regarding (e) Recorded and recovered or amortized as approved by the Alabama PSC. accounting for the financial statement impacts of (f) Fuel-hedging assets and liabilities are recorded over the life of Statement No. 143 from the Alabama PSC and will the underlying hedged purchase contracts, which generally do continue to recognize the accumulated removal costs for not exceed two years. Upon final settlement, actual costs other obligations as a regulatory liability. Therefore, the incurred are recovered through the fuel cost recovery clauses.

(g) Recovered from customers to settle future costs. Company had no cumulative effect to net income resulting from the adoption of Statement No. 143.

In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement The liability recognized to retire long-lived assets No. 71, the Company would be required to write off primarily relates to the Company's nuclear facility, related regulatory assets and liabilities that are not Plant Farley. The fair value of assets legally restricted specifically recoverable through regulated rates. In for settling retirement obligations related to nuclear addition, the Company would be required to determine if facilities as of December 31, 2003 was $385 million.

any impairment to other assets exists, including plant, and In addition, the Company has retirement obligations 30

NOTES (continued)

Alabama Power Company 2003 Annual Report related to various landfill sites and underground storage securities. Equity securities typically range from 50 to 75 tanks. The Company has also identified retirement percent of the funds and fixed income securities from 25 to obligations related to certain transmission and 50 percent. Amounts previously recorded in internal distribution facilities, co-generation facilities, certain reserves are being transferred into the external trust funds wireless communication towers, and certain structures over periods approved by the Alabama PSC. The NRC's authorized by the United States Army Corps of minimum external funding requirements are based on a Engineers. However, a liability for the removal of generic estimate of the cost to decommission the these assets will not be recorded because no reasonable radioactive portions of a nuclear unit based on the size and estimate can be made regarding the timing of any type of reactor. The Company has filed plans with the related retirements. The Company will continue to NRC to ensure that -- over time -- the deposits and recognize in the income statement allowed removal earnings of the external trust funds will provide the costs in accordance with its regulatory treatment. Any minimum funding amounts prescribed by the NRC.

difference between costs recognized under Statement No. 143 and those reflected in rates are recognized as Site study cost is the estimate to decommission the either a regulatory asset or liability, as ordered by the facility as of the site study year. The estimated costs of Alabama PSC, and are reflected in the Balance Sheets. decommissioning, based on the most current study as of The Company also revised the estimated cost to retire December 31, 2003, for Plant Farley were as follows:

Plant Farley as a result of a new site-specific decommissioning study. The effect of the revision is an Site study year 2003 increase of $35 million included in asset retirement Decommissioning periods:

obligations, with a corresponding increase in property, Beginning year 2017 plant, and equipment. See "Nuclear Decommissioning" Completion year 2046 for further information on amounts included in rates. (in millions)

Site study costs:

Details of the asset retirement obligations included in Radiated structures $892 the Balance Sheets are as follows: Non-radiated structures 63 2003 Total $955 (in millions)

Balance beginning of year $- Significant assumptions:

Liabilities incurred 301 Inflation rate 4.5%

Liabilities settled Trust earning rate 7.0 Accretion 23 Cash flow revisions 35 The decommissioning cost estimates are based on Balance end of year $ 359 prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from If Statement No. 143 had been adopted on January 1, the above estimates because of changes in the assumed 2002, the pro-forma asset retirement obligations would date of decommissioning, changes in NRC requirements, have been $281 million. or changes in the assumptions used in making estimates.

Annual provisions for nuclear decommissioning are Nuclear Decommissioning based on an annuity method as approved by the Alabama PSC. The amount expensed in 2003 and fund balances The Nuclear Regulatory Commission (NRC) requires all were as follows:

licensees operating commercial nuclear power reactors to (in millions) establish a plan for providing with reasonable assurance funds for decommissioning. The Company has established Amount expensed in 2003 $ 18 external trust funds to comply with the NRC's regulations. Accumulated provisions:

The funds set aside for decommissioning are managed and External trust funds, at fair value $385 invested in accordance with applicable requirements of Internal reserves 31 various regulatory bodies, including the NRC, the FERC, Total $416 and the Alabama PSC, as well as the Internal Revenue Service (IRS). Funds are invested in a tax efficient All of the Company's decommissioning costs for manner in a diversified mix of equity and fixed income ratemaking are based on the site study. The Company expects the Alabama PSC to periodically review and 31

NOTES (continued)

Alabama Power Company 2003 Annual Report adjust, if necessary, the amounts collected in rates for the Impairment of Long-Lived Assets and Intangibles anticipated cost of decommissioning.

The Company evaluates long-lived assets for impairment The Company filed an application with the NRC in when events or changes in circumstances indicate that the September 2003 to extend the operating license for Plant carrying value of such assets may not be recoverable. The Farley for an additional 20 years. determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an Allowance for Funds Used During Construction estimate of undiscounted future cash flows attributable to (AFUDC) and Interest Capitalized the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the In accordance with regulatory treatment, the Company impairment recognized is determined either by the amount records AFUDC. AFUDC represents the estimated debt of the regulatory disallowance or by estimating the fair and equity costs of capital funds that are necessary to value of the assets and recording a provision for loss if the finance the construction of new regulated facilities. While carrying value is greater than the fair value. For assets cash is not realized currently from such allowance, it identified as held for sale, the carrying value is compared increases the revenue requirement over the service life of to the estimated fair value less the cost to sell in order to the plant through a higher rate base and higher determine if an impairment provision is required. Until the depreciation expense. Interest related to the construction assets are disposed of, their estimated fair value is re-of new facilities not included in the Company's regulated evaluated when circumstances or events change.

rates is capitalized in accordance with standard interest capitalization requirements. All current construction costs Cash and Cash Equivalents should be included in retail rates. The composite rate used to determine the amount of AFUDC was 9.0 percent in For purposes of the financial statements, temporary cash 2003, 8.2 percent in 2002, and 7.7 percent in 2001. investments are considered cash equivalents. Temporary AFUDC and interest capitalized, net of income tax, as a cash investments are securities with original maturities of percent of net income after dividends on preferred stock 90 days or less.

was 3.5 percent in 2003 and 3.3 percent in each of 2002 and 2001. Materials and Supplies Generally, materials and supplies include the cost of Property, Plant, and Equipment transmission, distribution, and generating plant materials.

Property, plant, and equipment is stated at original cost Materials are charged to inventory when purchased and less regulatory disallowances and impairments. Original then expensed or capitalized to plant, as appropriate, when cost includes: materials; labor; minor items of property; installed.

appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; Natural Disaster Reserve and the interest capitalized and/or cost of funds used In accordance with an Alabama PSC order, the Company during construction.

has established a Natural Disaster Reserve. The Company The cost of replacements of property -- exclusive of is allowed to accrue $250 thousand per month until the minor items of property -- is capitalized. The cost of maximum accumulated provision of $32 million is maintenance, repairs and replacement of minor items of attained. Higher accruals to restore the reserve to its property is charged to maintenance expense as incurred or authorized level are allowed whenever the balance in the performed with the exception of nuclear refueling costs, reserve declines below $22.4 million. During 2003, the which are recorded in accordance with specific Alabama Company accrued $3 million to the reserve and at PSC orders. The Company accrues estimated refueling December 31, 2003, the reserve balance was $12.6 million.

costs in advance of the unit's next refueling outage. The Stock Options refueling cycle is 18 months for each unit. During 2003, the Company accrued $28.5 million to the nuclear Southern Company provides non-qualified stock options to refueling outage reserve and at December 31, 2003 the a large segment of the Company's employees ranging from reserve balance was $14.0 million. line management to executives. The Company accounts for its stock-based compensation plans in accordance with Accounting Principles Board Opinion No. 25.

32

NOTES (continued)

Alabama Power Company 2003 Annual Report Accordingly, no compensation expense has been Comprehensive Income recognized because the exercise price of all options granted equaled the fair-market value on the date of grant. The objective of comprehensive income is to report a When options are exercised, the Company receives a measure of all changes in common stock equity of an capital contribution from Southern Company equivalent to enterprise that result from transactions and other economic the related income tax benefit. events of the period other than transactions with owners.

Comprehensive income consists of net income and Financial Instruments changes in the fair value of qualifying cash flow hedges and changes in additional minimum pension liabilities, The Company uses derivative financial instruments to less income taxes and reclassifications for amounts limit exposure to fluctuations in interest rates, the prices of included in net income.

certain fuel purchases, and electricity purchases and sales.

All derivative financial instruments are recognized as 2. RETIREMENT BENEFITS either assets or liabilities and are measured at fair value.

Substantially all of the Company's bulk energy purchases The Company has a defined benefit, trusteed, pension plan and sales contracts that meet the definition of a derivative covering substantially all employees. The plan is funded are exempt from fair value accounting requirements and in accordance with Employee Retirement Income Security are accounted for under the accrual method. Other Act (ERISA) requirements. The Company also provides derivative contracts qualify as cash flow hedges of certain non-qualified benefit plans for a selected group of anticipated transactions. This results in the deferral of management and highly-compensated employees.

related gains and losses in other comprehensive income or Benefits under these non-qualified plans are funded on a regulatory assets or liabilities as appropriate until the cash basis. In addition, the Company provides certain hedged transactions occur. Any ineffectiveness is medical care and life insurance benefits for retired recognized currently in net income. Other derivative contracts employees. The Company funds trusts to the extent are marked to market through current period income and required by the Alabama PSC. For the year ended are recorded on a net basis in the Statements of Income. December 31, 2004, postretirement benefit contributions are expected to total approximately $4.2 million.

The Company is exposed to losses related to financial instruments in the event of counterparties' The measurement date for plan assets and obligations is nonperformance. The Company has established controls September 30 for each year. In 2002, the Company to determine and monitor the creditworthiness of adopted several plan changes that had the effect of counterparties in order to mitigate the Company's increasing benefits to both current and future retirees.

exposure to counterparty credit risk.

Pension Plans The Company's other financial instruments for which the carrying amount did not equal fair value at December The accumulated benefit obligation for the pension plans 31 were as follows: was $1.20 billion in 2003 and $1.09 billion in 2002.

Carrying Fair Changes during the year in the projected benefit Amount Value obligations, accumulated benefit obligations, and fair value (in millions) of plan assets were as follows:

Long-term debt: Projected At December 31, 2003 $3,903 $3,958 Benefit Obligations At December 31, 2002 3,991 4,065 2003 2002 Preferred Securities: (in millions)

At December 31, 2003 300 305 Balance at beginning of year $1,088 $1,011 At December 31, 2002 300 303 Service cost 27 26 Interest cost 68 74 The fair value for long-term debt and preferred Benefits paid (61) (61) securities was based on either closing market prices or Plan amendments 3 22 closing prices of comparable instruments. Actuarial (gain) loss 75 16 Balance at end of year $1,200 $1,088 33

NOTES (continued)

Alabama Power Company 2003 Annual Report Plan Assets 2003 2002 2001 2003 2002 (in millions)

(in millions) Service cost $ 27 $ 26 $ 25 Balance at beginning of year $1,419 $1,584 Interest cost 68 74 70 Actual return on plan assets 226 (106) Expected return on plan assets (138) (138) (131)

Benefits paid (62) (59) Recognized net gain (12) (20) (22)

Balance -at end of year $1,583 $1,419 Net amortization 3 2 l Net pension cost (income) $ (52) $ (56) $ (57)

Pension plan assets are managed and invested in accordance with all applicable requirements, including Postretirement Benefits ERISA and the IRS revenue code. The Company's Changes during the year in the accumulated benefit investment policy covers a diversified mix of assets, including equity and fixed income securities, real estate, obligations and in the fair value of plan assets were as and private equity, as described in the table below. follows:

Derivative instruments are used primarily as hedging tools Accumulated but may also be used to gain efficient exposure to the Benefit Obligations various asset classes. The Company primarily minimizes 2003 2002 the risk of large losses through diversification but also (in millions) monitors and manages other aspects of risk. Balance at beginning of year $405 $348 Service cost 6 5 Plan Assets Interest cost 26 26 Target 2003 2002 Benefits paid (20) (20)

Domestic equity 37% 37% 35% Actuarial (gain) loss 24 46 International equity 20 20 18 Balance at end of year $441 $405 Global fixed income 26 24 25 Plan Assets Real estate 10 11 12 2003 2002 Private equity 7 8 10 (in millions)

Total 100% 100% 100%

Balance at beginning of year $158 $169 Actual return on plan assets 25 (12)

The accrued pension costs recognized in the Balance Employer contributions 23 21 Sheets were as follows: Benefits paid (20) (20) 2003 2002 Balance at end of year $186 $158 (in millions)

Funded status $383 $331 Postretirement benefits plan assets are managed and Unrecognized transition amount (5) (10) invested in accordance with all applicable requirements, Unrecognized prior service cost 87 93 including ERISA and the IRS revenue code. The Unrecognized net (gain) loss (37) (40) Company's investment policy covers a diversified mix of Prepaid pension asset, net 428 374 assets, including equity and fixed income securities, real Portion included in estate, and private equity, as described in the table below.

benefit obligations 18 16 Derivative instruments are used primarily as hedging tools Total prepaid assets recognized in but may also be used to gain efficient exposure to the the Balance Sheets $446 $390 various asset classes. The Company primarily minimizes the risk of large losses through diversification but also monitors and manages other aspects of risk.

In 2003 and 2002, amounts recognized in the Balance Sheets for accumulated other comprehensive income and Plan Assets intangible assets to record the minimum pension Target 2003 2002 liability related to the non-qualified plans were $12.8 Domestic equity 46% 50% 42%

million and $6.7 million and $6.7 and $4.8 million, International equity 13 14 9 respectively. Global fixed income 34 28 40 Real estate 4 5 5 Components of the pension plans' net periodic cost Private equity 3 3 4 were as follows: Total 100% 100% 100%

34

NOTES (continued)

Alabama Power Company 2003 Annual Report The accrued postretirement costs recognized in the Employee Savings Plan Balance Sheets were as follows:

2003 2002 The Company also sponsors a 401(k) defined contribution (in millions) plan covering substantially all employees. The Company Funded status $(255) $(247) provides a 75 percent matching contribution up to 6 Unrecognized transition obligation 37 41 percent of an employee's base salary. Total matching Unrecognized prior service cost 73 77 contributions made to the plan were $12 million for each Unrecognized net loss (gain) 82 66 of the years 2003, 2002, and 2001.

Fourth quarter contributions 6 8 Accrued liability recognized in the 3. CONTINGENCIES AND REGULATORY Balance Sheets $ (57) $ (55) MATTERS Components of the postretirement plan's net periodic General Litigation Matters cost were as follows:

2003 2002 2001 The Company is subject to certain claims and legal actions (in millions) arising in the ordinary course of business. In addition, the Service cost $ 6 $ 5 $ 5 Company's business activities are subject to extensive Interest cost 25 25 24 governmental regulation related to public health and the Expected return on plan assets (17) (16) (15) environment. Litigation over environmental issues and Net amortization 9 9 7 claims of various types, including property damage, Net postretirement cost $ 23 $ 23 $ 21 personal injury, and citizen enforcement of environmental requirements, has increased generally throughout the The weighted average rates assumed in the actuarial United States. In particular, personal injury claims for calculations used to determine both the benefit obligations damages caused by alleged exposure to hazardous and the net periodic costs for the pension and materials have become more frequent. The ultimate postretirement benefit plans were as follows: outcome of such litigation against the Company cannot be predicted at this time; however, management does not 2003 2002 2001 anticipate that the liabilities, if any, arising from such Discount 6.00% 6.50% 7.50% current proceedings would have a material adverse effect Annual salary increase 3.75 4.00 5.00 on the Company's financial statements.

Long-term return on plan assets 8.50 8.50 8.50 New Source Review Actions The Company determined the long-term rate of return In November 1999, the Environmental Protection Agency on historical asset class returns and current market (EPA) brought a civil action in the U.S. District Court for conditions, taking into account the diversification benefits the Northern District of Georgia against the Company.

of investing in multiple asset classes.

The complaint alleged violations of the New Source Review (NSR) provisions of the Clean Air Act and An additional assumption used in measuring the violations of related state laws with respect to coal-fired accumulated postretirement benefit obligations was a generating facilities at the Company's Plants Miller, weighted average medical care cost trend rate of 8.25 Barry, and Gorgas. The civil action requested penalties percent for 2003, decreasing gradually to 5.25 percent and injunctive relief, including an order requiring the through the year 2010, and remaining at that level installation of the best available control technology at the thereafter. An annual increase or decrease in the assumed affected units. The EPA concurrently issued to the medical care cost trend rate of I percent would affect the Company a notice of violation relating to these specific accumulated benefit obligation and the service and interest facilities, as well as Plants Greene County and Gaston. In cost components at December 31, 2003 as follows:

early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation.

I Percent I Percent Increase Decrease In August 2000, the U.S. District Court in Georgia (in millions) granted the Company's motion to dismiss for lack of Benefit obligation $34 $30 jurisdiction in Georgia. The EPA refiled its claim against Service and interest costs 2 2 the Company in the U.S. District Court for the Northern 35

NOTES (continued)

Alabama Power Company 2003 Annual Report District of Alabama. The EPA brought similar NSR Court of Appeals for the District of Columbia Circuit enforcement actions against several other electric utility stayed the effectiveness of these revisions pending companies across the country including Georgia Power resolution of related litigation over those revisions. In and Savannah Electric. In each case, the EPA alleged that January 2004, the Bush Administration announced that it the utilities failed to comply with the NSR permitting would continue to enforce the existing rules.

requirements when performing maintenance and construction activities at coal-buming plants, which The Company believes that it complied with applicable activities the utilities considered to be routine or otherwise laws and the EPA's regulations and interpretations in not subject to NSR. effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 The action against the Company was stayed in the spring per day, per violation at each generating unit. Prior to of 2001 during the appeal of a very similar NSR January 30, 1997, the penalty was $25,000 per day. An enforcement action against the Tennessee Valley Authority adverse outcome in this matter could require substantial (TVA) before the U.S. Court of Appeals for the Eleventh capital expenditures that cannot be determined at this time Circuit. The TVA appeal involves many of the same legal and could possibly require payment of substantial issues raised by the actions against the Company. Because penalties. This could affect future results of operations, the final resolution of the TVA appeal could have a cash flows, and possibly financial condition if such costs significant impact on the Company, it has been involved in are not recovered through regulated rates.

that appeal. On June 24, 2003, the court of appeals issued its ruling in the TVA case. It found unconstitutional the Open Access Transmission Tariff statutory scheme set forth in the Clean Air Act that allowed the EPA to impose penalties for failing to comply with an In October 2003, the FERC approved a new Open Access administrative compliance order, like the one issued to Transmission Tariff for the Company of $1.73 per TVA, without the EPA having to prove the underlying kilowatt-month based on an 11.25 percent return on violation. Thus, the court of appeals held that the equity. The Company had requested a rate increase compliance order was of no legal consequence, and TVA effective April 2002 based on a 13 percent return on was free to ignore it. The court did not, however, rule equity. In September 2002, pending FERC approval, the directly on the substantive legal issues about the proper Company began collecting from customers based on the interpretation and application of certain NSR provisions 13 percent rate, but recorded revenue subject to refund for that had been raised in the TVA appeal. On September 16, amounts above the previously approved rate of $1.37 per 2003, the court of appeals denied the EPA's request for a kilowatt-month. As a result of the final settlement, a total rehearing of the decision. On February 13, 2004, the EPA of approximately $2.4 million was refunded to the petitioned the U.S. Supreme Court to review the decision of Company's transmission customers in October 2003 and the court of appeals. The EPA also filed a motion to lift the $7.6 million was recorded as revenue.

stay in the action against the Company.

Retail Rate Adjustment Procedures Since the inception of the NSR proceedings against the Company, the EPA has also been proceeding with similar The Alabama PSC has adopted rates that provide for NSR enforcement actions against other utilities, involving periodic adjustments based upon the Company's earned many of the same legal issues. In each case, the EPA return on end-of-period retail common equity. Increases alleged that the utilities failed to comply with the NSR in retail rates of 2 percent were effective in April 2002 and permitting requirements when performing maintenance and in October 2001 in accordance with the Rate Stabilization construction activities at coal-burning plants, which Equalization Plan, amounting to an annual increase of $55 activities the utilities considered to be routine or otherwise million and $58 million, respectively. In March 2002, the not subject to NSR. In 2003, district courts addressing Alabama PSC approved a revision to the rate adjustment these cases have issued opinions that reached conflicting procedures that provides for an annual, rather than conclusions. quarterly, adjustment and imposes a 3 percent limit on changes in rates in any calendar year. The return on In October 2003, the EPA issued final revisions to its common equity range of 13.0 percent to 14.5 percent NSR regulations under the Clean Air Act clarifying the remained unchanged.

scope of the existing Routine Maintenance, Repair, and Replacement exclusion. On December 24, 2003, the U.S. The rates also provide for adjustments to recognize the placing of new generating facilities into retail service and 36

NOTES (continued)

Alabama Power Company 2003 Annual Report the recovery of retail costs associated with certificated several utilities, including Southern Company's retail purchased power agreements (PPAs) under Rate CNP operating companies, and found them to be "pivotal (Certificated New Plant). Effective July 2001, the suppliers" in their service areas and ordered the Company's retail rates were adjusted by 0.6 percent ($17 implementation of several mitigation measures. SCS, on million annually) under Rate CNP to recover costs for behalf of the retail operating companies, sought rehearing Plant Barry Unit 7, which was placed into commercial of the FERC order, and the FERC delayed the operation on May 1, 2001. implementation of certain mitigation measures. SCS, on behalf of the retail operating companies, submitted In November 2000, the Alabama PSC certificated a comments to the FERC in 2002 regarding these issues. In seven-year, 615 megawatt, PPA with Southern Power December 2003, the FERC issued a staff paper discussing beginning in June 2003. In addition, the Alabama PSC alternatives and held a technical conference in January certificated a seven-year PPA with a third party for 2004. The Company anticipates that the FERC will approximately 630 megawatts; one half of the capacity address the requests for rehearing in the near future.

became available in 2003 while the remaining half is Regardless of the outcome of the SMA proposal, the scheduled to become available in 2004. As a result, the FERC retains the ability to modify or withdraw the Company's retail rates were adjusted beginning July 2003 authorization for any seller to sell at market-based rates, if by approximately 2.6 percent ($79 million annually) under it determines that the underlying conditions for having Rate CNP. One month after the contracted capacity such authority are no longer applicable. The final delivery begins, which is scheduled for June 2004, Rate outcome of this matter will depend on the form in which CNP will adjust retail rates by approximately 0.8 percent the SMA test and mitigation measures rules may be

($25 million annually) to recover costs associated with the ultimately adopted and cannot be determined at this time.

scheduled 2004 PPA capacity.

4. JOINT OWNERSHIP AGREEMENTS In October 2001, the Alabama PSC approved a revision to the Company's Rate ECR (Energy Cost Recovery) The Company and Georgia Power own equally all of the allowing the recovery of specific costs associated with the outstanding capital stock of SEGCO, which owns electric sales of natural gas that become necessary due to generating units with a total rated capacity of 1,020 operating considerations at its electric generating megawatts, together with associated transmission facilities.

facilities. This revision also includes the cost of financial The capacity of these units is sold equally to the Company tools used for hedging market price risk up to 75 percent and Georgia Power under a contract which, in substance, of the budgeted annual amount of natural gas purchases. requires payments sufficient to provide for the operating The Company may not engage in natural gas hedging expenses, taxes, interest expense and a return on equity, activities that extend beyond a rolling 42-month window. whether or not SEGCO has any capacity and energy Also, the premiums paid for natural gas financial options available. The term of the contract extends automatically may not exceed 5 percent of the Company's natural gas for two-year periods, subject to either party's right to budget for that year. cancel upon two year's notice. The Company's share of purchased power totaled $87 million in 2003, $84 million The Company's ratemaking procedures will remain in in 2002, and $80 million in 2001 and is included in effect until the Alabama PSC votes to modify or "Purchased power from affiliates" in the Statements of discontinue them. Income.

FERC Matters In addition the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale The Company has obtained FERC approval to sell power agreement for the purchase of certain pollution control to nonaffiliates at market-based prices under specific facilities at SEGCO's generating units, pursuant to which contracts. Through SCS, as agent, the Company also has $24.5 million principal amount of pollution control revenue FERC authority to make short-term opportunity sales at bonds are outstanding. Georgia Power has agreed to market rates. Specific FERC approval must be obtained reimburse the Company for the pro rata portion of such with respect to a market-based contract with an affiliate. obligation corresponding to its then proportionate In November 2001, the FERC modified the test it uses to ownership of stock of SEGCO if the Company is called consider utilities' applications to charge market-based upon to make such payment under its guaranty.

rates and adopted a new test called the Supply Margin Assessment (SMA). The FERC applied the SMA to 37

NOTES (continued)

Alabama Power Company 2003 Annual Report At December 31, 2003, the capitalization of SEGCO Details of the income tax provisions are as follows:

consisted of $63 million of equity and $94 million of debt on which the annual interest requirement is $3.4 million. 2003 2002 2001 SEGCO paid dividends totaling $2.3 million in 2003, $5.8 (in millions) million in 2002, and $0.7 million in 2001, of which one- Total provision for income half of each was paid to the Company. In addition, the taxes:

Company recognizes 50 percent of SEGCO's net income. Federal --

Current $111 $209 $234 In addition to the Company's ownership of SEGCO, Deferred 137 41 (20) the Company's percentage ownership and investment in 248 250 214 jointly-owned generating plants at December 31, 2003 is State --

as follows: Current 26 35 37 Total Deferred 16 7 (2)

Megawatt Company 42 42 35 Facility (Type) Capacity Ownership Total $292 $249

$290 Greene County 500 60.00% (1)

(coal) The tax effects of temporary differences between the Plant Miller carrying amounts of assets and liabilities in the financial Units 1 and 2 1,320 91.84% (2) statements and their respective tax bases, which give rise (coal) to deferred tax assets and liabilities, are as follows:

(1) Jointly owned with an affiliate, Mississippi Power. 2003 2002 (2) Jointly owned with Alabama Electric Cooperative, Inc. (in millions)

Deferred tax liabilities:

Company Accumulated Accelerated depreciation $1,204 $ 1,081 Facility Investment Depreciation Property basis differences 401 381 (in millions) Premium on reacquired debt 42 39 Greene County $110 $ 54 Pensions 117 103 Plant Miller 38 Other 29 Units 1 and 2 767 355 Total 1,793 1,642 The Company has contracted to operate and maintain Deferred tax assets:

the jointly owned facilities as agent for their co-owners. Capacity prepayments 8 11 The Company's proportionate share of its plant operating Other deferred costs 13 13 expenses is included in the operating expenses in the Postretirement benefits 14 18 Statements of Income. Unbilled revenue 21 20 Other 86 87

5. INCOME TAXES Total 142 149 Total deferred tax liabilities, net 1,651 1,493 Southern Company files a consolidated federal income tax Portion included in current liabilities, net (80) (56) return. Under a joint consolidated income tax agreement, Accumulated deferred income taxes each subsidiary's current and deferred tax expense is in the Balance Sheets $1,571 $1,437 computed on a stand-alone basis. In accordance with IRS regulations, each company is jointly and severally liable for In accordance with regulatory requirements, deferred the tax liability. investment tax credits are amortized over the lives of the At December 31, 2003, the Company's tax-related related property with such amortization normally applied as regulatory assets and liabilities were $321 million and a credit to reduce depreciation in the Statements of Income.

$162 million, respectively. These assets are attributable to Credits amortized in this manner amounted to $11 million tax benefits flowed through to customers in prior years in each of 2003, 2002, and 2001. At December 31, 2003, and to taxes applicable to capitalized interest. These all investment tax credits available to reduce federal income liabilities are attributable to deferred taxes previously taxes payable had been utilized.

recognized at rates higher than the current enacted tax law A reconciliation of the federal statutory income tax rate and to unamortized investment tax credits. to the effective income tax rate is as follows:

38

NOTES (continued)

Alabama Power Company 2003 Annual Report 2003 2002 2001 Company occurs. As the liquidated damages decline, a Federal statutory rate 35.0% 35.0% 35.0% portion of the bond equal to the decrease is returned to the State income tax, Company. At December 31, 2003, $26.7 million of these net of federal deduction 3.5 3.5 3.5 bonds were held by the escrow agent under the contract.

Non-deductible book depreciation 1.2 1.3 1.5 Pollution Control Bonds Differences in prior years' deferred and current tax rates (0.9) (1.2) (1.3) Pollution control obligations represent installment Other (1.6) (0.5) (0.5) purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds.

Effective income tax rate 37.2% 38.1% 38.2%

The Company is required to make payments sufficient for

6. FINANCING the authorities to meet principal and interest requirements of such bonds. With respect to $114.2 million of such Mandatorily Redeemable Preferred Securities pollution control obligations, the Company has authenticated and delivered to the trustees a like principal The Company has formed certain wholly owned trust amount of first mortgage bonds as security for its subsidiaries for the purpose of issuing preferred securities. obligations under the installment purchase agreements.

The proceeds of the related equity investments and No principal or interest on these first mortgage bonds is preferred security sales were loaned back to the Company payable unless and until a default occurs on the through the issuance of junior subordinated notes totaling installment purchase agreements.

$309 million, which constitute substantially all assets of these trusts. The Company considers that the mechanisms Senior Notes and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and The Company issued a total of $1.4 billion of unsecured unconditional guarantee by it of the respective trusts' senior notes in 2003. The proceeds of these issues were payment obligations with respect to these securities. At used to redeem higher cost debt and for other general December 31, 2003, preferred securities of $300 million corporate purposes.

were outstanding and recognized as liabilities in the Balance Sheets. For additional information, see the At December 31, 2003 and 2002, the Company had Statements of Capitalization. $3.4 billion of senior notes outstanding. These senior notes are subordinate to all secured debt of the Company First Mortgage Bonds which amounted to approximately $295 million at December 31, 2003.

In October 1991, the Company entered into a firm power sales contract with the Alabama Municipal Electric Long-Term Debt Due Within One Year Authority (AMEA) entitling AMEA to scheduled amounts of capacity (up to a maximum 80 megawatts) for a period A summary of the improvement fund requirements and of 15 years. Under the terms of the contract, the Company scheduled maturities and redemptions of long-term debt received payments from AMEA representing the net due within one year at December 31 is as follows:

present value of the revenues associated with the capacity entitlement, discounted at an effective annual rate of 1I.19 20C13 2002 percent. These payments are being recognized as (in nillions) operating revenues and the discount is amortized to other Capitalized leases $ 1 $ I interest expense as scheduled capacity is made available Senior notes 525 1,117 over the terms of the contract. Total $526 $1,118 To secure AMEA's advance payments and the Debt redemptions and/or serial maturities through 2008 Company's performance obligation under the contracts, applicable to total long-term debt are as follows: $526 the Company issued and delivered to an escrow agent first million in 2004; $225 million in 2005; $715 million in mortgage bonds representing the maximum amount of 2006; $200 million in 2007; and $410 million in 2008.

liquidated damages payable by the Company in the event of a default under the contracts. No principal or interest is payable on such bonds unless and until a default by the 39

NOTES (continued)

Alabama Power Company 2003 Annual Report Assets Subject to Lien At December 31, 2003, the Company had regulatory approval to have outstanding up to $1 billion of short-term The Company's mortgage, as amended and supplemented, borrowings.

securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Financial Instruments Company's fixed property and franchises.

The Company enters into energy-related derivatives to Bank Credit Arrangements hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations, The Company maintains committed lines of credit in the the Company has limited exposure to market volatility amount of $865 million (including $504 million of such in commodity fuel prices and prices of electricity. The lines which are dedicated to funding purchase obligations Company has implemented fuel-hedging programs at relating to variable rate pollution control bonds), all of the instruction of the Alabama PSC. The Company which expire at various times during 2004. Approximately also enters into hedges of forward electricity sales.

$450 million of the credit facilities expiring in 2004 allow for the execution of term loans for an additional two-year At December 31, 2003, the fair value of derivative period, and $245 million allow for the execution of one- energy contracts was reflected in the financial year term loans. All of the credit arrangements require statements as follows:

payment of a commitment fee based on the unused portion Amounts of the commitment or the maintenance of compensating (in thousands) balances with the banks. Commitment fees are less than Regulatory liabilities, net $6,402 1/4 of 1 percent for the Company. Because the Net income 11 arrangements are based on an average balance, the Total fair value $6,413 Company does not consider any of its cash balances to be restricted as of any specific date. For syndicated credit The fair value gain or loss for cash flow hedges that arrangements, a fee is also paid to the agent bank. are recoverable through the regulatory fuel clauses are recorded in the regulatory assets and liabilities and are Most of the Company's credit arrangements with recognized in earnings at the same time the hedged banks have covenants that limit the Company's debt to 65 items affect earnings.

percent of total capitalization, as defined in the agreements. Exceeding this debt level would result in a The Company also enters into derivatives to hedge default under the credit arrangements. At December 31, exposure of interest rate changes. Interest derivatives 2003, the Company was in compliance with the debt limit related to variable rate securities or forecasted covenants. In addition, the credit arrangements typically transactions are accounted for as cash flow hedges.

contain cross default provisions that would be triggered if The interest derivatives are generally structured to the Company defaulted on other indebtedness (including match the critical terms of the hedged debt instruments; guarantee obligations) above a specified threshold. None therefore, no material ineffectiveness has been recorded of the arrangements contain material adverse change in earnings.

clauses at the time of borrowings.

At December 31, 2003, the Company had The Company borrows through commercial paper $1.2 billion notional amount of interest rate swaps programs that have the liquidity support of committed outstanding with net deferred gains of $5.7 million as bank credit arrangements. In addition, the Company follows:

borrows from time to time through extendible commercial Cash Flow Hedges note programs. As of December 31, 2003, the Company Weighted Average Fair had no extendible commercial notes and no commercial Fixed Value paper outstanding. The amount of commercial paper Rate Notional Gain/

outstanding at December 31, 2002 was $37 million. Maturity Paid Amount (Loss)

During 2003, the peak amount outstanding for commercial (in millions) paper was $255 million and the average amount 2004 1.63* $486 $(0.2) outstanding was $30 million. The average annual interest 2006 1.89 195 1.5 rate on commercial paper in 2003 was 1.29 percent. 2007 1.99* 486 4.4 Commercial paper and extendible commercial notes are *Hedged using the Bond Market Association Municipal Swap Index.

included in notes payable on the Balance Sheets.

40

NOTES (continued)

Alabama Power Company 2003 Annual Report The fair value gain or loss for cash flow hedges is Long-Term Service Agreements recorded in other comprehensive income and is reclassified into earnings at the same time the hedged The Company has entered into several Long-Term items affect earnings. In 2003 and 2002, the Company Service Agreements (LTSAs) with General Electric recognized losses of $8 million and $13 million, (GE) for the purpose of securing maintenance support respectively, upon termination of certain interest for its combined cycle and combustion turbine derivatives at the same time it issued debt. These losses generating facilities. The LTSAs stipulate that GE will have been deferred in other comprehensive income and perform all planned maintenance on the covered will be amortized to interest expense over the life of the equipment, which includes the cost of all labor and related debt. For 2003, approximately $11.3 million of materials. GE is also obligated to cover the costs of pre-tax losses were reclassified from other comprehensive income to interest expense. For 2004, unplanned maintenance on the covered equipment pre-tax losses of approximately $5.8 million are subject to a limit specified in each contract.

expected to be reclassified from other comprehensive income to interest expense. In general, these LTSAs are in effect through two major inspection cycles per unit. Scheduled payments

7. COMMITMENTS to GE are made at various intervals based on actual operating hours of the respective units. Total payments Construction Program to GE under these agreements are currently estimated at

$253 million over the life of the agreements, which are The Company is engaged in continuous construction approximately 12 to 14 years per unit. At December programs, currently estimated to total $791 million in 31, 2003, the remaining balance was approximately 2004, $863 million in 2005, and $884 million in 2006. $213 million. However, the LTSAs contain various These amounts include $12.5 million, $11.3 million, cancellation provisions at the option of the Company.

and $6.6 million in 2004, 2005, and 2006, respectively, for construction expenditures related to contractual Payments made to GE prior to the performance of purchase commitments for uranium and nuclear fuel any planned maintenance are recorded as a prepayment conversion, enrichment, and fabrication services in the Balance Sheets. Inspection costs are capitalized included in this note under "Fuel Commitments." The or charged to expense based on the nature of the work construction programs are subject to periodic review performed.

and revision, and actual construction costs may vary from the above estimates because of numerous factors. Purchased Power Commitments These factors include: changes in business conditions; revised load growth estimates; changes in The Company has entered into various long-term environmental regulations; changes in existing nuclear commitments for the purchase of electricity. Total plants to meet new regulatory requirements; changes in FERC rules and transmission regulations; increasing estimated minimum long-term obligations at December costs of labor, equipment, and materials; and cost of 31, 2003 were as follows:

capital. At December 31, 2003, significant purchase Commitments commitments were outstanding in connection with the Non-construction program. The Company has no generating Year Affiliate d Affiliated Total plants under construction. Construction of new (in millions) transmission and distribution facilities and capital 2004 $ 49 $ 36 $ 85 improvements, including those needed to meet 2005 49 38 87 environmental standards for existing generation 2006 49 39 88 transmission, and distribution facilities, will continue. 2007 49 40 89 2008 49 40 89 Southern Company has guaranteed Southern Power's 2009 and thereafter 62 67 129 obligations to the Company for transmission Total commitments $307 $260 $567 interconnection facilities of $6.8 million related to Plant Harris units 1 & 2. The obligations were guaranteed at December 31, 2003, but, upon completion of construction, were released in February 2004.

41

NOTES (continued)

Alabama Power Company 2003 Annual Report Fuel Commitments and $21.1 million for 2003, 2002, and 2001, respectively, relates to the rail car leases and are recoverable through To supply a portion of the fuel requirements of its the Company's energy cost recovery clause. At December generating plants, the Company has entered into various 31, 2003, estimated minimum rental commitments for long-term commitments for the procurement of fossil and noncancellable operating leases were as follows:

nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, Rail Vehicles and other financial commitments. Natural gas purchase Year Cars & Other Total commitments contain fixed volumes with prices based on (in millions) various indices at the time of delivery. Amounts included 2004 $19.1 $10.6 $ 29.7 in the chart below represent estimates based on New York 2005 16.3 8.9 25.2 Mercantile future prices at December 31, 2003. Total 2006 11.3 6.2 17.5 estimated minimum long-term commitments at December 2007 4.1 3.6 7.7 31, 2003 were as follows: 2008 3.8 2.0 5.8 Coal & 2009 and thereafter 30.7 4.5 35.2 Natural Nuclear Total minimum payments $85.3 $35.8 $121.1 Year Gas Fuel (in millions)

In addition to the rental commitments above, the 2004 $318 $ 750 Company has potential obligations upon expiration of 2005 181 514 certain leases with respect to the residual value of the 2006 158 437 leased property. These leases expire in 2004 and 2006, 2007 107 429 and the Company's maximum obligations are $25.7 2008 26 154 million and $66.0 million, respectively. At the 2009 and thereafter 108 termination of the leases, at the Company's option, the Total commitments $898 $2,284 Company may negotiate an extension, exercise its Additional commitments for fuel will be required to purchase option, or the property can be sold to a third supply the Company's future needs. party. The Company expects that the fair market value of the leased property would substantially reduce or SCS may enter into various types of wholesale energy eliminate the Company's payments under the residual and natural gas contracts acting as an agent for the value obligations.

Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Guarantees Company GAS. Under these agreements, each of the retail At December 31, 2003, the Company had outstanding operating companies, Southern Power, and Southern guarantees related to SEGCO's purchase of certain Company GAS may be jointly and severally liable. The pollution control facilities, as discussed in Note 4, and to creditworthiness of Southern Power and Southern certain residual values of leased assets. See "Operating Company GAS is currently inferior to the creditworthiness Leases" above.

of the retail operating companies. Accordingly, Southern Company has entered into keep-well agreements with the 8. NUCLEAR INSURANCE Company and each of the other retail operating companies to insure the Company will not subsidize or be responsible Under the Price-Anderson Amendments Act of 1988 for any costs, losses, liabilities, or damages resulting from (Act), the Company maintains agreements of indemnity the inclusion of Southern Power or Southern Company with the NRC that, together with private insurance, cover GAS as a contracting party under these agreements. third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to Operating Leases $10.9 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured The Company has entered into rental agreements for coal against this liability to a maximum of $300 million by rail cars, vehicles, and other equipment with various terms American Nuclear Insurers (ANI), with the remaining and expiration dates. These expenses totaled $29.5 coverage provided by a mandatory program -ofdeferred million in 2003, $29.6 million in 2002, and $27.9 million premiums that could be assessed, after a nuclear incident, in 2001. Of these amounts, $19.4 million, $19.1 million, against all owners of nuclear reactors. The Company 42

NOTES (continued)

Alabama Power Company 2003 Annual Report could be assessed up to $100.5 million per incident for indemnity from an outside source. The non-certified ANI each licensed reactor it operates but not more than an cap is a $300 million shared industry aggregate. Any act aggregate of $10 million per incident to be paid in a of terrorism that is certified pursuant to the TRIA will not calendar year for each reactor. Such maximum be subject to the foregoing NEIL and ANI limitations but assessment, excluding any applicable state premium taxes, will be subject to the TRIA annual aggregate limitation of for the Company is $201 million per incident but not more $100 billion of insured losses arising from certified acts of than an aggregate of $20 million to be paid for each terrorism. The TRIA will expire on December 31, 2005.

incident in any one year. The Price-Anderson Amendments Act expired in August 2002; however, the For all on-site property damage insurance policies for indemnity provisions of the act remain in place for commercial nuclear power plants, the NRC requires that commercial nuclear reactors. the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable The Company is a member of Nuclear Electric condition after an accident. Any remaining proceeds are Insurance Limited (NEIL), a mutual insurer established to to be applied next toward the costs of decontamination provide property damage insurance in an amount up to and debris removal operations ordered by the NRC, and

$500 million for members' nuclear generating facilities. any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate Additionally, the Company has policies that currently under the policies and applicable trust indentures.

provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion All retrospective assessments, whether generated for for losses in excess of the $500 million primary coverage. liability, property, or replacement power, may be subject This excess insurance is also provided by NEIL. to applicable state premium taxes.

NEIL also covers the additional costs that would be 9. QUARTERLY FINANCIAL INFORMATION incurred in obtaining replacement power during a (UNAUDITED) prolonged accidental outage at a member's nuclear plant.

Members can purchase this coverage, subject to a Summarized quarterly financial information for 2003 and deductible waiting period of up to 26 weeks, with a 2002 are as follows:

maximum per occurrence per unit limit of $490 million. Net Income After this deductible period, weekly indemnity payments After would be received until either the unit is operational or Dividends until the limit is exhausted in approximately three years. Quarter Operating Operating on Preferred The Company purchases the maximum limit allowed by Ended Revenues Income Stock (in millions)

NEIL and has elected a 12 week waiting period.

Under each of the NEIL policies, members are subject March 2003 $ 890 $211 $ 92 to assessments if losses each year exceed the accumulated June 2003 950 227 107 funds available to the insurer under that policy. The September 2003 1,216 414 217 current maximum annual assessments for the Company December 2003 904 163 57 under the NEIL policies would be $36 million.

March 2002 $ 802 $191 $ 72 Following the terrorist attacks of September 2001, both June 2002 924 256 116 ANI and NEIL confirmed that terrorist acts against September 2002 1,119 393 201 commercial nuclear power plants would be covered under December 2002 865 182 72 their insurance. However, both companies revised their The Company's business is influenced by seasonal policy terms on a prospective basis to include an industry weather conditions.

aggregate for all "non-certified" terrorist acts, i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA). The NEIL aggregate -- applies to all non-certified claims stemming from terrorism within a 12 month duration -- is $3.24 billion plus any amounts available through reinsurance or 43

SELECTED FINANCIAL AND OPERATING DATA 1999-2003 Alabama Power Company 2003 Annual Report 2003 2002 2001 2000 1999 Operating Revenues (in thousands) $3,960,161 $3,710,533 $3,586,390 $3,667,461 $3,385,474 Net Income after Dividends on Preferred Stock (in thousands) $472,810 $461,355 $386,729 $419,916 $399,880 Cash Dividends on Common Stock (in thousands) $430,200 $431,000 $393,900 $417,100 $399,600 Return on Average Common Equity (percent) 13.75 13.80 11.89 13.58 13.85 Total Assets (in thousands) $12,070,624 $11,591,666 $11,303,605 $11,228,118 $10,450,052 Gross Property Additions (in thousands) $648,560 $634,094 $635,540 $870,581 $809,044 Capitalization (in thousands):

Common stock equity $3,500,660 $3,377,740 $3,310,877 $3,195,772 $2,988,863 Preferred stock 372,512 247,512 317,512 317,512 317,512 Mandatorily redeemable preferred securities 300,000 300,000 347,000 347,000 347,000 Long-term debt 3,377,148 2,872,609 3,742,346 3,425,527 3,190,378 Total (excluding amounts due within one year) $7,550,320 $6,797,861 $7,717,735 $7,285,811 $6,843,753 Capitalization Ratios (percent):

Common stock equity 46.4 49.7 42.9 43.9 43.7 Preferred stock 4.9 3.6 4.1 4.4 4.6 Mandatorily redeemable preferred securities 4.0 4.4 4.5 4.8 5.1 Long-term debt 44.7 42.3 48.5 46.9 46.6 Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 Security Ratings:

First Mortgage Bonds -

Moody's Al Al Al Al Al Standard and Poor's A A A A A+

Fitch A+ A+ A+ AA- AA-Preferred Stock -

Moody's Baal Baal Baal a2 a2 Standard and Poor's BBB+ BBB+ BBB+ BBB+ A-Fitch A- A- A- A A Unsecured Long-Term Debt -

Moody's A2 A2 A2 A2 A2 Standard and Poor's A A A A A Fitch A A A A+ A+

Customers (year-end):

Residential 1,160,129 1,148,645 1,139,542 1,132,410 1,120,574 Commercial 204,561 203,017 196,617 193,106 188,368 Industrial 5,032 4,874 4,728 4,819 4,897 Other 757 789 751 745 735 Total 1.370,479 1.357,325 1,341,638 1,331,080 1,314,574 Employees (year-end): 6,730 6,715 6,706 6,871 6,792 44

SELECTED FINANCIAL AND OPERATING DATA 1999-2003 (continued)

Alabama Power Company 2003 Annual Report 2003 2002 2001 2000 1999 Operating Revenues (in thousands):

Residential $1,276,800 $1,264,431 $1,138,499 $1,222,509 $1,145,646 Commercial 913,697 882,669 829,760 854,695 807,098 Industrial 844,538 788,037 763,934 859,668 843,090 Dther 16,428 16,080 15,480 15,835 15,283 Total retail 3,051,463 2,951,217 2,747,673 2,952,707 2,811,117 3ales for resale - non-affiliates 487,456 474,291 485,974 461,730 415,377 Sales for resale - affiliates 277,287 188,163 245,189 166,219 92,439 rotal revenues from sales of electricity 3,816,206 3,613,671 3,478,836 3,580,656 3,318,933

)ther revenues 143,955 96,862 107,554 86,805 66,541 Total $3.960,161 $3.710,533 $3,586,390 $3.667.461 $3.385.474 Kilowatt-Hour Sales (in thousands):

Zesidential 16,959,566 17,402,645 15,880,971 16,771,821 15,699,081 ommercial 13,451,757 13,362,631 12,798,711 12,988,728 12,314,085 ndustrial 21,593,519 21,102,568 20,460,022 22,101,407 21,942,889 Jther 203,178 205,346 198,102 205,827 201,149 rotal retail 52,208,020 52,073,190 49,337,806 52,067,783 50,157,204 5ales for resale - non-affiliates 17,085,376 15,553,545 15,277,839 14,847,533 12,437,599 sales for resale - affiliates 9,422,301 8,844,050 8,843,094 5,369,474 5,031,781 Total 78.715,697 76.470.785 73.458.739 72,284.790 67.626.584 average Revenue Per Kilowatt-Hour (cents):

Zesidential 7.53 7.27 7.17 7.29 7.30 Commercial 6.79 6.61 6.48 6.58 6.55 ndustrial 3.91 3.73 3.73 3.89 3.84 Total retail 5.84 5.67 5.57 5.67 5.60 sales for resale 2.88 2.72 3.03 3.11 2.91 Potal sales 4.85 4.73 4.74 4.95 4.91 Zesidential Average Annual Kilowatt-Hour Use Per Customer 14,688 15,198 13,981 14,875 14,097 Zesidential Average Annual Revenue Per Customer $1,105.77 $1,104.28 $1,002.30 $1,084.26 $1,028.76 Ilant Nameplate Capacity Ratings (year-end) (megawatts) 12,174 12,153 12,153 12,122 11,379 Vaximum Peak-Hour Demand (megawatts):

Minter 10,409 9,423 9,300 9,478 8,863

)ummer 10,462 10,910 10,241 11,019 10,739 knnual Load Factor (percent) 64.1 62.9 62.5 59.3 59.7 lant Availability (percent):

<ossil-steam 85.9 85.8 87.1 89.4 80.4 Nquclear 94.7 93.2 83.7 88.3 91.0 source of Energy Supply (percent):

Toal 56.5 55.5 56.8 63.0 64.1 Tuclear 17.0 17.1 15.8 16.9 17.8

-ydro 7.0 5.1 5.1 2.9 4.7 Jas 7.6 11.6 10.7 4.9 1.1 "urchased power -

From non-affiliates 4.1 4.0 4.4 4.6 4.5 From affiliates 7.8 6.7 7.2 7.7 7.8 Fotal 100.0 100.0 100.0 100.0 100.0 45

DIRECTORS AND OFFICERS Alabama Power Company 2003 Annual Report Directors Whit Armstrong William F. Walker William B. Johnson President, Chairman and CEO, President, Auburn University Vice President The Citizens Bank John Cox Webb, IV J. Bruce Jones 5 David J. Cooper President, Webb Lumber Company, Inc. Vice President President, Cooper/T. Smith Corporation James W. Wright Bobby J. Kerley 6 Chairman and CEO, Vice President, Southeast Division H. Allen Franklin First Tuskegee Bank Chairman, President and CEO, Barbara J. Knight Southern Company Officers Vice President R. Kent Henslee Charles D. McCrary Ellen N. Lindemann Managing Partner, President and Chief Executive Officer Vice President Henslee, Robertson, Strawn & Knowles, L.L.C. William B. Hutchins, III Gordon G. Martin Executive Vice President, Chief Vice President, Southern Division John D. Johns' Financial Officer and Treasurer Chairman, President and CEO, Donald W. Reese Protective Life Corporation C. Alan Martin Vice President Executive Vice President Carl E. Jones, Jr. R. Michael Saxon 7 Chairman, President and CEO, Steve R. Spencer Vice President, Southeast Division Regions Financial Corporation Executive Vice President Julia H. Segars Patricia M. King Rodney 0. Mundy Vice President President and CEO, Senior Vice President and Counsel King Motor Company, Inc. Julian H. Smith, Jr.

Robert Holmes, Jr. Vice President James K. Lowder Senior Vice President W. Ronald Smith

Chairman, Robin A. Hurst Vice President, Eastern Division The Colonial Company Senior Vice President Wallace D. Malone, Jr. Cheryl A. Thompson Michael L. Scott Vice President, Mobile Division Chairman and CEO, SouthTrust Corporation Senior Vice President Terry H. Waters Jerry L. Stewart Vice President, Western Division Charles D. McCrary President and CEO, Senior Vice President Robert Cole Giddens Alabama Power Company Art P. Beattie Assistant Comptroller Mayer Mitchell 2 Vice President and Comptroller E. Wayne Boston President, MBI, LLC William E. Zales, Jr. Assistant Secretary and Vice President, Corporate Secretary Assistant Treasurer Malcolm Portera Chancellor, The University of and Assistant Treasurer Ceila H. Shorts Alabama System Christopher T. Bell Assistant Secretary Robert D. Powers Vice President Kay 1. Worley President, The Eufaula Agency Willard L. Bowers Assistant Secretary Andreas Renschler 3 Vice President J. Randy DeRieux President, Mcc smart Gmbh Larry R. Grill 4 Assistant Treasurer C. Dowd Ritter Vice President All information as of Chairman, President and CEO, Gerald L. Johnson December 31, 2003 AmSouth Bancorporation Vice President except as noted below James H. Sanford 'Elected 1/04 Chairman, HOME Place Farms, Inc. Marsha S. Johnson 2 Retired 4/03 Vice President, Birmingham Division Resigned 4/03 4Elected 4/03 5

Retired 1/04 6

Resigned 12/03 7 Elected 12/03 46

CORPORATE INFORMATION Alabama Power Company 2003 Annual Report General Registrar, Transfer Agent and Dividend This annual report is submitted for general Paying Agent information and is not intended for use in All series of Preferred Stock and Class A Preferred connection with any sale or purchase of, or any Stock except for the Flexible Money Market and solicitation of offers to buy or sell, securities. 5.30% Series Class A Preferred Stock Southern Company Services, Inc.

Profile Stockholder Services The Company operates as a vertically integrated P.O. Box 54250 utility providing electricity to retail customers Atlanta, GA 30308-0250 within its traditional service area located within (800) 554-7626 the State of Alabama and to wholesale customers in the Southeast. The Company sells electricity to The Flexible Money Market and 5.30% Series Class more than 1.3 million customers within its service A Preferred Stock area of approximately 45,000 square miles. In The Bank of New York 2003, retail energy sales accounted for 66 percent 101 Barclay Street of the Company's total sales of 78.7 billion New York, NY 10286 kilowatt-hours.

Number of Preferred Shareholders of record The Company is a wholly owned subsidiary at December 31, 2003, was 1,836.

of The Southern Company, which is the parent company of five regulated Southeast utilities. Form 10-K There is no established public trading market for A copy of Form 10-K as filed with the the Company's common stock. Securities and Exchange Commission will be provided upon written request to the office of Audit Committee the Corporate Secretary. For additional Prior to April 25, 2003 the Company had an Audit information, contact the office of the Committee comprised of R. Kent Henslee, James Corporate Secretary at (205) 257-3385.

K. Lowder, and John Cox Webb, IV. On April 25, 2003, the Board amended the Company's Bylaws Alabama Power Company to remove the provision requiring the Board to 600 North 18d' Street have an Audit Committee. The Southern Company Birmingham, AL 35291 Audit Committee provides broad oversight of the (205) 257-1000 Company's financial reporting and control www.alabamapower.com functions.

Auditors Trustee, Registrar and Interest Paying Agent Deloitte & Touche LLP All series of First Mortgage Bonds, 417 North 2 0 "' Street Senior Notes and Mandatorily Redeemable Suite 1000 Preferred Securities Birmingham, AL 35203 JPMorgan Chase Bank Institutional Trust Services Legal Counsel 4 New York Plaza, i 5 t" Floor Balch & Bingham LLP New York, NY 10004 P.O. Box 306 Birmingham, AL 35201 47