ML031210017

Annual Submission Reports

ML031210017
Person / Time
Site:	Farley
Issue date:	04/28/2003
From:	Derieux J Alabama Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML031210017 (50)

Text

J. Randy DeRieux 600 North 18th Street Assistant Treasurer and Post Office Box 2641 General Manager- Birmingham, Alabama 35291-0030 Corporate Finance and Tel 205.257.2454 Planning Fax 205.257.1023 April 28, 2003 ALABAMAA 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. 2002 Annual Report which includes financial statements for the calendar year 2002, together with the report on such statements by Deloitte & Touche LLP, independent public accountants;

2. Unaudited Financial Statements for the quarter ended March 31, 2003;

3. Cash Flow Projections for the period January 1, 2003 through December 31, 2003, 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, 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 Reaulatory Commission. Region II Mr. L. A. Reyes, Regional Administrator Mr. T. P. Johnson, Senior Resident Inspector - Farley C) c)4

bc: w/o attachments Mr. C. D. McCrary Mr. W. B. Hutchins, Ill Mr. A. P. Beattie Ms. P. R. Williams w/attachments Mr. C. L. Whatley - SCS Mr. R. W. Clouse - Southern Nuclear Mr. A. E. Jones - Southern Nuclear Mr. J. B. Beasley, Jr. - Southern Nuclear Mr. J. E. Stough File: H:\Price Anderson Act/Annual Submission Reports to NRC.doc

ALABAMA POWER COMPANY STATEMENT OF INCOME (THOUSANDS OF DOLLARS) 3 Months Ended 3/31/2003 OPERATING REVENUES:

Revenues $ 894,561 OPERATING EXPENSES:

Operation --

Fuel 237,598 Purchased & interchange power, net 74,766 Other 134,189 Maintenance 74,575 Depreciation, amortization & accretion 100,211 Taxes other than income taxes 60,085 Federal and State income taxes 59,871 Total Operating Expenses 741,295 OPERATING INCOME 153,266 OTHER INCOME (EXPENSES):

Allowance for equity funds used during construction 4,737 Income from subsidiary 300 Other, net (2,891)

INCOME BEFORE INTEREST CHARGES 155,412 INTEREST CHARGES:

Interest on long-term debt 52,709 Allowance for debt funds used during construction (2,507)

Amortization of debt discount, premium and expenses, net 3,533 Other interest charges 4,278 Net Interest Charges 58,013 NET INCOME 97,399 DIVIDENDS ON PREFERRED STOCK 4,025 NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 93,374 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.

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ALABAMA POWER COMPANY Internal Cash Flow for Joseph M. Farley Nuclear Power Station (Thousands of Dollars) 2002 2003 Actual Projections Net Income $ 475,794 $ 485,550 Less Dividends Paid 445,176 449,307 Retained Earnings 30,618 36,243 Adjustments:

Depreciation and Amortization 465,325 485,865 Deferred Income Taxes and Investment Tax Credits 48,828 53,238 Allowance for Equity Used During Construction 11,168 16,355 Total Adjustments 525,321 555,458 Internal Cash Flow $ 555,939 $ 591,701 Average Quarterly Cash Flow $ 138,985 $ 147,925 Percentage Ownership in all Operating Nuclear Units:

Joseph M. Farley Units 1 and 2 100%

Maximum Total Contingent Liability $ 20,000 HANFCASHFL.xls

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 1,11& IlIl is subject to audit and end of year (Stated in Thousands of Dollars) adjustments.

At At March 31, March 31, ASSETS 2003 2002 UTILITY PLANT:

Plant In service, at original cost............................................................................. $ 13,662,507 $ 13,227,382 Less - Accumulated provision for depreciation and amortization........................... 5,327,380 5,393,858 8,335,127 7,833,524 Nuclear fuel, at amortized cost.............................................................................. 92,993 77,108 Construction work In progress................................................................................ 564,672 457,469 8,992,792 8,368,101 OTHER PROPERTY AND INVESTMENTS:

Equity Investm ents In subsidiaries......................................................................... 45,916 45,685 Nuclear decommissioning trusts............................................................................ 300,072 311,639 M iscellaneous........................................................................................................ 16,405 16,987 362,393 374,311 CURRENT ASSETS:

Cash...................................................................................................................... 28,603 32,193 Special Deposits.................................................................................................... 0 0 Temporary cash investments................................................................................. 0 0 Investment securities............................................................................................. 0 0 Receivables -

Customer accounts receivable............................................................................ 297,045 316,267 Other accounts and notes receivable................................................................. 82,113 61,464 Affiliated com panies............................................................................................ 70,299 60,593 Accumulated provision for uncollectible accounts...................................... (5,229) (5,715)

Refundable Income taxes...................................................................................... 10,346 0 Fossil fuel stock, at average cost........................................................................... 77,692 94.927 M aterials and supplies, at average cost................................................................. 162,124 168,820 Allowance Inventory............................................................................................... 27,558 21,101 Prepayments -

Income taxes....................................................................................................... 0 0 Other................................................................................................................... 102,234 84,614 Other current assets - SFAS 133............................................................................ 37,177 21,224 Vacation pay deferred............................................................................................ 33,901 32,324 923,863 887,812 Debt expense, being amortized............................................................................. 9,703 8,109 Debt redem ption expense, being amortized.......................................................... 112,466 75,179 Nuclear decontamination and decommissioning fund........................................... 17,144 21,015 Prepaid pension cost............................................................................................. 402,781 344,044 Regulatory assets.................................................................................................. 596,890 309,178 Miscellaneous........................................................................................................ 99,367 109,088 1,238,351 866,613 TOTAL ASSETS...................................................................................................... $ 11,517,399 $ 10,496,837 4/2812003 +

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 l, II & III is subject to audit and end of year (Stated in Thousands of Dollars) adjustments.

At At March 31, March 31, CAPITALIZATION AND UABILTIES 2003 2002 CAPITALIZATION:

Common stock equity............................................................................................ $ 3,366,043 $ 3,277,133 Preferred stock....................................................................................................... 372,512 317,512 Company obligated mandatorily redeemable preferred securities ...................... 300,000 347,000 Long-term debt...................................................................................................... 3,089,658 3,742,657 7,128,213 7,684,302 CURRENT LIABILITIES:

Preferred stock due or to be redeemed within one year........................................ 0 0 Long-term debt due or to be redeemed within one year........................................ 947,158 904 Notes payable to banks......................................................................................... 0 0 Commercial paper............................................................................................ 0 96,833 Accounts payable -

Affiliated com panies............................................................................................ 138,296 94,260 Other................................................................................................................... 70,670 91,668 Customer deposits................................................................................................. 45,322 43,419 Taxes accrued -

Federal and state Income................................................................................... 120,867 158,090 Other................................................................................................................... 39,896 38,293 Interest accrued..................................................................................................... 50,511 61,162 Distributions accrued.............................................................................................. 8,119 5,816 Vacation pay accrued............................................................................................ 33,901 32,324 M iscellaneous........................................................................................................ 78,776 53,492 1,533,516 676,261 DEFERRED CREDITS AND OTHER LIABILITIES:

Accumulated deferred Incom e taxes...................................................................... 1,468,010 1,369,097 Accumulated deferred Investment tax credits........................................................ 224,530 235,491 Asset Retirem ent Obligations................................................................................ 306,144 0 Prepaid capacity revenues, net.............................................................................. 31,578 39,099 Regulatory liabilities............................................................................................... 171,825 198,571 Nuclear decontamination and decommissioning fund........................................... 12,858 16,812 Natural disaster reserve......................................................................................... 12,551 12,981 M iscellaneous........................................................................................................ 628,174 264,223 2,855,670 2,136,274 TOTAL CAPITALIZATION AND LIABILITIES.......................................................... $ 11,517,399 $ 10,496,837 I Substantially all assets of Alabama Power Capital Trust I, II & III are junior subordinate notes Issued by the company. Upon redemption of such notes, the Trust securities will be mandatorily redeemable. See Note 9 to the financial statements of Alabama Power Company In Rem 8 o the 1998 Form 1 0-K for further details.

Corporate Accounting Department 4/28/2003 +

l A, A A

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CONTENTS Alabama Power Company 2002 Annual Report I

SUMMARY

2 LETTER TO INVESTORS 3 MANAGEMENTS REPORT 4 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS 5 MANAGEMENTS DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION 18 FINANCIAL STATEMENTS 25 NOTES TO FINANCIAL STATEMENTS 40 SELECTED FINANCIAL AND OPERATING DATA 42 DIRECTORS AND OFFICERS 43 CORPORATE INFORMATION

SUMMARY

Percent 2002 2001 Change Financial Highlights (in millions):

Operating revenues $3,710 $3,586 3.5 Operating expenses S2,688 $2,676 0.5 Net income after dividends on preferred stock $461 $387 19.3 Operating Data:

Kilowatt-hour sales (inmillions):

Retail 52,073 49,338 5.5 Sales for resale - non-affiliates 15,554 15,278 1.8 Sales for resale - affiliates 8,844 8,843 -

Total 76,471 73,459 4.1 Customers served at year-end (inthousands) 1,357 1,342 1.2 Peak-hour demand fin megawatts) 10,910 10,241 6.5 Capitalization Ratios (percent):

Common stock equity 49.8 42.9 Preferred stock 3.7 4.1 Company obligated mandatorily redeemable preferred securities 4.4 4.5 Long-term debt 42.1 48.5 (Excluding long-term debt due within one year)

Return on Average Common Equity(percent) 13.80 11.89 1

LETTER TO INVESTORS Alabama Power Company 2002 Annual Report Alabama Power Company faced many challenges during 2002. In meeting these challenges, we once again lived up to our reputation and showed our strength and stability.

Our customers know they can count on Alabama Power Company 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 we met the expectations of our customers in 2002 by exceeding our previous service-reliability record and maintaining low prices. Thanks to our excellent transmission and distribution system, electric service was available to customers 99.96 percent of the time.

Alabama Power Company again ranked in the top quartile in customer satisfaction in 2002, and our customers continued to pay prices that are 15% below the national average.

Alabama Power Company's commitment to our customers includes a desire to make the state a great place to live, work and do business. We are constantly researching and developing new ways to generate cleaner energy. We continue to be a leader in developing technology and taking the initiative to protect and clean up our environment.

We had a successful year and we believe the key to success will always be the same that is to make every decision with the best interest of your customer, shareholder and employee in mind and to 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 2002 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 14, 2003 2

MANAGEMENT'S REPORT Alabama Power Company 2002 Annual Report The management of Alabama Power Company has The Southern Company audit committee of its board of prepared - and is responsible for -- the financial directors, composed of five 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, a accounting principles generally accepted in the United committee of Alabama Power's board of directors, States and necessarily include amounts that are based on composed of three outside directors, meets periodically the best estimates and judgments of management. with management, the internal auditors and the Financial information throughout this annual report is 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 system of internal accounting controls Power Company in conformity with accounting principles is evaluated on an ongoing basis by the Company's generally accepted in the United States.

internal 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.

Charles D. McCrary William B. Hutchins, El[

President Executive Vice President, and Chief Executive Officer Chief Financial Officer, and Treasurer February 17, 2003 3

INDEPENDENT AUDITORS' REPORT Alabama Power Company:

We have audited the accompanying balance sheet and perform the audit to obtain reasonable assurance about statement of capitalization of Alabama Power Company whether the financial statements are free of material (a wholly owned subsidiary of Southern Company) as of misstatement. An audit includes examining, on a test December 31, 2002, and the related statements of income, basis, evidence supporting the amounts and disclosures in comprehensive income, common stockholder's equity, the financial statements. An audit also includes assessing and cash flows for the year then ended. These financial the accounting principles used and significant estimates statements are the responsibility of Alabama Power made by management, as well as evaluating the overall Company's management. Our responsibility is to express financial statement presentation. We believe that our an opinion on these financial statements based on our audit provides a reasonable basis for our opinion.

audit. The financial statements of Alabama Power Company as of December 31, 2001, and for each of the In our opinion, the 2002 financial statements (pages 18 two years then ended were audited by other auditors who to 39) present fairly, in all material respects, the financial have ceased operations. Those auditors expressed an position of Alabama Power Company at December 31, unqualified opinion on those financial statements and 2002, and the results of its operations and its cash flows included an explanatory paragraph that described a for the year then ended in conformity with accounting change in the method of accounting for derivative principles generally accepted in the United States of instruments and hedging activities in their report dated America.

February 13, 2002.

We conducted our audit in accordance with auditing standards generally accepted in the United States of Birmingham, Alabama America. Those standards require that we plan and February 17, 2003 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 16-34) 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 6L eL/

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 2002 Annual Report RESULTS OF OPERATIONS Revenues Earnings Operating revenues for 2002 were $3.7 billion, reflecting a

$124 million increase from 2001. The following table Alabama Power Company's 2002 net income after summarizes the principal factors that have affected dividends on preferred stock was $461 million, operating revenues for the past three years:

representing a $74 million (19.3 percent) increase from the prior year. This improvement is primarily attributable Amount to increased territorial energy sales and higher retail rates 2002 2001 2000 when compared to the prior year. More favorable weather (in thousands) conditions in 2002 as compared to the unusually mild Retail - prior year $2,747,673 $2,952,707 $2,811,117 weather experienced in 2001 contributed to the increases Change in -

in territorial sales. The increases in revenues were Base rates 76,326 22,918 -

partially offset by increased non-fuel operating expenses.

Sales growth 70,050 (36,197) 58,347 In 2001 earnings were $387 million, representing a 7.9 Weather 60,089 (61,846) 21,917 percent decrease from the prior year. This decline was Fuel cost recovery primarily attributable to a decrease in territorial energy and other (2,921) (129,909) 61,326 sales as a result of an economic downturn and milder Total retail 2,951,217 2,747,673 2,952,707 temperatures. Earnings in the year 2000 were $420 Sales for resale --

million, representing a 5 percent increase from the prior Non-affiliates 474,291 485,974 461,730 year. This improvement was primarily attributable to an Affiliates 188,163 245,189 166,219 increase in territorial sales partially offset by increased Total sales for resale 662,453 731,163 627,949 non-fuel operating expenses. Other operating revenues 96,862 107,554 86,805 The return on average common equity for 2002 was Total operating 13.80 percent compared to 11.89 percent in 2001 and revenues $3,710,533 $3,586,390 $3,667,461 13.58 percent in 2000. A condensed income statement is Percent change 3.5% (2.2)% 8.3%

as follows:

Increase (Decrease) Retail revenues of $3.0 billion in 2002 increased Amount From Prior Year $204 million (7.4 percent) from the prior year, decreased 2002 2002 2001 2000 $205 million (6.9 percent) in 2001, and increased $142 (in millions) million (5 percent) in 2000. The primary contributors to Operating revenues $3,710 $124 $(81) $282 the increase in revenues in 2002, shown in the table above, Fuel 970 (31) 38 108 were the positive effect of favorable weather conditions on Purchased power 249 (44) (56) 75 energy sales and increases in retail base rates (0.6 percent Other operation increase in July 2001, and 2 percent increases in October and maintenance 854 71 (56) 30 2001 and April 2002). The Company mitigated these Depreciation increases to the customer with a decrease to the energy and amortization 398 15 19 17 cost recovery factor in April 2002.

Taxes other than income taxes 217 2 5 5 Fuel rates billed to customers are designed to fully Total operating recover fluctuating fuel costs over a period of time.

expenses 2,688 13 (50) 235 Lower natural gas prices and increased hydro production Operating income 1,022 111 (31) 47 combined with decreased costs of purchased power have Other income resulted in an $83 million reduction in under-recovered (expense), net (269) 7 (15) (8) fuel costs. At December 31, 2002, the Company had Less - completely recovered its previously under-recovered fuel Income taxes 292 44 (13) 19 cost. Fuel revenues have no effect on net income because Net Income $ 461 $ 74 $(33) $ 20 they represent the recording of revenues to offset fuel expenses.

5

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Babana Power Company 2002 Annual Report Energy sales for resale outside the service area are Kilowatt-hour (KWH) sales for 2002 and the percent predominantly unit power sales under long-term contracts change by year were as follows:

to Florida utilities. Economy energy and energy sold under short-term contracts are also sold for resale outside KWH Percent Change the service area. Revenues from power sales contracts 2002 2002 2001 2000 have both a capacity and energy component. Capacity (millions) revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold Residential 17,403 9.6% (5.3)% 6.8%

at variable cost. These capacity and energy components Commercial 13,363 4.4 (1.5) 5.5 of the unit power contracts and other outside the service Industrial 21,103 3.1 (7.4) 0.7 area contracts with non-affiliates, were as follows: Other 204 3.7 (3.9) 2.3 Total retail 52,073 5.5 (5.2) 3.8 2002 2001 2000 Sales for resale -

(in thousands) Non-affiliates 15,554 1.8 2.9 19.4 Unit power - Affiliates 8,844 - 64.7 6.7 Capacity $119,193 $124,720 $127,445 Total 76,471 4.1 1.6 6.9 Energy 134,051 134,006 127,911 Other power contracts - Residential energy sales for 2002 experienced a 9.6 Capacity 14,613 13,324 11,546 percent increase over the prior year and total retail energy Energy 61,925 91,608 43,964 sales grew by 5.5 percent primarily as a result of warmer Total $329.782 $363,658 $310,866 summer temperatures and colder winter weather conditions compared to the previous year.

Capacity revenues from non-affiliates were relatively unchanged over the past three years. There are no Although retail sales to industrial customers increased significant scheduled declines in capacity until the 3.1 percent in 2002, overall sales to industrial customers termination of the unit power sales contracts in 2010. remain depressed due to the continuing effect of sluggish economic conditions.

Revenues from sales to affiliated companies within the Southern electric system, as well as purchases of energy, Retail energy sales in 2001 decreased by 5.2 percent will vary from year to year depending on demand and the due to milder temperatures and an economic downturn in availability and cost of generating resources at each the Company's service area. This was offset by an company. These transactions did not have a significant increase in sales for resale to affiliates. Increased impact on earnings. operation of the Company's combined cycle facilities due to lower natural gas prices and an increase in the Other operating revenues in 2002 decreased $11 Company's combined cycle capacity contributed to the million (9.9 percent) from 2001 due to a decrease in increase in sales for resale.

revenues from gas-fueled co-generation steam facilities The increase in 2000 retail energy sales was primarily primarily from lower gas prices and lower demand. Since co-generation steam revenues are generally offset by fuel due to the strength of business and economic conditions in expenses, these revenues did not have a significant impact the Company's service area. Residential energy sales on earnings. experienced a 6.8 percent increase over the prior year primarily as a result of warmer summer temperatures and The $21 million (23.9 percent) increase in other colder winter weather conditions compared to 1999.

operating revenues in 2001 and $20 million (30.5 percent) Expenses increase in 2000 were primarily attributed to increased steam sales in conjunction with the operation of the Total 2002 operating expenses of $2.7 billion increased by Company's co-generation facilities, fuel sales, and rent $13 million or 0.5 percent over the previous year. This from electric property. slight increase is mainly due to a $35 million increase in administrative and general expenses primarily related to employee salaries, insurance expense and injuries and damages expense, a $19 million increase in production 6

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabna Power Company 2002 Annual Report expenses related to boiler plant maintenance, and a $15 In 2002, total fuel and purchased power expenses of $1.2 million increase in depreciation and amortization expenses billion decreased $75 million (5.8 percent) due primarily to due to an increase in depreciable property. These increases lower average fuel cost, while total energy sales increased are offset by a $43 million decrease in purchased power 3,012 million kilowatt hours (4.1 percent) compared with expenses and a $14 million decrease in fuel expenses the amounts recorded in 2001. Fuel and purchased power related to lower coal prices. Fuel expenses, including expenses in 2001 decreased $18 million (1.4 percent) purchased power, are offset by fuel revenues and have no compared to 2000 because of milder temperatures in 2001.

effect on net income. Fuel and purchased power expenses increased $183 million (16 percent) in 2000 compared to 1999 because of hotter-In 2001 total operating expenses of $2.7 billion were than-normal summer weather in 2000.

down $50 million or 1.8 percent compared with 2000.

This decline is mainly due to an $18 million net decrease Purchased power consists of purchases from affiliates in fuel and purchased power costs related to lower fuel in the Southern electric system and non-affiliated prices, increased hydro generation and added capacity. companies. Purchased power transactions among the The Company also had a $56 million decrease in non- Company and its affiliates will vary from period to period production operation and maintenance expense related to depending on demand, the availability, and the variable settlements received in connection with the Company's production cost of generating resources at each company.

insurance program, lower costs related to services During 2002 purchased power transactions from non-provided by the system service company and Southern affiliates decreased $54 million (37 percent) due to the Nuclear, and a reduction to the natural disaster reserve addition in May 2001 of a combined cycle unit which accrual. These decreases in expense were partially offset generated 6.1 billion kilowatt hours in 2002, an 18.4 by a $19 million increase in depreciation and amortization percent increase over the previous year. Purchased power due to an increase in depreciable property. transactions from non-affiliates also declined in 2001 because of the addition of the combined cycle unit and an Total operating expenses of $2.7 billion in 2000 were increase in hydro generation resulting in a $20 million (12 up $235 million or 9.4 percent compared with the prior percent) decline from the year 2000.

year. This increase was mainly due to a $183 million increase in fuel and purchased power costs as a result of Depreciation and amortization expense increased 3.9 warmer summer temperatures and colder winter weather percent in 2002, 5.2 percent in 2001, and 4.9 percent in conditions compared to 1999, accompanied by a $23 2000. These increases reflect additions to property, plant, million increase in maintenance expenses related to and equipment.

overhead line clearing.

Allowance for Funds Used During Construction Fuel costs constitute the single largest expense for the (AFUDC) increased $4 million (57.5 percent) in 2002 due Company. The mix of fuel sources for generation of to an increase in the amount of construction work in electricity is determined primarily by system load, the unit progress over the prior year. AFUDC decreased $16 cost of fuel consumed, and the availability of hydro and million (68.9 percent) in 2001 due to completion of nuclear generating units. The amount and sources of construction of Plant Barry Unit 7 and placing it in service generation and the average cost of fuel per net KWH in May 2001. In 2000, AFUDC increased $11 million generated were as follows:

(94.6 percent) as a result of this construction.

2002 2001 2000 Total generation (billions of KWHs) 71 68 65 Interest expense decreased $26 million (9.9 percent) in 2002. The decrease reflects a decrease in interest on long-Sources of generation term debt due to refinancing activities. Interest expense (peent) -

Coal 62 64 72 increased $3 million (1.1 percent) in 2001 compared to Nuclear 19 18 19 2000. In 2000 interest expense was relatively flat when Hydro 6 6 3 compared to the previous year.

Gas 13 12 6 Average cost of fuel per net KWH generated (cents) -- 1.47 1.56 1.54 7

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2002 Annual Report Effects of Inflation Equalization plan. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional The Company is subject to rate regulation that is based on information.

the recovery of historical costs. In addition, the income tax laws are also based on historical costs. Therefore, The rates also provide for adjustments to recognize the inflation creates an economic loss because the Company is placing of new generating facilities into retail service recovering its costs of investments in dollars that have less under Rate CNP (Certificated New Plant). Effective July purchasing power. While the inflation rate has been 2001, the Company's retail rates were adjusted by 0.6 relatively low in recent years, it continues to have an percent under Rate CNP to recover costs for Plant Barry adverse effect on the Company because of the large Unit 7, which was placed into commercial operation on investment in utility plant with long economic lives. May 1, 2001.

Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting In April 2000, the APSC approved an amendment to gain that arises through financing facilities with fixed- the Company's existing rate structure to provide for the money obligations, such as long-term debt and preferred recovery of retail costs associated with certified purchased securities. Any recognition of inflation by regulatory power agreements. In November 2000, the APSC authorities is reflected in the rate of return allowed in the certified a seven-year purchased power agreement Company's approved electric rates. pertaining to a 615 megawatt wholesale generating facility under construction in Autaugaville, Alabama (Plant Future Earnings Potential Harris), which was sold to Southern Power in June 2001.

All of the 615 megawatts are scheduled to be available General beginning in June 2003. In addition, the APSC certified a The results of continuing operations for the past three seven-year purchase power agreement with a third party years are not necessarily indicative of future earnings for approximately 630 megawatts; one half of the capacity potential. The level of future earnings depends on will be available beginning in 2003, while the remaining numerous factors. The major factor is the ability of the half is scheduled to be available beginning in 2004. Rate Company to achieve energy sales growth while containing CNP will adjust retail rates one month after the contracted costs and maintaining a stable regulatory environment. capacity delivery is scheduled to begin.

Growth in energy sales is subject to a number of factors.

These factors include weather, competition, new short- In accordance with Financial Accounting Standards and long-term contracts with neighboring utilities, energy Board (FASB) Statement No. 87, Employers' Accounting conservation practiced by customers, the elasticity of for Pensions, the Company recorded non-cash pre-tax demand, and the rate of economic growth in the pension income of approximately $56 million in 2002.

Company's service area. Future pension income is dependent on several factors including trust earnings and changes to the plan. Current Assuming normal weather, sales to retail customers are estimates indicate a reversal of recording pension income projected to grow approximately 1.8 percent annually on to recording pension expense by as early as 2007.

average during 2003 through 2007. Postretirement benefit costs for the Company were $23 million in 2002 and are expected to continue to trend The Company currently operates as a vertically upward. A portion of pension income is capitalized based integrated utility providing electricity to customers within on construction related labor charges. For the Company, its traditional service area located in the state of Alabama. pension income and postretirement benefits are a Prices for electricity provided by the Company to retail component of the regulated rates and do not have a customers are set by the Alabama Public Service significant effect on net income. For more information Commission (APSC) under cost-based regulatory see Note 2 to the financial statements.

principles.

Proposed nuclear security legislation is expected to be Rates for the Company can be adjusted periodically introduced in the 10 8e Congress. The Nuclear Regulatory within certain limitations based on earned retail rate of Commission is also considering additional security return compared with an allowed return. Increases in retail measures for licensees that could require immediate rates of 2 percent were effective in April 2002 and October implementation. Any such requirements could have a 2001 in accordance with the Rate Stabilization 8

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

AlabamC Power Company 2002 Annual Report significant impact on the Company's nuclear power plant electricity provider. Some states have approved initiatives and result in increased operation and maintenance that result in a separation of the ownership and/or expenses as well as additional capital expenditures. The operation of generating facilities from the ownership impact of any new requirements would depend upon the and/or operation of transmission and distribution facilities.

development and implementation of the regulations. While various restructuring and competition initiatives have been discussed in Alabama, none have been enacted.

The Company is involved in various matters being In October 2000, the APSC completed a two-year study of litigated. See Note 3 to the financial statements for electric industry restructuring, concluding that (i) information regarding material issues that could possibly restructuring of the electric utility industry in Alabama affect future earnings. was not in the public interest and (ii) the APSC itself would not mandate retail competition or electric industry Compliance costs related to current and future restructuring without enabling state legislation. Electric environmental laws and regulations could affect earnings utility restructuring would require numerous issues to be if such costs are not fully recovered. The Clean Air Act resolved, including significant ones relating to recovery of and other important environmental items are discussed any stranded investments, full cost recovery of energy later under "Environmental Matters." produced, and other issues related to the energy crisis that occurred in California.

Industry Restructuring Continuing to be a low-cost producer could provide The electric utility industry in the United States is opportunities to increase market share and profitability in continuing to evolve as a result of regulatory and markets that evolve with changing regulation and competitive factors. Among the primary agents of change competition. Conversely, if the Company does not remain has been the Energy Policy Act of 1992 (Energy Act). a low-cost producer and provide quality service, then The Energy Act allows independent power producers energy sales growth could be limited, and this could (IPPs) to access a utility's transmission network in order significantly erode earnings.

to sell electricity to other utilities. This enhances the incentive for IPPs to build power plants for a utility's FERC Matters large industrial and/or commercial customers where retail access is allowed and to sell excess energy to other In December 1999, the Federal Energy Regulatory utilities. Also, electricity sales for resale rates were Commission (FERC) issued its final ruling on Regional affected by numerous new energy suppliers, including Transmission Organizations (RTOs). The order power marketers and brokers. encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern Company This past year, merchant energy companies and and its operating companies, including the Company, traditional electric utilities with significant energy have submitted a series of status reports informing the marketing and trading activities came under severe FERC of progress toward the development of a financial pressures. Many of these companies have Southeastern RTO. In these status reports, Southern completely exited or drastically reduced all energy Company explained that it is developing a for-profit marketing and trading activities and sold foreign and RTO known as SeTrans with a number of non-domestic electric infrastructure assets. The Company has jurisdictional cooperative and public power entities. In not experienced any material financial impact regarding 2001, Entergy Corporation and Cleco Power joined the its limited energy trading operations through SCS and SeTrans development process. In 2002, the sponsors of recent generating capacity additions. SeTrans established a Stakeholder Advisory Committee, which will participate in the development Although the Energy Act does not provide for retail of the RTO, and held public meetings to discuss the customer access, it was a major catalyst for the recent SeTrans proposal. On October 10, 2002, the FERC restructuring and consolidation taking place within the granted Southern Company's and other SeTrans' utility industry. Numerous federal and state initiatives sponsors petition for a declaratory order regarding the that promote wholesale and retail competition are in governance structure and the selection process for the varying stages. Among other things, these initiatives Independent System Administrator (ISA) of the allow retail customers in some states to choose their SeTrans RTO. The FERC also provided guidance on 9

MANAGEMENT'S DISCUSSION AND ANALYSIS (contanued)

Alabama Power Company 2002 Annual Report other issues identified in the petition. The SeTrans Accounting Policies sponsors announced the selection of ESB International, Ltd. (ESBI) to be the preferred ISA candidate. Should CriticalPolicy negotiations with this candidate successfully conclude with final agreement among the parties, the SeTrans The Company's significant accounting policies are sponsors intend to seek any state and federal regulatory described in Note 1 to the financial statements. The or other approvals necessary for formation of the Company's only critical accounting policy involves rate SeTrans RTO and the approval of ESBI to serve in the regulation. The Company is subject to the provisions of capacity of the SeTrans ISA. The creation of SeTrans FASB Statement No. 71, Accounting for the Effects of is not expected to have a material impact on the Certain Types of Regulation. In the event that a portion of Company's financial statements; however, the outcome the Company's operation is no longer subject to these of this matter cannot now be determined. provisions, the Company would be required to write off related regulatory assets and liabilities that are not In July 2002, the FERC issued a notice of proposed specifically recoverable and determine if any other assets rulemaking regarding open access transmission service and have been impaired. See Note 1 to the financial standard electricity market design. The proposal, if statements under "Regulatory Assets and Liabilities" for adopted, would among other things: (1)require additional information.

transmission assets of jurisdictional utilities to be operated by an independent entity; (2) establish a standard market New Accounting Standards design; (3) establish a single type of transmission service that applies to all customers; (4) assert jurisdiction over Derivatives the transmission component of bundled retail service; (5) establish a generation reserve margin; (6) establish Effective January 2001, the Company adopted FASB bid caps for a day ahead and spot energy markets; and Statement No. 133, Accounting for Derivative (7) revise the FERC policy on the pricing of Instruments and Hedging Activities, as amended. In transmission expansions. Comments on certain aspects October 2002, the Emerging Issues Task Force (E1Th of the proposal have been submitted by Southern of the FASB announced accounting changes related to Company and the Company. Any impact of this energy trading contracts in Issue No. 02-03. In October proposal on the Company will depend on the form in 2002, the Company prospectively adopted the EITF's which final rules may be ultimately adopted; however, requirements to reflect the impact of certain energy the Company's revenues, expenses, assets, and trading contracts on a net basis. This change had no liabilities could be adversely affected by changes in the material impact on the Company's income statement.

transmission regulatory structure in its regional power Another change also required certain energy trading market. contracts to be accounted for on an accrual basis effective January 2003. This change had no impact on In 2002, the Company initiated the relicensing the Company's current accounting treatment.

process for the Company's seven hydroelectric projects on the Coosa River (Weiss, Henry, Logan Martin, Lay, Asset Retirement Obligations Mitchell, Jordan, and Bouldin) and the Smith and Bankhead Projects on the Warrior River. The FERC Prior to January 2003, the Company accrued for the licenses for all of these nine projects expire in 2007. ultimate cost of retiring most long-lived assets over the Upon or after the expiration of each license, the United life of the related asset through depreciation expense.

States Government, by act of Congress, may take over FASB Statement No. 143, Accounting for Asset the project or the FERC may relicense the project either Retirement Obligations, establishes new accounting and to the original licensee or to a new licensee. The FERC reporting standards for legal obligations associated with may grant relicenses subject to certain requirements the ultimate cost of retiring long-lived assets. The that could result in additional costs to the Company. present value of the ultimate costs for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Additionally, Statement No. 143 10

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2002 Annual Report does not permit non-regulated companies to continue manage the volatility attributable to these exposures, the accruing future retirement costs for long-lived assets Company nets the exposures to take advantage of natural that they do not have a legal obligation to retire. For offsets and enters into various derivative transactions for more information regarding the impact of adopting this the remaining exposures pursuant to the Company's standard effective January 1, 2003, see Note I to the policies in areas such as counterparty exposure and financial statements under "Regulatory Assets and hedging practices. Company policy is that derivatives are Liabilities" and "Depreciation and Nuclear to be used primarily for hedging purposes. Derivative Decommissioning." positions are monitored using techniques that include market valuation and sensitivity analysis.

Guarantees The weighted average interest rate on variable long-In 2002, the FASB issued Interpretation No. 45, term debt outstanding at December 31, 2002 was 1.64%.

Accounting and Disclosure Requirements for If the Company sustained a 100 basis point change in Guarantees. This interpretation requires disclosure of interest rates for all variable long-term debt, the change certain direct and indirect guarantees as reflected in would affect annualized interest expense by $10.5 million.

Note 8 to the financial statements under "Guarantees." To further mitigate the Company's exposure to interest Also, the interpretation requires recognition of a rates, it has entered into interest rate swaps that were liability at inception for certain new or modified designed as cash flow hedges of variable rate debt or guarantees issued after December 31, 2002. The anticipated debt issuances. See Note 1 and Note 7 to the adoption of Interpretation No. 45 in January 2003 did financial statements under "Financial Instruments" for not have a material impact on the Company's financial additional information. The Company is not aware of any statements. facts or circumstances that would significantly affect such exposures in the near term.

FINANCIAL CONDITION Due to cost-based rate regulation, the Company has Overview limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To Over the last several years the Company's financial mitigate residual risks relative to movements in electricity condition has remained stable with emphasis on cost prices, the Company enters into fixed price contracts for control measures combined with significantly lower cost the purchase and sale of electricity through the wholesale of capital, achieved through the refinancing and/or electricity market.

redemption of higher-cost long-term debt and preferred stock. In addition, in October 2001, the APSC approved a revision to the Company's Rate ECR (Energy Cost The Company had gross property additions of $635 Recovery) allowing the recovery of specific costs million in 2002. The majority of funds needed for gross associated with the sales of natural gas that become property additions for the last several years have been necessary due to operating considerations at its electric provided from operating activities, principally from generating facilities. This revision also includes the cost earnings and non-cash charges to income such as of financial instruments used for hedging market price risk depreciation and deferred income taxes. The Statements up to 75 percent of the budgeted annual amount of natural of Cash Flows provide additional details. gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-Credit Rating Risk month window. Also, the premiums paid for natural gas financial options may not exceed 5 percent of the The Company does not have any credit agreements that Company's natural gas budget for that year.

would require material changes in payment schedules or terminations as a result of a credit rating downgrade. At December 31, 2002, exposure from these activities was not material to the Company's financial position, Exposure to Market Risk results of operations, or cash flows. The changes in fair value of derivative energy contracts and year-end The Company is exposed to market risks, including valuations were as follows:

changes in interest rates and certain commodity prices. To 11

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2002 Annual Report Changes in Fair Value Composite financing rates for long-term debt, 2002 2001 preferred stock, and preferred securities for the years 2000 (in thousands) through 2002, as of year-end, were as follows:

Contracts beginning of year $ 214 $ 567 Contracts realized or settled (21,088) (509) 2002 2001 2000 New contracts at inception * - Long-term debt interest Changes in valuation techniques rate 5.05% 5.72% 6.60%

Current period changes 42,276 156 Preferred stock dividend Contracts end of year $ 21,402 $ 214 rate 5.17 4.79 5.18 Preferred securities dividend rate 5.25 6.96 7.38 Source of Year-End Valuation Prices Total Maturity The Company's current liabilities exceed current Fair Value Year 1 1-3 Years assets because of securities due within one year. The (in thousands) Company intends to refinance debt that comes due during 2003. Subsequent to December 31, 2002, the Company Actively quoted $21,402 $26,462 $(5,060) has refinanced $167 million of securities classified as External sources current on the Balance Sheet with long-term securities. An Models and other additional $250 million of securities has been issued to methods retire long-term debt and for other corporate purposes.

Contracts end of Year $21,402 $26,462 $(5,060)

Capital Structure Unrealized gains and losses from mark to market adjustments on contracts related to the retail fuel hedging The Company's ratio of common equity to total programs are recorded as regulatory assets and liabilities. capitalization - including short-term debt - was 42.6 Realized gains and losses from these programs are percent in 2002, 42.8 percent in 2001, and 42.2 percent in included in fuel expense and are recovered through the 2000. See Note 7 to the financial statements under Company's fuel cost recovery clause. Gains and losses on "Capitalization" for additional information.

contracts that do not represent hedges are recognized in the Statements of Income as incurred. At December 31, Capital Requirements for Construction 2002, the fair value of derivative energy contracts reflected in the financial statements was as follows: Capital expenditures are estimated to be $643 million for 2003, $787 million for 2004, and $948 million for 2005.

Amounts (in millions)

Over the next three years the Company estimates spending

$485 million on environmental related additions including Regulatory liabilities, net $213 $355 million on Selective Catalytic Reduction facilities, Other comprehensive income

$164 million on Plant Farley including $43 million on Net income 0.1 replacing reactor vessel heads, $620 million on Total fair value $21.4 distribution facilities, and $569 million on transmission additions. See Note 8 to the financial statements for For the years ended December 31, 2002 and 2001, additional details.

approximately $(2.0) million and $2.0 million, respectively, of gains (losses) were recognized in income. Actual construction costs may vary from estimates Financing Activities because of changes in such factors as: business conditions; environmental regulations; nuclear plant In 2002, the Company's financing costs decreased due to regulations; FERC rules and transmission regulations; lower interest rates despite the issuance of new debt load projections; the cost and efficiency of construction during the year. New issues during 2000 through 2002 labor, equipment, and materials; and the cost of capital. In totaled $2.0 billion and retirement or repayment of higher- addition there can be no assurance that costs related to cost securities totaled $1.5 billion. capital expenditures will be fully recovered.

12

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabamm Power Company 2002 Annual Report Other Capital Requirements Sources of Capital In addition to the funds required for the Company's The Company plans to obtain the funds required for construction program, approximately $1.9 billion will be construction and other purposes from sources similar to required by the end of 2005 for maturities of long-terrn those used in the past, which were primarily from internal debt. The Company plans to continue, when economically sources. However, the type and timing of any financings feasible, to retire higher cost debt and preferred stock and - if needed - will depend on market conditions and replace these obligations with lower-cost capital if market regulatory approval. In recent years financings primarily conditions permit. have utilized unsecured debt and trust preferred securities.

As a result of requirements by the Nuclear Regulatory To meet short-term cash needs and contingencies, the Commission, the Company has established external trust Company has various internal and external sources of funds for the purpose of funding nuclear decommissioning liquidity. At the beginning of 2003, the Company had costs. Annual provisions for nuclear decommissioning are approximately $23 million of cash and cash equivalents and based on an annuity method as approved by the APSC. $923 million of unused credit arrangements with banks. In The amount expensed in 2002 was $18 million. For addition, the Company has substantial cash flow from additional information concerning nuclear operating activities and access to the capital markets to decommissioning costs, see Note 1 to the financial meet liquidity needs. Cash flows from operating activities statements under "Depreciation and Nuclear were $951 million in 2002, $838 million in 2001, and $827 Decommissioning." million in 2000. Credit arrangements are as follows:

In 1994 the Company also established an external trust Expires fund for postretirement benefits as ordered by the APSC. Total Unused 2003 2004 The cumulative effect of funding these items over a long (in millions) period will diminish internally funded capital and may $923 $923 $533 $390 require capital from other sources. For additional information, see Note 2 to the financial statements under Approximately $361 million of the credit facilities "Postretirement Benefits." expiring in 2003 allow for the execution of term loans for an additional two-year period. See Note 7 to the financial These capital requirements, lease obligations, purchase statements under "Bank Credit Arrangements" for commitments, and trust requirements - discussed above additional information.

and in the financial statements - are summarized as follows: The Company may also meet short-term cash needs 2003 2004 2005 through a Southern Company subsidiary organized to (in millions) issue and sell commercial paper at the request and for the Construction expenditures $$ 643.0 $787.0 $948.0 benefit of the Company and the other Southern Company Senior Notes 1,117.0 525.0 225.0 operating companies. At December 31, 2002, the Leases - Company had outstanding $37 million of commercial Capital 0.9 1.0 0.5 paper.

Operating 28.2 27.2 23.4 Purchase commitments - Environmental Matters Fuel 757.7 768.1 522.6 Purchased Power 53.0 83.0 86.0 New Source Review Enforcement Actions Long-term service agreements 25.7 15.2 14.3 In November 1999, the Environmental Protection Agency Trusts - (EPA) brought a civil action against the Company in the Nuclear decommissioning 20.3 20.3 20.3 U.S. District Court in Atlanta, Georgia. The complaint Postretirement benefits 5.1 4.9 24.2 alleges violations of the New Source Review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The civil action requests penalties and injunctive 13

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2002 Annual Report relief, including an order requiring the installation of the environmental media, including air, water, and land best available control technology at the affected units. The resources. Compliance with these environmental EPA concurrently issued to the Company a notice of requirements will involve significant costs, a major portion violation relating to these specific facilities, as well as of which is expected to be recovered through existing Plants Greene County and Gaston. In early 2000, the EPA ratemaking provisions. There is no assurance, however, filed a motion to amend its complaint to add the violations that all such costs will, in fact, be recovered.

alleged in its notice of violation. The complaint and notice of violation are similar to those brought against and issued Compliance with the federal Clean Air Act and to several other electric utilities. These complaints and resulting regulations has been and will continue to be, a notices of violation allege that the utilities failed to secure significant focus for the company. The Title IV acid rain necessary permits or install additional pollution control provisions of the Clean Air Act, for example, required equipment when performing maintenance and construction significant reductions in sulfur dioxide and nitrogen oxide at coal-burning plants constructed or under construction emissions. Compliance was required in two phases -

prior to 1978. Phase L effective in 1995 and Phase IL,effective in 2000.

Construction expenditures associated with Phase I and The U.S. District Court in Georgia granted Alabama Phase II compliance totaled approximately $88 million.

Power's motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims against Alabama Some of the expenditures required to comply with the Power in the U.S. District Court in Alabama. The Phase II acid rain requirements also assisted the Company Company's case has been stayed since the spring of 2001, in complying with nitrogen oxide emission reduction pending a ruling by the U.S. Court of Appeals for the requirements under Title I of the Clean Air Act, which Eleventh Circuit in the appeal of a very similar New were designed to address one-hour ozone nonattainment Source Review enforcement action against the Tennessee problems in Birmingham, Alabama. In December 2000, Valley Authority (TVA). The TVA appeal involves many the Alabama Department of Environmental Management of the same legal issues raised by the actions against the (ADEM) adopted revisions to the State Implementation Company. Because the outcome of the TVA appeal could Plan for meeting the one-hour ozone standard. New have a significant adverse impact on the Company, it is a emission limits to comply with these requirements must be party to that case as well. In February 2003, the U.S. implemented in May 2003. Two plants in the Birmingham District Court in Alabama extended the stay of the EPA area will be affected. Construction expenditures for litigation proceeding in Alabama until the earlier of May 6, compliance with these new rules are currently estimated at 2003 or a ruling by the U.S. Court of Appeals for the approximately $270 million, of which $70 million remains Eleventh Circuit in the related litigation involving TVA. to be spent.

The Company believes that it complied with applicable To help bring the remaining nonattainment areas into laws and the EPA's regulations and interpretations in effect at compliance with the one-hour ozone standard, in 1998 the the time the work in question took place. The Clean Air Act EPA issued regional nitrogen oxide reduction rules. Those authorizes civil penalties of up to $27,500 per day, per rules required 21 states, including Alabama, to reduce and violation at each generating unit. Prior to January 30, 1997, cap nitrogen oxide emissions from power plants and other the penalty was $25,000 per day. An adverse outcome in large industrial sources. Affected sources, including five any one of these cases could require substantial capital of the Company's coal-fired plants in Alabama, must expenditures that cannot be determined at this time and comply with the reduction requirements by May 31, could possibly require payment of substantial penalties. 2004. Additional construction expenditures for This could affect future results of operations, cash flows, compliance with these new rules are currently estimated at and possibly financial condition if such costs are not approximately $292 million, of which $287 million recovered through regulated rates. remains to be spent.

Environmental Statutes and Regulations In July 1997, the EPA revised the national ambient air quality standards for ozone and particulate matter. These The Company's operations are subject to extensive revisions made the standards significantly more stringent.

regulation by state and federal environmental agencies In the subsequent litigation of these standards, the U.S.

under a variety of statutes and regulations governing Supreme Court found the EPA's implementation program 14

MANAGEMENT'S DISCUSSION AND ANALYSIS (contnued)

Alabama Power Company 2002 Annual Report for the new ozone standards unlawful and remanded it to Further reductions in sulfur dioxide could also be the EPA for further rulemaking. The EPA is expected to required under the EPA's Regional Haze rules. The propose implementation rules designed to address the Regional Haze rules require states to establish Best court's concerns in 2003 and issue final implementation Available Retrofit Technology (BART) standards for rules in 2004. The remaining legal challenges to the new certain sources that contribute to regional haze. The standards, which were pending before the U.S. Court of Company has a number of plants that could be subject to Appeals, District of Columbia Circuit, have been resolved. these rules. The EPA regional haze program calls for States to submit State Implementation Plans in 2007 and The EPA plans to designate areas as attainment or 2008 that contain emission reduction strategies for nonattainment with the new eight-hour ozone standard by achieving progress toward the visibility improvement goal.

April 2004, based on air quality data for 2001 through In 2002, however, the U.S. Court of Appeals, District of 2003. Several areas within the Company's service area are Columbia Circuit, vacated and remanded the BART likely to be designated nonattainment under the new ozone provisions of the federal Regional Haze rules to the EPA standard. State implementation plans, including new for further rulemaking. Because new BART rules have not emission control regulations necessary to bring those areas been developed and state visibility assessments are only into attainment, could be required as early as 2007. Those beginning, it is not possible to determine the effect of these state plans could require further reductions in nitrogen rules on the company at this time.

oxide emissions from power plants. If so, reductions could be required sometime after 2007. The impact of any new The EPA's Compliance Assurance Monitoring (CAM) standards will depend on the development and regulations under Title V of the Clean Air Act require that implementation of applicable regulations. monitoring be performed to ensure compliance with emissions limitations on an ongoing basis. The regulations The EPA currently plans to designate areas as require certain facilities with Title V operating permits to attainment or nonattainment with the new fine particulate develop and submit a CAM plan to the appropriate matter standard by the end of 2004. Those area permitting authority upon applying for renewal of the designations will be based on air quality data collected facility's Title V operating permit. The Company is in the during 2001 through 2003. Several areas within the process of developing CAM plans, which could indicate a Company's service area will likely be designated need for improved particulate matter controls at affected nonattainment under the new particulate matter standard. facilities. Because the plans are still in the early stages of State implementation plans, including new regulations development, the Company cannot determine the extent to necessary to bring those areas into attainment could be which improved controls could be required or the costs required as early as the end of 2007. Those state plans will associated with any necessary improvements. Actual likely require reductions in sulfur dioxide emissions from ongoing monitoring costs are expensed as incurred and are power plants. If so, the reductions could be required not material for any period presented.

sometime after 2007. Any additional emission reductions and costs associated with the new fine particulate matter In December 2000, having completed its utility studies standard cannot be determined at this time. for mercury and other hazardous air pollutants (HAPS),

the EPA issued a determination that an emission control The EPA has also announced plans to issue a proposed program for mercury and, perhaps, other HAPS is Regional Transport Rule for the fine particulate matter warranted. The program is being developed under the standard by the end of 2003 and to finalize the rule in Maximum Achievable Control Technology provisions of 2005. This rule would likely require year-round sulfur the Clean Air Act. The EPA currently plans to issue dioxide and nitrogen oxide emission reductions from proposed rules regulating mercury emissions from electric power plants as early as 2010. If issued, this rule would utility boilers by the end of 2003, and those regulations are likely modify other state implementation plan scheduled to be finalized by the end of 2004. Compliance requirements for attainment of the fine particulate matter could be required as early as 2007. Because the rules have standard and the eight-hour ozone standard. It is not not yet been proposed, the costs associated with possible at this time to determine the effect such a rule compliance cannot be determined at this time.

would have on the Company.

In December 2002, the EPA issued final and proposed revisions to the New Source Review program under the 15

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2002 Annual Report Clean Air Act. In February 2003, several northeastern Under these various laws and regulations, the Company states petitioned the D.C. Circuit Court for a stay of the could incur substantial costs to clean up properties. The final rules. The proposed rules are open to public Company conducts studies to determine the extent of any comment and may be revised before being finalized by the required cleanup and will recognize in its financial EPA. If fully implemented, these proposed and final statements costs to clean up known sites. The Company regulations could affect the applicability of the New may be liable for a portion or all required cleanup costs for Source Review provisions to activities at the Company's additional sites that may require environmental facilities. In any event, any final regulations must be remediation. The Company has not incurred any adopted by the states in the Company's service area in significant cleanup costs to date.

order to apply to the Company's facilities. The effect of these proposed and final rules cannot be determined at this Under the Clean Water Act, the EPA is developing new time. rules aimed at reducing impingement and entrainment of fish and fish larvae at cooling water intake structures that Several major bills to amend the Clean Air Act to will require numerous biological studies, and perhaps, impose more stringent emissions limitations have been retrofits to some intake structures at existing power plants.

proposed. Three of these, the Bush Administration's Clear The new rule was proposed in February 2002 and will be Skies Act, the Clean Power Act of 2002, and the Clean Air finalized by August 2004. The impact of any new Planning Act of 2002, proposed to further limit power standards will depend on the development and plant emissions of sulfur dioxide, nitrogen oxides, and implementation of applicable regulations.

mercury. The latter two bills also proposed to limit emissions of carbon dioxide. None of these bills were Also, under the Clean Water Act, the EPA and ADEM enacted into law in the last Congress. Similar bills have are developing total maximum daily loads (IMDLs) for been, and are anticipated to be, introduced this year. The certain impaired waters. Establishment of maximum loads Bush Administration's Clear Skies Act was recently by the EPA or ADEM may result in lowering permit limits reintroduced, and President Bush has stated that it will be a for various pollutants and a requirement to take additional high priority for the Administration. Other bills already measures to control non-point source pollution (e.g., storm introduced include the Climate Stewardship Act of 2003, water runoff) at facilities discharging into waters for which which proposes capping greenhouse gas emissions. The TMDLs are established. Because the effect on the cost impacts of such legislation would depend upon the Company will depend on the actual TMDLs and permit specific requirements enacted. limitations established by the implementing agency, it is not possible to determine the effect on the Company at this Domestic efforts to limit greenhouse gas emissions have time.

been spurred by international discussions surrounding the Framework Convention on Climate Change and The EPA and state environmental regulatory agencies specifically the Kyoto Protocol, which proposes are reviewing and evaluating various other matters international constraints on the emissions of greenhouse including limits on pollutant discharges to impaired gases. The Bush Administration does not support U.S. waters, hazardous waste disposal requirements, and other ratification of the Kyoto Protocol or other mandatory regulatory matters. The impact of any new standards will carbon dioxide reduction legislation and has instead depend on the development and implementation of announced a new voluntary climate initiative which seeks applicable regulations.

an 18 percent reduction by 2012 in the rate of greenhouse gas emissions relative to the dollar value of the U.S. Several major pieces of environmental legislation are economy. The Company is involved in a voluntary periodically considered for reauthorization or amendment electric utility industry sector climate change initiative in by Congress. These include: the Clean Air Act; the Clean partnership with the government. Because this initiative is Water Act; the Comprehensive Environmental Response, still under development, it is not possible to determine the Compensation, and Liability Act; the Resource effect on the company at this time. Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community The Company must comply with other environmental Right-to-Know Act; and the Endangered Species Act.

laws and regulations that cover the handling and disposal of hazardous waste and releases of hazardous substances.

16

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2002 Annual Report Compliance with possible additional federal or state acceptance of the Company's new product and service legislation related to global climate change, offerings; the ability of the Company to obtain additional electromagnetic fields, and other environmental and generating capacity at competitive prices; weather and health concerns could also significantly affect the other natural phenomena; and other factors discussed Company. The impact of any new legislation, or elsewhere herein and in other reports (including the Form changes to existing legislation, could affect many areas 10-K) filed from time to time by the Company with the of the Company's operations. The full impact of any Securities and Exchange Commission.

such changes cannot, however, be determined at this time.

Cautionary Statement Regarding Forward-Looking Information The Company's 2002 Annual Report includes forward-looking statements in addition to historical information.

Forward-looking information includes, among other things, statements concerning projected retail sales growth and scheduled completion of new generation. In some cases, forward-looking statements can be identified by terminology such as "may," "will:, "could," "should,"

"expects," "plans 9'"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 restucturing of the electric utility industry, and also changes in environmental 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, 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; state and federal rate regulations; political, legal, and economic conditions and developments in the United States; internal restructuring or other restructuring options that may be pursued; the ability of counterparties of the Company to make payments as and when due; the effects of, and changes in, economic conditions in the areas in which the Company operates, including the current soft economy; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any simila such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the timing and 17

STATEMENTS OF INCOME For the Years Ended December 31,2002,2001, and 2000 Alabama Power Company 2002 Annual Report 2002 2001 2000 (in thousands)

Operating Revenues:

Retail sales $2,951,217 $2,747,673 $2,952,707 Sales for resale -

Non-affiliates 474,291 485,974 461,730 Affiliates 188,163 245,189 166,219 Other revenues 96,862 107,554 86,805 Total operating revenues 3,710,533 3,586,390 3,667,461 Operating Expenses:

Operation -

Fuel 969,521 1,000,828 963,275 Purchased power--

Non-affiliates 90,998 144,991 164,881 Affiliates 158,121 147,967 184,014 Other 574,979 508,264 538,529 Maintenance 279,406 275,510 301,046 Depreciation and amortization 398,428 383,473 364,618 Taxes other than income taxes 216,919 214,665 209,673 Total operating expenses 2,688,372 2,675,698 2,726,036 Operating Income 1,022,161 910,692 941,425 Other Income and (Expense):

Allowance for equity funds used during construction 11,168 7,092 22,769 Interest income 13,991 15,101 16,152 Equity in earnings of unconsolidated subsidiaries 3,399 4,494 3,156 Interest expense, net of amounts capitalized (225,706) (246,436) (235,331)

Distributions on preferred securities of subsidiary (24,599) (24,775) (25,549)

Other income (expense), net (32,184) -

(15,671) -

(24,995)

Total other income and (expense) (253,931) (260,195) (243,798)

Earnings Before Income Taxes 768,230 650,497 697,627 Income taxes 292,436 248,597 261,555 Earnings Before Cumulative Effect of Accounting Change 475,794 401,900 436,072 Cumulative effect of accounting change-less income taxes of $215 thousand 353 -

Net Income 475,794 402,253 436,072 Dividends on Preferred Stock 14,439 15,524 16,156 Net Income After Dividends on Preferred Stock $ 461,355 $ 386.729 $ 419,916 The accompanying notes are an integal part of these financial statemaents.

18

STATEMENTS OF CASH FLOWS For the Years Ended December 31,2002,2001, and 2000 Alabama Power Company 2002 Annual Report 2002 2001 2000 (i thousands)

Operating Activities:

Net income $ 475,794 $ 402,253 $ 436,072 Adjustments to reconcile net income to net cash provided from operating activities -

Depreciation and amortization 465,325 437,490 412,998 Deferred income taxes and investment tax credits, net 48,828 (21,569) 66,166 Pension, postretirement, and other employee benefits (34,464) (58,118) (53,362)

Other, net (50,863) (64,533) 15,659 Changes in certain current assets and liabilities -

Receivables, net (46,458) 88,325 (125,652)

Fossil fuel stock 25,535 (38,663) 23,967 Materials and supplies 3,728 (13,025) (10,662)

Other current assets 6,889 (15,474) (6,613)

Accounts payable 10,587 (83,077) 107,702 Taxes accrued (40,922) 46,187 3,266 Other current liabilities 86,850 158,110 (42,507)

Net cash provided from operating activities 950,829 837,906 827,034 Investing Activities:

Gross property additions (634,559) (635,540) (870,581)

Cost of removal net of salvage (32,105) (37,304) (34,378)

Sales of property - 102,068 Other 2,054 2,533 (15,036)

Net cash used for investing activities (664,610) (568,243) (919,995)

Financing Activities:

Increase (decrease) in notes payable, net 26,994 (271,347) 184,519 Proceeds -

Pollution control bonds - 35,000 Senior notes 975,000 442,000 250,000 Preferred securities 300,000 Common stock - 15,642 Capital contributions from parent company 49,788 107,313 204,371 Redemptions -

First mortgage bonds (350,000) (138,991) (111,009)

Pollution control bonds . (15,000)

Senior notes (415,602) (3,179) (5,041)

Other long-term debt (883) (842) (946)

Preferred securities (347,000) -

Preferred stock (70,000)

Payment of preferred stock dividends (14,176) (14,942) (16,110)

Payment of common stock dividends (431,000) (393,900) (417,100)

Other (22,411) (9,908) (951)

Net cash provided from (used for) financing activities (299,290) (248,154) 87,733 Net Change in Cash and Cash Equivalents (13,071) 21,509 (5,228)

Cash and Cash Equivalents at Beginning of Period 35,756 14,247 19,475 Cash and Cash Eguivalents at End of Period $ 22.685 $ 35.756 $ 14,247 Supplemental Cash Flow Information:

Cash paid during the period for -

Interest (net of $6,738, $11,690, and $19,953 capitalized $230,102 $246,316 $237,066 Income taxes (net of refunds) 236,634 223,961 175,303 The accompanying notes are an integral part of these financial statements.

19

BALANCE SHEETS At December 31,2002 and 2001 Alabama Power Company 2002 Annual Report Assets 2002 2001 (in thousands)

Current Assets:

Cash and cash equivalents $ 22,685 $ 35,756 Receivables -

Customer accounts receivable 240,052 201,566 Unbilled revenues 89,336 80,419 Under recovered regulatory clause revenues - 83,497 Other accounts and notes receivable 47,535 49,940 Affiliated companies 74,099 72,639 Accumulated provision for uncollectible accounts (4,827) (5,237)

Fossil fuel stock, at average cost 73,742 99,278 Materials and supplies, at average cost 187,596 191,324 Other 110,035 74,640 Total current assets 840,253 883,822 Property, Plant, and Equipment:

In service 13,506,170 13,159,560 Less accumulated provision for depreciation 5,543,416 5,309,557 7,962,754 7,850,003 Nuclear fuel, at amortized cost 103,088 88,777 Construction work in progress 478,652 357,906 Total property, plant, and equipment 8544,494 8,296,686 Other Property and Investments:

Equity investments in unconsolidated subsidiaries 45,553 44,742 Nuclear decommissioning trusts 292,297 317,508 Other 16,477 12,244 Total other property and investments 354,327 374,494 Deferred Charges and Other Assets:

Deferred charges related to income taxes 327,276 334,830 Prepaid pension costs 389,793 329,259 Unamortized debt issuance expense 4,361 8,150 Unamortized premium on reacquired debt 103,819 77,173 Department of Energy assessments 17,144 21,015 Other 104,539 108,031 Total deferred charges and other assets 946,932 878,458 Total Assets ' $10.686.006 $10.433,460 The accompanying notes are an integral part of these financial statements.

20

BALANCE SHEETS At December 31, 2002 and 2001 Alabama Power Company 2002 Annual Report Liabilities and Stockholder's Equity 2002 2001 (in thousands)

Current Liabilities:

Securities due within one year $ 1,117,945 $ 5,382 Notes payable 36,991 9,996 Accounts payable -

Affiliated 109,790 98,268 Other 150,195 151,705 Customer deposits 44,410 42,124 Taxes accrued -

Income taxes 80,438 113,003 Other 20,561 19,023 Interest accrued 36,344 35,522 Vacation pay accrued 33,901 32,324 Other 114,870 93,589 Total current liabilities 1,745,445 600,936 Long-term debt (See accompanying statements) 2,851,562 3,742,346 Deferred Credits and Other Liabilities:

Accumulated deferred income taxes 1,436,559 1,387,661 Deferred credits related to income taxes 177,205 202,881 Accumulated deferred investment tax credits 227,270 238,225 Employee benefits provisions 141,149 115,078 Deferred capacity revenues 33,924 40,730 Other 147,640 130,214 Total deferred credits and other liabilities 2,163,747 2,114,789 Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding company junior subordinated notes (See accompanying statements) 300,000 347,000 Cumulative preferred stock (See accompanying statements) 247,512 317,512 Common stockholder's equity (See accompanying statements) 3,377,740 3,310,877 Total Liabilities and Stockholder's Eauitv $10.686.006 $10.433.460 Commitments and Contingent Matters (See notes)

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

21

STATEMENTS OF CAPITALIZATION At December 31,2002 and 2001 Alabama Power Company 2002 Annual Report 2002 2001 2002 2001 (in thousands) (percent of total)

Long-Term Debt:

First mortgage bonds -

Maturity Interest Rates 2023 7.30% - 7.75% $ - $ 350,000 Total first mortgage bonds - 350,000 Long-term notes payable -

Variable rate (1.525% at /l1/03) due 2003 517,000 167,000 5.35% to 7.85% due 2003 406,200 406,200 4.875% to 7.125% due 2004 525,000 525,000 5.49% due November 1, 2005 225,000 225,000 7.125% due October 1, 2007 200,000 200,000 5.375% due October 1, 2008 160,000 160,000 4.70% to 7.125% due 2010-2048 1,408,800 1,199,402 Tntal lonn-te-rm inotpe nnvnhhle 3.442.000 2-882-602 Other long-term debt -

Pollution control revenue bonds -

Collateralized:

5.50% due 2024 24,400 24,400 Variable rates (1.56% to 1.80% at 1/1/03) due 2015-2017 89,800 89,800 Non-collateralized:

Variable rates (1.42% to 1.95% at 1/1/03) due 2021-2031 445,940 445,940 Total other long-term debt 560,140 560,140 Capitalized lease obligations 2,439 3,323 Unamortized debt premium (discount), net (35,072) (48,337)

Total long-term debt (annual interest requirement - $202.1 million) 3,969,507 3,747,728 Less amount due within one year 1,117,945 5,382 Long-term debt excluding amount due within one year $2,851,562 $3,742,346 42.1% 48.5%

22

STATEMENTS OF CAPITALIZATION (continued)

At December 31,2002 and 2001 Alabama Power Company 2002 Annual Report 2002 2001 2002 2001 (in thousands) (percent of total)

Company Obligated Mandatorily Redeemable Preferred Securities:

$25 liquidation value -

4.75% $ 100,000 $

5.50% 200,000 -

7.375% - 97,000 7.60% - 200,000 Auction rate (3.60% at 1/1/02) - 50,000 Total (annual distribution requirement - $15.8 million) 300,000 347,000 4.4 4.5 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 Auction rates - at /11/02 3.10% to 3.557% . 70,000 Total (annual dividend requirement - $12.8 million) 247,512 317,512 3.7 4.1 Common Stockholder's Equity:

Common stock, par value $40 per share -

Authorized - 6,000,000 shares Outstanding - 6,000,000 shares Par value 240,000 240,000 Paid-in capital 1,900,464 1,850,676 Premium on Preferred Stock 99 99 Retained earnings 1,250,594 1,220,102 Accumulated other comprehensive income (loss) (13,417)

Total common stockholder's equity 3,377,740 3,310,877 49.8 42.9 Total Capitalization $6.776,814 $7.717.735 100.0%

100.0%

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

23

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31,2002,2001, and 2000 Alabama Power Company 2002 Annual Report Premium on Other Common Paid-In Preferred Retained Comprehensive Stock Capital Stock Earnings Income (loss) Total (in thousands)

Balance at December 31, 1999 $224,358 $1,538,992 $99 $1,225,414 $ - $2,988,863 Net income after dividends on preferred stock - - - 419,916 - 419,916 Capital contributions from parent company - 204,371 - - - 204,371 Cash dividends on common stock - - - (417,100) - (417,100)

Other - - - (278) - (278)

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 Capital contributions from parent company - 107,313 - - - 107,313 Cash dividends on common stock - - - (393,900) - (393,900)

Issuance of common stock 15,642 - - - - 15,642 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 The accompanying notes are an integral part of these financial statments STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31,2002,2001, and 2000 Alabama Power Company 2002 Annual Report 2002 2001 2000 (in thousands)

Net income after dividends on preferred stock $461,355 $386,729 $419,916 Other comprehensive income (loss):

Change in additional minimum pension liability, net of tax of

$(2,536) (4,172) -

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

$(5,621) (9,245)

Total other comprehensive income (loss) (13,417) - -

Comnrehensive Income $447.938 $386.729 $419.916 The accompanying notes are an integral part of these financial statements.

24

NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2002 Annual Report

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING principles generally accepted in the United States requires POLICIES the use of estimates, and the actual results may differ from those estimates.

General Certain prior years' data presented in the financial Alabama Power Company (the Company) is a wholly statements have been reclassified to conform with current owned subsidiary of Southern Company, which is the year presentation.

parent company of five operating companies, Southern Power Company (Southern Power), a system service Affiliate Transactions company, Southern Communications Services (Southern The Company has an agreement with the system service LINC), Southern Company Gas (Southern GAS),

company under which the following services are rendered Southern Company Holdings (Southern Holdings),

to the Company at direct or allocated cost: general and Southern Nuclear Operating Company (Southern design engineering, purchasing, accounting and statistical Nuclear), Southern Telecom, and other direct and indirect analysis, finance and treasury, tax, information resources, subsidiaries. The operating companies -- Alabama Power marketing, auditing, insurance and pension administration, Company, Georgia Power Company, Gulf Power human resources, systems and procedures, and other Company, Mississippi Power Company, and Savannah services with respect to business and operations and power Electric and Power Company - provide electric service in pool transactions. Costs for these services amounted to four southeastern states. Southern Power constructs, $218 million, $183 million, and $187 million during 2002, owns, and manages Southern Company's competitive 2001, and 2000, respectively. Cost allocation generation assets and sells electricity at market-based rates methodologies used by the system service company are in the wholesale market. Contracts among the operating approved by the SEC and management believes they are companies and Southern Power -- related to jointly-owned reasonable.

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

services to the public within the Southeast. Southern Costs for these services amounted to $154 million, $160 Telecom provides fiber cable services within the million, and $148 million during 2002, 2001, and 2000, Southeast. Southern GAS, which began operation in respectively.

August 2002, is a competitive retail natural gas business serving communities in Georgia. Southern Holdings is an The Company has an agreement with Mississippi Power intermediate holding subsidiary for Southern Company's under which Mississippi Power owns a portion of Plant investments in leveraged leases, alternative fuel products, Greene County. The Company operates Plant Greene and an energy service business. Southern Nuclear County and Mississippi Power reimburses the Company provides services to the operating companys' nuclear for its proportionate share of expenses which were $6.4 power plants. million in 2002. See Note 4 for additional information.

Southern Company is registered as a holding company In 2001, the Company had under construction a 1,230 under the Public Utility Holding Company Act of 1935 megawatt combined cycle facility in Autaugaville, Alabama (PUHCA). Both Southern Company and its subsidiaries (Plant Harris). In June 2001, the Company sold this project are subject to the regulatory provisions of the PUHCA. to Southern Power. The Company has entered into an The Company is also subject to regulation by the FERC agreement with Southern Power to operate and maintain and the Alabama Public Service Commission (APSC). Plant Harris and provide fuel at cost beginning in June 2003.

The Company follows accounting principles generally accepted in the United States and complies with the The operating companies, including the Company, accounting policies and practices prescribed by its Southern Power, and Southern GAS may jointly enter into respective regulatory commissions. The preparation of various types of wholesale energy, natural gas and certain financial statements in conformity with accounting 25

NOTES (continued Alabama Power Company 20 Annual Repor other contracts, either directly or through the system Revenues and Fuel Costs service company as agent. Each participating company may be jointly and severally liable for the obligations The Company currently operates as a vertically integrated incurred under these agreements. utility providing electricity to retail customers within its traditional service area located within the state of Alabama Regulatory Assets and Liabilities and to wholesale customers in the southeast. Revenues are recognized as services are rendered. Unbilled revenues are The Company is subject to the provisions of Financial accrued at the end of each fiscal period. Fuel costs are Accounting Standards Board (FASB) Statement No. 71, expensed as the fuel is used. Electric rates for the Company Accounting for the Effects of Certain Types of include provisions to adjust billings for fluctuations in fuel Regulation. Regulatory assets represent probable future costs, fuel hedging, the energy component of purchased revenues associated with certain costs that are expected to power costs, and certain other costs. Revenues are adjusted be recovered from customers through the ratemaking for differences between recoverable fuel costs and amounts process. Regulatory liabilities represent probable future actually recovered in current regulated periods.

reductions in revenues associated with amounts that are expected to be credited to customers through the The Company has a diversified base of customers. No ratemaking process. single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible Regulatory assets and (liabilities) reflected in the accounts continue to average less than 1percent of Balance Sheets at December 31 relate to the following: revenues.

2002 2001 Fuel expense includes the amortization of the cost of (in millions) nuclear fuel and a charge based on nuclear generation for Deferred income tax charges $327 $335 the permanent disposal of spent nuclear fuel. Total Premium on reacquired debt 104 77 charges for nuclear fuel included in fuel expense Department of Energy assessments 17 21 amounted to $63 million in 2002, $58 million in 2001, and Vacation pay 34 32 $61 million in 2000. The Company has a contract with Deferred income tax credits (177) (203) the U.S. Department of Energy (DOE) that provides for Natural disaster reserve (12) (12) the permanent disposal of spent nuclear fuel. The DOE Fuel-hedging assets 4 failed to begin disposing of spent fuel in January 1998 as Fuel-hedging liabilities (21) (2) required by the contract, and the Company is pursuing Other regulatory assets 56 55 legal remedies against the government for breach of Other regulatory liabilities (12) (4) contract. Sufficient fuel storage capacity is available at Total $ 316 $ 303 Plant Farley to maintain full-core discharge capability until the refueling outage scheduled in 2006 for Farley See "Depreciation and Nuclear Decommissioning" in Unit 1 and the refueling outage scheduled in 2008 for this note for information regarding significant regulatory Farley Unit 2. Procurement of on-site dry spent fuel assets and liabilities created as a result of the January 1, storage capacity at Plant Farley is in progress, with the 2003, adoption of FASB Statement No. 143, Accounting intent to place the capacity in operation in 2005.

for Asset Retirement Obligations.

Also, the Energy Policy Act of 1992 required the In the event that a portion of the Company's operations establishment of a Uranium Enrichment Decontamination is no longer subject to the provisions of FASB Statement and Decommissioning Fund, which is funded in part by a No. 71, the Company would be required to write off special assessment on utilities with nuclear plants. This related regulatory assets and liabilities that are not assessment is being paid over a 15-year period, which specifically recoverable through regulated rates. In began in 1993. This fund will be used by the DOE for the addition the Company would be required to determine if decontamination and decommissioning of its nuclear fuel any impairment to other assets exists, including plant, and enrichment facilities. The law provides that utilities will write down the assets, if impaired, to their fair values. All recover these payments in the same manner as any other regulatory assets and liabilities are reflected in rates. fuel expense. The Company estimates its remaining liability under this law to be approximately $17 million at December 31, 2002. This obligation is recorded in other deferred credits in the accompanying Balance Sheets.

26

NOTES (continued)

Alabam Power Company 2002 Annual Report Depreciation and Nuclear Decommissioning removal of these assets will not be recorded because no reasonable estimate can be made regarding the timing Depreciation of the original cost of depreciable utility of any related retirements. The Company will continue plant in service is provided primarily by using composite to recognize in the income statement its ultimate straight-line rates, which approximated 3.2 percent in removal costs in accordance with its regulatory 2002, 2001, and 2000. When property subject to treatment. Any difference between costs recognized depreciation is retired or otherwise disposed of in the under Statement No. 143 and those reflected in rates normal course of business, its original cost - together with will be recognized as either a regulatory asset or the cost of removal, less salvage - is charged to liability as ordered by the APSC. It is estimated that accumulated depreciation. Minor items of property this annual difference will be approximately $4 million.

included in the original cost of the plant are retired when The APSC regulatory order states that actual asset the related property unit is retired. Depreciation expense removal costs will be recoverable in rates.

includes an amount for the expected cost of decommissioning nuclear facilities and removal of other Statement No. 143 does not permit non-regulated facilities. Prior to January 2003, in accordance with companies to continue accruing future retirement costs regulatory requirements, the Company followed the for long-lived assets they do not have a legal obligation industry practice of accruing for the ultimate cost of to retire. However, in accordance with the regulatory retiring most long-lived assets over the life of the related treatment of these costs, the Company will continue to asset as part of the annual depreciation expense provision. recognize the removal costs for these other obligations in their depreciation rates. As of January 1, 2003, the In January 2003, the Company adopted FASB amount included in the accumulated depreciation Statement No. 143, Accounting for Asset Retirement reserve that represents a regulatory liability for these Obligations. Statement No. 143 establishes new costs was $550 million.

accounting and reporting standards for legal obligations associated with the ultimate cost of retiring long-lived The Nuclear Regulatory Commission (NRC) requires assets. The present value of the ultimate costs for an all licensees operating commercial nuclear power reactors asset's future retirement must be recorded in the period in to establish a plan for providing with reasonable assurance which the liability is incurred. The cost must be funds for decommissioning. The Company has established capitalized as part of the related long-lived asset and external trust funds to comply with the NRC's regulations.

depreciated over the asset's useful life. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods There was no cumulative effect to net income resulting approved by the APSC. The NRC's minimum external from the adoption of Statement No. 143. The Company funding requirements are based on a generic estimate of received an accounting order from the APSC to defer the the cost to decommission the radioactive portions of a transition adjustment; therefore, the Company recorded a nuclear unit based on the size and type of reactor. The related regulatory liability of $71 million to reflect the Company has filed plans with the NRC to ensure that -

Company's regulatory treatment of these costs under over time - the deposits and earnings of the external trust Statement No. 71. The initial Statement No. 143 liability funds will provide the minimum funding amounts the Company recognized was $301 million, of which $310 prescribed by the NRC.

million was removed from the accumulated depreciation reserve. The amount capitalized to property, plant, and Site study cost is the estimate to decommission the equipment was $63 nillion. facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of its retirement The liability recognized to retire long-lived assets date. The estimated costs of decommissioning - both site primarily relates to the Company's nuclear facility, study costs and ultimate costs - based on the most current Plant Farley. In addition, the Company has retirement study for Plant Farley were as follows:

obligations related to various landfill sites and underground storage tanks. The Company has also identified retirement obligations related to certain transmission and distribution facilities, co-generation facilities, certain wireless communication towers, and certain structures authorized by the United States Army Corps of Engineers. However, a liability for the 27

NOTES (continued)

Aabama Power Company 2002 Annual Report Site study year 1998 Income Taxes Decommissioning periods: The Company uses the liability method of accounting for Beginning year 2017 deferred income taxes and provides deferred income taxes Completion year 2031 for all significant income tax temporary differences.

(in millions) Investment tax credits utilized are deferred and amortized Site study costs: to income over the average lives of the related property.

Radiated structures $629 Non-radiated structures 60 Allowance For Funds Used During Construction Total $689 (AFUDC) and Interest Capitalized (in millions)

Ultimate costs: In accordance with regulatory treatment, the Company Radiated structures $1,868 records AFUDC. AFUDC represents the estimated debt Non-radiated structures 178 and equity costs of capital funds that are necessary to Total $2,046 finance the construction of new regulated facilities. While cash is not realized currently from such allowance, it The decommissioning cost estimates are based on increases the revenue requirement over the service life of prompt dismantlement and removal of the plant from the plant through a higher rate base and higher service. The actual decommissioning costs may vary from depreciation expense. Interest related to the construction the above estimates because of changes in the assumed of new facilities not included in the Company's retail rates date of decommissioning, changes in NRC requirements, is capitalized in accordance with standard interest or changes in the assumptions used in making estimates. capitalization requirements. All current construction costs should be included in retail rates. The composite rate used Annual provisions for nuclear decommissioning are to determine the amount of AFUDC was 8.2 percent in based on an annuity method as approved by the APSC. 2002, 7.7 percent in 2001, and 9.6 percent in 2000.

The amount expensed in 2002 and fund balances as of AFUDC and interest capitalized, net of income tax, as a December 31, 2002 were as follows: percent of net income after dividends on preferred stock (in millions) was 3.3 percent in 2002 and 2001, and 8.4 percent in Amount expensed in 2002 $ 18 2000.

Accumulated provisions: Property, Plant, and Equipment External trust funds, at fair value $292 Internal reserves 34 Property, plant, and equipment is stated at original cost Total less regulatory disallowances and impairments. Original

$326 cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-All of the Company's decommissioning costs are related costs such as taxes, pensions, and other benefits; approved for recovery by the APSC through the and the estimated cost of funds used during construction.

ratemaking process. Significant assumptions include an estimated inflation rate of 4.5 percent and an estimated The cost of replacements of property--exclusive of trust earnings rate of 7.0 percent. The Company expects minor items of property-is capitalized. The cost of the APSC to periodically review and adjust, if necessary, maintenance, repairs and replacement of minor items of the amounts collected in rates for the anticipated cost of property is charged to maintenance expense as incurred or decommissioning. performed with the exception of nuclear refueling costs, which are recorded in accordance with specific APSC The Company has informed the NRC that the Company orders. The Company accrues estimated refueling costs in plans to submit an application in September 2003 to advance of the unit's next refueling outage. The refueling extend the operating license for Plant Farley for 20 cycle is 18 months for each unit. During 2002, the additional years. Company accrued $34.4 million to the nuclear refueling outage reserve and at December 31, the reserve balance was $9.7 million.

28

NOTES (continued)

Alabama Power Company 2002 Annual Report Impairment of Long-Lived Assets and Intangibles report a measure of all changes in common stock equity of an enterprise that result from transactions and other The Company evaluates long-lived assets for impairment economic events of the period other than transactions with when events or changes in circumstances indicate that the owners. For additional information, see Note 7.

carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is Stock Options based on either a specific regulatory disallowance or an Southern Company provides non-qualified stock options to estimate of undiscounted future cash flows attributable to a large segment of the Company's employees ranging from the assets, as compared with the carrying value of the line management to executives. The Company accounts assets. If an impairment has occurred, the amount of the for its stock-based compensation plans in accordance with impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the Accounting Principles Board Opinion No. 25.

Accordingly, no compensation expense has been carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared recognized because the exercise price of all options to the estimated fair value less the cost to sell in order to granted equaled the fair-market value on the date of grant.

When options are exercised, the Company receives a determine if an impairment provision is required. Until the capital contribution from Southern Company equivalent to assets are disposed of, their estimated fair value is reevaluated when circumstances or events change. the related income tax benefit.

Financial Instruments Cash and Cash Equivalents For purposes of the financial statements, temporary cash The Company uses derivative financial instruments to investments are considered cash equivalents. Temporary limit exposure to fluctuations in interest rates, the prices of cash investments are securities with original maturities of certain fuel purchases, and electricity purchases and sales.

All derivative financial instruments are recognized as 90 days or less.

either assets or liabilities and are measured at fair value.

Materials and Supplies Substantially all of the Company's bulk energy purchases and sales contracts are derivatives. However, in many Generally, materials and supplies include the cost of cases, these contracts qualify as normal purchases and transmission, distribution, and generating plant materials. sales and are accounted for under the accrual method.

Materials are charged to inventory when purchased and Other contracts qualify as cash flow hedges of anticipated then expensed or capitalized to plant, as appropriate, when transactions. This results in the deferral of related gains installed. and losses in other comprehensive income or regulatory assets or liabilities as appropriate until the hedged Natural Disaster Reserve transactions occur. Any ineffectiveness is recognized currently in net income. Contracts that do not qualify for the In accordance with an APSC order, the Company has normal purchase and sale exception and that do not meet the established a Natural Disaster Reserve. The Company is hedge requirements are marked to market through current allowed to accrue $250 thousand per month until the period income and are recorded on a net basis in the maximum accumulated provision of $32 million is Statements of Income.

attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the The Company is exposed to losses related to financial reserve declines below $22.4 million. During 2002, the instruments in the event of counterparties' Company accrued $3 million to the reserve and at nonperformance. The Company has established controls December 31, the reserve balance was $11.8 million. to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's Comprehensive Income exposure to counterparty credit risk.

Comprehensive income - consisting of net income and changes in the fair value of qualifying cash flow hedges and changes in additional minimum pension liabilities, less income taxes and reclassifications for amounts included in net income - is presented in the financial statements. The objective of comprehensive income is to 29

NOTES (continued Alabama Power Company 2002 Annual Report Other Company financial instruments for which the Pension Plan carrying amount did not equal fair value at December 31 were as follows: Changes during the year in the projected benefit obligations Carrying Fair and in the fair value of plan assets were as follows:

Amount Value (in milions) Projected Benefit Obligations Long-term debt:

2002 2001 At December 31,2002 $3,967 $4,065 (in millions)

At December 31, 2001 3,744 3,800 Balance at beginning of year $1,011 $ 925 Preferred Securities:

Service cost 26 25 At December 31,2002 300 303 Interest cost 74 70 At December 31,2001 347 346 Benefits paid (61) (56)

The fair value for long-term debt and preferred Actuarial gain and securities was based on either closing market prices or employee transfers 16 (1) closing prices of comparable instruments. Amendments 22 48 Balance at end of year $1,088 $1,011

2. RETIREMENT BENEFITS Plan Assets The Company has a defined benefit, trusteed, pension plan 2002 2001 that covers substantially all employees. The Company (in millions) also provides certain non-qualified benefit plans for a Balance at beginning of year $1,584 $1,921 selected group of management and highly-compensated Actual return on plan assets (106) (277) employees. The Company provides certain medical care Benefits paid (61) (56) and life insurance benefits for retired employees. Employee transfers 2 (4)

Substantially all employees may become eligible for such Balance at end of year $1,419 $1,584 benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations The accrued pension costs recognized in the Balance or to the extent required by the APSC and the FERC. In Sheets were as follows:

late 2000, as well as in 2002, the Company adopted several pension and postretirement benefit plan changes 2002 2001 that had the effect of increasing benefits to both current (in millions) and future retirees. Funded status $331 $ 573 Unrecognized transition obligation (10) (15)

Plan assets consist primarily of domestic and Unrecognized prior service cost 93 78 international equities, global fixed income securities, real Unrecognized net gain (loss) (40) (322) estate, and private equity investments. The measurement Prepaid asset, net 374 314 date for plan assets and obligations is September 30 of Portion included in each year. The weighted average rates assumed in the benefit obligations 16 15 actuarial calculations for both the pension and Prepaid asset recognized in the postretirement benefit plans were as follows: Balance Sheets $390 $ 329 2002 2001 2000 In 2002 and 2001, amounts recognized in the Balance Discount 6.50% 7.50% 7.50% Sheets for accumulated other comprehensive income and Annual salary increase 4.00 5.00 5.00 intangible assets were $6.7 million and $4.8 million, and Long-term return on plan assets 8.50 8.50 8.50 $0 and $6.3 million, respectively.

30

NOTES (continued)

Alabama Power Company 2002 Annual Report Components of the pension plan's net periodic cost Components of the plan's net periodic cost were as were as follows: follows:

2002 2001 2000 2002 2001 2000 (in millions) (in millions)

Service cost $ 26 $ 25 $ 23 Service cost $ 5 $ 5 $ 4 Interest cost 74 70 65 Interest cost 25 24 19 Expected return on plan assets (138) (131) (119) Expected return on plan assets (16) (15) (13)

Recognized net actuarial gain (20) (22) (19) Net amortization 9 7 4 Net amortization 2 1 (1) Net postretirement cost $ 23 $ 21 $ 14 Net pension cost (income) _ $ (56) $ (57) $ (51) 5 , . . . . .

An additional assumption used in measuring the Postretirement Benefits accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 8.75 Changes during the year in the accumulated benefit percent for 2002, decreasing gradually to 5.25 percent obligations and in the fair value of plan assets were as through the year 2010, and remaining at that level follows: thereafter. An annual increase or decrease in the assumed Accumulated medical care cost trend rate of 1 percent would affect the Benefit Obligations accumulated benefit obligation and the service and interest 2002 2001 cost components at December 31, 2002 as follows:

(in millions)

Balance at beginning of year $348 $264 1 Percent 1 Percent Service cost 5 5 Increase Decrease 24 (in millions)

Interest cost 26 Benefits paid (20) (18) Benefit obligation $32 $28 Actuarial gain and Service and interest costs 3 2 employee transfers 46 (13)

Amendments 86 Employee Savings Plan Balance at end of year $405 $348 The Company also sponsors a 401(k) defined contribution Plan Assets plan covering substantially all employees. The Company 2002 2001 provides a 75 percent matching contribution up to 6 (in millions) percent of an employee's base salary. Total matching

$169 $192 contributions made to the plan for the years 2002, 2001, Balance at beginning of year and 2000 were $12 million, $12 million, and $11 million, Actual return on plan assets (12) (24)

Employer contributions 21 19 respectively.

Benefits paid (20) (18)

$158 $169 Work Force Reduction Programs Balance at end of year The Company has incurred costs for work force reduction programs totaling $13.6 million, $13.0 million and $2.6 The accrued postretirement costs recognized in the million for the years 2002, 2001 and 2000, respectively.

Balance Sheets were as follows: These costs were deferred and are being amortized in 2002 2001 accordance with regulatory treatment over 22 month (in millions) periods. The unamortized balance of these costs was $5.1 Funded status $(247) $(179) million at December 31, 2002.

Unrecognized transition obligation 41 45 Prior service cost 77 82 Unrecognized net actuarial gain 66 (9)

Fourth quarter contributions 8 8 Accrued liability recognized in the Balance Sheets $ (55) $ (53) 31

NOTES (continued)

Alabana Power Company 2002 Annual Report

3. CONTINGENCIES AND REGULATORY lack of jurisdiction in Georgia. The EPA refiled its claims MAfTERS against Alabama Power in U.S. District Court in Alabama.

General Litigation Matters The Company's case has been stayed since the spring of 2001, pending a ruling by the U.S. Court of Appeals for the The Company is subject to certain claims and legal actions Eleventh Circuit in the appeal of a very similar New Source arising in the ordinary course of business. The Review enforcement action against the Tennessee Valley Company's business activities are also subject to Authority (TVA). The TVA appeal involves many of the extensive governmental regulation related to public health same legal issues raised by the actions against the and the environment. Litigation over environmental Company. Because the outcome of the TVA appeal could issues and claims of various types, including property have a significant adverse impact on the Company, it is a damage, personal injury, and citizen enforcement of party to that case as well. In February 2003, the U.S.

environmental requirements, has increased generally District Court in Alabama extended the stay of the EPA throughout the United States. In particular, personal litigation proceeding in Alabama until the earlier of May 6, injury claims for damages caused by alleged exposure to 2003 or a ruling by the U.S. Court of Appeals for the hazardous materials have become more frequent. Eleventh Circuit in the related litigation involving TVA.

The ultimate outcome of such litigation currently filed The Company believes that it complied with applicable against the Company cannot be predicted at this time; laws and the EPA's regulations and interpretations in however, after consultation with legal counsel, effect at the time the work in question took place. An management does not anticipate that the liabilities, if any, adverse outcome of this matter could require substantial arising from such proceedings would have a material capital expenditures that cannot be determined at this time adverse effect on the Company's financial statements. and possibly require payment of substantial penalties.

This could affect future results of operations, cash flows, Environmental Protection Agency Litigation and possibly financial condition if such costs are not recovered through regulated rates.

In November 1999, the EPA brought a civil action in U.S.

District Court in Georgia against the Company. The Retail Rate Adjustment Procedures complaint alleges violations of the New Source Review provisions of the Clean Air Act with respect to coal-fired The APSC has adopted rates that provide for periodic generating facilities at the Company's Plants Miller, adjustments based upon the Company's earned return on Barry, and Gorgas. The civil action requests penalties and end-of-period retail common equity. Increases in retail injunctive relief, including an order requiring the rates of 2 percent were effective in April 2002 and in installation of the best available control technology at the October 2001 in accordance with the Rate Stabilization affected units. The Clean Air Act authorizes civil Equalization Plan. In March 2002, the APSC approved a penalties of up to $27,500 per day, per violation at each revision to the rate adjustment procedures that provides generating unit. Prior to January 30, 1997, the penalty for an annual, rather than quarterly, adjustment and was $25,000 per day. imposes a 3 percent limit on changes in rates in any calendar year. The return on common equity range of The EPA concurrently issued to the Company a notice 13.0 percent to 14.5 percent remained unchanged.

of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA The rates also provide for adjustments to recognize the filed a motion to amend its complaint to add the violations placing of new generating facilities into retail service alleged in its notice of violation. The complaint and the under Rate CNP (Certificated New Plant). Effective July notice of violation are similar to those brought against and 2001, the Company's retail rates were adjusted by 0.6 issued to several other electric utilities. The complaint percent under Rate CNP to recover costs for Plant Barry and the notice of violation allege that the Company failed Unit 7, which was placed into commercial operation on to secure necessary permits or install additional pollution May 1, 2001.

control equipment when performing maintenance and construction at coal burning plants constructed or under In April 2000, the APSC approved an amendment to construction prior to 1978. The U.S. District Court in the Company's existing rate structure to provide for the Georgia granted Alabama Power's motion to dismiss for recovery of retail costs associated with certified purchased power agreements. In November 2000, the APSC 32

NOTES (continued)

Alabama Power Company 2002 Annual Report certified a seven-year purchased power agreement $24.5 million principal amount of pollution control revenue pertaining to a 615 megawatt wholesale generating facility bonds are outstanding. Georgia Power has agreed to under construction at Plant Harris, which was sold to reimburse the Company for the pro rata portion of such Southern Power in June 2001. All of the 615 megawatts obligation corresponding to its then proportionate are scheduled to be available beginning in June 2003. In ownership of stock of SEGCO if the Company is called addition, the APSC certified a seven-year purchased upon to make such payment under its guaranty.

power agreement with a third party for approximately 630 megawatts; one half of the capacity will be available At December 31, 2002, the capitalization of SEGCO beginning in 2003 while the remaining half is scheduled to consisted of $59 million of equity and $92 million of debt on which the annual interest requirement is $2.2 million.

be available beginning in 2004. Rate CNP will adjust retail rates one month after the contracted capacity SEGCO paid dividends totaling $5.8 million in 2002, $0.7 million in 2001, and $5.1 million in 2000, of which one-delivery is scheduled to begin.

half of each was paid to the Company. In addition, the In October 2001, the APSC approved a revision to the Company recognizes 50 percent of SEGCO's net income.

Company's Rate ECR (Energy Cost Recovery) allowing the recovery of specific costs associated with the sales of The Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2002 natural gas that become necessary due to operating is as follows:

considerations at its electric generating facilities. This revision also includes the cost of financial tools used for Total hedging market price risk up to 75 percent of the budgeted Megawatt Company annual amount of natural gas purchases. The Company Facility (Type) Capacity Ownership may not engage in natural gas hedging activities that Greene County 500 60.00% (1) extend beyond a rolling 42-month window. Also, the (coal) premiums paid for natural gas financial options may not Plant Miller exceed 5 percent of the Company's natural gas budget for Units 1 and 2 1,320 91.84% (2) that year. (coal)

(1) Jointly owned with an affiliate, Mississippi Power Company.

The Company's ratemaking procedures will remain in (2) Jointly owned with Alabama Electric Cooperative, Inc.

effect until the APSC votes to modify or discontinue them.

Company Accumulated

4. JOINT OWNERSHIP AGREEMENTS Facility Investment Depreciation (in millions)

The Company and Georgia Power own equally all of the Greene County $105 $ 51 outstanding capital stock of Southern Electric Generating Plant Miller Company (SEGCO), which owns electric generating units Units 1 and 2 760 341 with a total rated capacity of 1,020 megawatts, together with associated transmission facilities. The capacity of The Company has contracted to operate and maintain these units is sold equally to the Company and Georgia the jointly owned facilities as agent for their co-owners.

Power under a contract which, in substance, requires The Company's proportionate share of their plant payments sufficient to provide for the operating expenses, operating expenses is included in the operating expenses taxes, interest expense and a return on equity, whether or in the Statements of Income.

not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year 5. LONG-TERM POWER SALES AGREEMENTS periods, subject to either party's right to cancel upon two year's notice. The Company's share of expenses totaled General

$84 million in 2002, $80 million in 2001, and $85 million in 2000 and is included in "Purchased power from The Company and the other operating companies of affiliates" in the Statements of Income. Southern Company have entered into long-term contractual agreements for the sale of capacity to certain In addition the Company has guaranteed unconditionally non-affiliated utilities located outside the system's service the obligation of SEGCO under an installment sale area. These agreements are firm and related to specific agreement for the purchase of certain pollution control generating units. Because the energy is generally facilities at SEGCO's generating units, pursuant to which 33

NOTES (continued)

Alabama Power Company 2002 Annual Report provided at cost under these agreements, profitability is Details of the income tax provisions are as follows:

primarily affected by capacity revenues.

2002 2001 2000 Unit power from Plant Miller is being sold to Florida (in millions)

Power Corporation (FPC), Florida Power & Light Total provision for income Company (FP&L), and Jacksonville Electric Authority taxes:

(JEA). Under these agreements approximately 1,239 Federal -

megawatts of capacity are scheduled to be sold annually Current $209 $234 $168 through the expiration of the contract in 2010. The Deferred 41 (20) 60 Company's capacity revenues from these unit power sales 250 214 228 amounted to $119 million in 2002, $125 million in 2001, State --

and $127 million in 2000. Current 35 37 27 Deferred 7 (2) 7 Alabama Municipal Electric Authority (AMEA) 42 35 34 Capacity Contracts Total $292 $249 $262 In October 1991, the Company entered into a firm power sales contract with AMEA entitling AMEA to scheduled The tax effects of temporary differences between the amounts of capacity (up to a maximum 80 megawatts) for carrying amounts of assets and liabilities in the financial a period of 15 years. Under the terms of the contract, the statements and their respective tax bases, which give rise Company received payments from AMEA representing to deferred tax assets and liabilities, are as follows:

the net present value of the revenues associated with the capacity entitlement, discounted at an effective annual rate 2002 2001 of 11.19 percent. These payments are being recognized as (in millions) operating revenues and the discount is amortized to other Deferred tax liabilities:

interest expense as scheduled capacity is made available Accelerated depreciation $1,081 $1,034 over the terms of the contract. Property basis differences 381 390 Fuel cost adjustment 28 To secure AMEA's advance payments and the Premium on reacquired debt 39 29 Company's performance obligation under the contracts, Pensions 103 89 the Company issued and delivered to an escrow agent first Other 38 23 mortgage bonds representing the maximum amount of Total 1,642 1,593 liquidated damages payable by the Company in the event Deferred tax assets:

of a default under the contracts. No principal or interest is Capacity prepayments 11 13 payable on such bonds unless and until a default by the Other deferred costs 13 14 Company occurs. As the liquidated damages decline, a Postretirement benefits 18 21 portion of the bond equal to the decrease is returned to the Unbilled revenue 20 18 Company. At December 31, 2002, $32.6 million of these Other 87 93 bonds was held by the escrow agent under the contract. Total 149 159 Total deferred tax liabilities, net 1,493 1,434

6. INCOME TAXES Portion included in current liabilities, net (56) (47)

At December 31, 2002, the Company's tax-related Accumulated deferred income taxes regulatory assets and liabilities were $327 million and in the Balance Sheets $1,437 $1,387

$177 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years In accordance with regulatory requirements, deferred and to taxes applicable to capitalized interest. These investment tax credits are amortized over the lives of the liabilities are attributable to deferred taxes previously related property with such amortization normally applied as recognized at rates higher than current enacted tax law and a credit to reduce depreciation in the Statements of Income.

to unamortized investment tax credits. Credits amortized in this manner amounted to $11 million in 2002, 2001, and 2000. At December 31, 2002, all investment tax credits available to reduce federal income taxes payable had been utilized.

34

NOTES (continued)

Alabama Power Company 2002 Annual Report A reconciliation of the federal statutory income tax rate Pollution Control Bonds to the effective income tax rate is as follows:

Pollution control obligations represent installment 24002 2001 2000 purchases of pollution control facilities financed by funds Federal statutory rate I15.0% 35.0% 35.0% derived from sales by public authorities of revenue bonds.

State income tax, The Company is required to make payments sufficient for net of federal deduction 35 3.5 3.1 the authorities to meet principal and interest requirements Non-deductible book of such bonds. With respect to $114.2 million of such depreciation 1.3 1.5 1.4 pollution control obligations, the Company has Differences in prior years' authenticated and delivered to the trustees a like principal deferred and current tax rates (1.2) (1.3) (1.3) amount of first mortgage bonds as security for its Other i(0.5) (0.5) (0.7) obligations under the installment purchase agreements.

Effective income tax rate M8.1% 38.2% 37.5% No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the Southern Company files a cons olidated federal income installment purchase agreements. The amount of pollution tax return. Under a joint consolidc ited income tax control revenue bonds outstanding was $560 million at agreement, each subsidiary's curre-nt and deferred tax December 31, 2002 and 2001.

expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is Senior Notes jointly and severally liable for the tax liability.

The Company issued a total of $975 million of unsecured

7. CAPITALIZATION senior notes in 2002. The proceeds of these issues were Mandatorily Redeemable Preferred Securities used to redeem higher cost debt and for other general corporate purposes.

Statutory business trusts formed by the Company, of which the Company owns all the common securities, have At December 31, 2002 and 2001, the Company had $3.A issued mandatorily redeemable flexible trust preferred billion and $2.9 billion, respectively, of senior notes securities as follows: outstanding. These senior notes are subordinate to all secured debt of the Company which amounted to Date of Maturity approximately $302 million at December 31, 2002.

Issue Amount Rate* Notes Date (mieons)

(nitions)

Capitalized Leases TrustIV 10/2002 $100 4.75% $103 10t2042 Trust V 10/2002 200 5.50 206 10/2042 The estimated aggregate annual maturities of capitalized

• Issued at a five year initial fixed rate and a seven year initial fixed rate for lease obligations through 2006 are as follows: $0.9 million Trust IV and Trust V, respectively, and thereafter, at fixed rates determined through ernarketings for specific periods of varying length or at floating rates in 2003, $1.0 million in 2004, $0.5 million in 2005, and determined by reference to 3-month IUBOR plus 291% and 3.10%. respectively. $0.1 million in 2006.

Substantially all of the assets of each trust are junior Securities Due Within One Year subordinated notes issued by the Company in the respective approximate principal amounts set forth above. A summary of the improvement fund requirements and The Company considers that the mechanisms and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:

obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by 2002 2001 the Company of the Trusts' payment obligations with (in thousands) respect to the preferred securities.

First mortgage bond maturities The Trusts are subsidiaries of the Company and and redemptions $ - $4,498 accordingly are consolidated in the Company's financial Other long-term debt maturities statements. and redemptions 1,117,945 884 Total long-term debt due within The securities issued by Trusts L IL and Ell were one year $1,117,945 $5,382 redeemed in 2002.

35

NOTES (continued)

Alabama Power Company 2002 Annual Report Bank Credit Arrangements hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings. The gain or The Company maintains committed lines of credit in the loss in fair value for cash flow hedges is recorded in other amount of $923 million (including $454 million of such comprehensive income and will be recognized in earnings lines which are dedicated to funding purchase obligations over the life of the hedged items.

relating to variable rate pollution control bonds). Of these lines, $533 million expire at various times during 2003 At December 31, 2002, the Company had and $390 mirnion expire in 2004. In certain cases, such $1.25 billion notional amount of interest rate swaps lines require payment of a commitment fee based on the outstanding with net deferred losses of $15 million as unused portion of the commitment or the maintenance of follows:

compensating balances with the banks. Commitment fees are less than 1/8 of 1 percent for the Company. Because Cash Flow Hedges the arrangements are based on an average balance, the Weighted Average Company does not consider any of its cash balances to be Variable Fixed Fair restricted as of any specific date. An annual fee is also Rate Rate Notional Value paid to the agent bank. Maturity Received Paid Amount (Loss)

(in millions)

Most of the Company's credit arrangements with 2003 1.5.95 3.02 $350 $(5) banks have covenants that limit the Company's debt to 65 2004 1.'.4 1.63 486 (2) percent of total capitalization. Exceeding this debt level 2003

• 3.05 167 (2) would result in a default under the credit arrangements. 2003

• 3.96 250 (6)

In addition, the credit arrangements typically contain *Rate has not been set.

cross default provisions on other indebtedness of the Company that would be triggered if the Company Assets Subject to Lien defaulted on other indebtedness above a specified threshold. The Company is currently in compliance with The Company's mortgage, as amended and supplemented, all such covenants. Borrowings under unused credit securing the first mortgage bonds issued by the Company, arrangements totaling $74 million would be prohibited if constitutes a direct lien on substantially all of the the Company experiences a material adverse change (as Company's fixed property and franchises.

defined in such arrangements).

8. COMMITMENTS The Company borrows through commercial paper programs that have the liquidity support of committed Construction Program bank credit arrangements. In addition, the Company borrows from time to time pursuant to arrangements with The Company's construction program includes significant banks for uncommitted lines of credit and through projects related to transmission, distribution and extendible commercial note programs. At December 31, generating facilities, including the expenditures necessary 2002, there were no extendible commercial notes to comply with environmental regulation. The Company outstanding. The amount of commercial paper currently estimates property additions to be $643 million outstanding at December 31, 2002 was $37 million. in 2003, $787 million in 2004, and $948 million in 2005.

At December 31, 2002, the Company had regulatory The capital budget is subject to periodic review and approval to have outstanding up to $1 billion of short-term revision, and actual capital costs incurred may vary from borrowings. estimates because of numerous factors. These factors include: changes in business conditions; revised load Financial Instruments growth estimates; changes in environmental regulations; changes in existing nuclear plants to meet new regulatory The Company enters into interest rate swaps to hedge requirements; increasing costs of labor, equipment, and exposure to interest rate changes. Swaps related to fixed materials; and cost of capital. At December 31, 2002, rate securities are accounted for as fair value hedges. significant purchase commitments were outstanding in Swaps related to variable rate securities or forecasted connection with the construction program. There can be transactions are accounted for as cash flow hedges. The no assurance that costs related to capital expenditures will swaps are generally structured to mirror the terms of the be fully recovered.

36

NOTES (continued)

Alabama Power Company 2002 Annual Report Southern Company has guaranteed Southern Power Fuel Commitments obligations totaling $6.6 million for the Company's construction of transmission interconnection facilities to To supply a portion of the fuel requirements of its Plant Harris. generating plants, the Company has entered into various long-term commitments for the procurement of fossil and Long-Term Service Agreements nuclear fuel. In most cases these contracts contain provisions for price escalations, minimum purchase levels, The Company has entered into several Long-Term and other financial commitments. Total estimated long-Service Agreements (LTSAs) with General Electric term obligations at December 31, 2002, were as follows:

(GE) for the purpose of securing maintenance support for its combined cycle and combustion turbine Year Commnitments generating facilities. In summary, the LTSAs stipulate (in millions) that GE will perform all planned maintenance on the 2003 $ 772 covered equipment, which includes the cost of all labor 2004 782 and materials. GE is also obligated to cover the costs 2005 537 of unplanned maintenance on the covered equipment 2006 448 subject to a limit specified in each contract. 2007 453 2008 and thereafter 280 In general, these LTSAs are in effect through two Total commitments $3.272 major inspection cycles per unit. Scheduled payments to GE are made at various intervals based on actual In addition, the system service company acts as agent operating hours of the respective units. Total payments for the five operating companies, Southern Power, and to GE under these agreements are currently estimated at Southern GAS with regard to natural gas purchases.

$253 million over the life of the agreements, which are Natural gas purchases (in dollars) are based on various approximately 12 to 14 years per unit. However, the indices at the actual time of delivery; therefore, only the LTSAs contain various cancellation provisions at the volume commitments are firm. The Company's option of the Company. committed volumes allocated based on usage projections, as of December 31, 2002, are as follows:

Payments made to GE prior to the performance of any planned maintenance are recorded as a prepayment Year Natural Gas in the Balance Sheets. Inspection costs are capitalized (MMBtu) or charged to expense based on the nature of the work 2003 91,672,637 performed. 2004 53,978,335 2005 20,562,820 Purchased Power Commitments 2006 12,962,557 2007 4,534,876 The Company has entered into various long-term Total commitments 183.711.225 commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 2002 were as Additional commitments for fuel will be required to follows: supply the Company's future needs.

Commitmenlts Non- Acting as an agent for all of Southern Company's Affiliated Affiliated Total operating companies, Southern Power, and Southern GAS, (in millions) the system service company may enter into various types of 2003 $ 37 $ 16 $ 53 wholesale energy and natural gas contracts. Under these 2004 49 34 83 agreements, each of the operating companies, Southern 2005 49 37 86 Power, and Southern GAS may be jointly and severally liable 2006 49 38 87 for the obligations of each of the operating companies.

2007 49 39 88 Accordingly, the creditworthiness of Southern Power and 2008 and thereafter 111 103 214 Southern GAS is currently inferior to the creditworthiness of Total commitments $344 $267 $611 the operating companies. Southern Company has entered into 37

NOTES (contnued Alabama Power Company 2002 Annual Report keep-well agreements with each of the operating companies 9. NUCLEAR INSURANCE to insure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the Under the Price-Anderson Amendments Act of 1988 (the inclusion of Southern Power or Southern GAS as a Act), the Company maintains agreements of indemnity contracting party under these agreements. with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident Operating Leases occurring at Plant Farley. The Act provides funds up to

$9.5 billion for public liability claims that could arise from The Company has entered into rental agreements for coal a single nuclear incident. Plant Farley is insured against rail cars, vehicles, and other equipment with various terms this liability to a maximum of $300 million by American and expiration dates. These expenses totaled $29.6 Nuclear Insurers (ANI), with the remaining coverage million in 2002, $27.9 million in 2001, and $20.9 million provided by a mandatory program of deferred premiums in 2000. Of these amounts, $19.1 million, $21.1 million, which could be assessed, after a nuclear incident, against and $20.9 million for 2002,2001, and 2000, respectively, all owners of nuclear reactors. The Company could be relates to the railcar leases and is recoverable through the assessed up to $88 million per incident for each licensed Company's energy cost recovery clause. At December 31, reactor it operates, but not more than an aggregate of $10 2002, estimated minimum rental commitments for million per incident to be paid in a calendar year for each noncancellable operating leases were as follows: reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $176 Vehicles million per incident but not more than an aggregate of $20 Year Railcars & Other Total million to be paid for each incident in any one year.

(in millions) 2003 $18.6 $ 9.6 $ 28.2 The Company is a member of Nuclear Electric 2004 18.2 9.0 27.2 Insurance Limited (NEIL), a mutual insurer established to 2005 15.5 7.9 23.4 provide property damage insurance in an amount up to 2006 10.6 5.6 16.2 $500 million for members' nuclear generating facilities.

2007 3.3 2.8 6.1 2008 and thereafter 33.4 4.2 37.6 Additionally, the Company has policies that currently Total minimum payments $99.6 $39.1 $138.7 provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.

In addition to the rental commitments above, the This excess insurance is also provided by NEIL.

Company has potential obligations upon expiration of certain leases with respect to the residual value of the NEIL also covers the additional cost that would be leased property. These leases expire in 2004 and 2006, incurred in obtaining replacement power during a and the Company's maximum obligations are $25.7 prolonged accidental outage at a member's nuclear plant.

million and $66 million, respectively. At the termination Members can purchase this coverage, subject to a of the leases, at the Company's option, the Company may deductible waiting period of between 8 to 26 weeks, with negotiate an extension, exercise its purchase option, or the a maximum per occurrence per unit limit of $490 million.

property can be sold to a third party. The Company After this deductible period, weekly indemnity payments expects that the fair market value of the leased property would be received until either the unit is operational or would substantially reduce or eliminate the Company's until the limit is exhausted in approximately three years.

payments under the residual value obligations. The Company purchases the maximum limit allowed by NEIL and has elected a 12 week waiting period.

Guarantees Under each of the NEIL policies, members are subject At December 31, 2002, the Company had outstanding to assessments if losses each year exceed the accumulated guarantees related to SEGCO's purchase of certain funds available to the insurer under that policy. The pollution control facilities, as discussed in Note 4, and to current maximum annual assessments for the Company certain residual values of leased assets. See "Operating under the three NEIL policies would be $36 million.

Leases" above. Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power stations would be covered 38

NOTES (continued)

Ahbama Power Company 2002 Annua Report under their insurance. However, both companies revised their policy terms on a prospective basis to include an industry aggregate for all terrorist acts. The NEIL aggregate, which applies to all claims stemming from terrorism within a 12 -month duration, is $3.24 billion plus any amounts that would be available through reinsurance or indemnity from an outside source. The ANI cap is a

$300 million shared industry aggregate.

For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

All retrospective assessments, whether generated for liability, property or replacement power may be subject to applicable state premium taxes.

10. QUARTERLY FINANCIAL INFORMATION (Unaudited)

Summarized quarterly financial data for 2002 and 2001 are as follows:

Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock (inmillions)

March2002 $ 802 $191 $ 72 June 2002 924 256 116 September 2002 1,119 393 201 December 2002 865 182 72 March 2001 $ 850 $180 $ 70 June 2001 904 194 75 September 2001 1,061 362 180 December 2001 772 175 62 The Company's business is influenced by seasonal weather conditions.

39

SELECTED FINANCIAL AND OPERATING DATA 1998-2002 Alabama Power Company 2002 Annual Report 2002 2001 2000 1999 1998 Operating Revenues (In thousands) $3,710,533 $3,586,390 $3,667,461 $3,385,474 $3,386,373 Net Income after Dividends on Preferred Stock (in thousands) $461,355 $386,729 $419,916 $399,880 $377,223 Cash Dividends on Common Stock (in thousands) $431,000 $393,900 $417,100 $399,600 $367,100 Return on Average Common Equity (percent) 13.80 11.89 13.58 13.85 13.63 Total Assets (in thousands) $10,686,006 $10,433,460 $10,379,108 $9,648,704 $9,225,698 Gross Property Additions (in thousands) $634,559 $635,540 $870,581 $809,044 $610,132 Capitalization (in thousands):

Common stock equity $3,377,740 $3,310,877 $3,195,772 $2,988,863 $2,784,067 Preferred stock 247,512 317,512 317,512 317,512 317,512 Company obligated mandatorily redeemable preferred securities 300,000 347,000 347,000 347,000 297,000 Long-term debt 2,851,562 3,742,346 3,425,527 3,190,378 2,646,566 Total (excluding amounts due within one year) $6,776.814 $7,717,735 $7,285,811 $6.843.753 $6.045.145 Capitalization Ratios (percent):

Common stock equity 49.8 42.9 43.9 43.7 46.1 Preferred stock 3.7 4.1 4.4 4.6 5.3 Company obligated mandatorily redeemable preferred securities 4.4 4.5 4.8 5.1 4.9 Long-term debt 42.1 48.5 46.9 46.6 43.7 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+ AA- AA- AA-Preferred Stock -

Moody's Baal Baal a2 a2 a2 Standard and Poor's BBB+ BBB+ BBB+ A- 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 1,148,645 1,139,542 1,132,410 1,120,574 1,106,217 Commercial 203,017 196,617 193,106 188,368 182,738 Industrial 4,874 4,728 4,819 4,897 5,020 Other 789 751 745 735 733 Total 1.357,325 1,341.638 1,331_080 1,314.574 1.294 708 Employees (year-end): 6,715 6,706 6,871 6,792 6,631 40

SELECTED FINANCIAL AND OPERATING DATA 1998-2002 (continued)

Alabama Power Company 2002 Annual Report 2002 2001 2000 1999 1998 Operating Revenues (in thousands):

Residential $1,264,431 $1,138,499 $1,222,509 $1,145,646 $1,133,435 Commercial 882,669 829,760 854,695 807,098 779,169 Industrial 788,037 763,934 859,668 843,090 853,550 Other 16,080 15,480 15,835 15.283 14,523 _._ __

2,74,67 2,5,0 2,780,677 l ota retail 2,951,217 2,747,673 2,952,707 2,811,117 2,780,677 Sales for resale - non-affiliates 474,291 485,974 461,730 415,377 448,973 Sales for resale - affiliates 188,163 245,189 166,219 92,439 103,562 Total revenues from sales of electricity 3,613,671 3,478,836 3,580,656 3,318,933 3,333,212 Other revenues 96.862 107.554 86,805 66.541 VAIRIT 53,161 Total 3t.71 n 91:A VA rA 14on $3667-461 $.9385.474 Kilowatt-Hour Sales (in thousands):

L

---

47 V 6 -~

Residential 17,402,645 15,880,971 16,771,821 15,699,081 15,794,543 Commercial 13,362,631 12,798,711 12,988,728 12,314,085 11,904,509 Industrial 21,102,568 20,460,022 22,101,407 21,942,889 21,585,117 Other 205,346 198,102 205,827 201,149 196.647 Total retail 52,073,190 49,337,806 52,067,783 50,157,204 49,480,816 Sales for resale - non-affiliates 15,553,545 15,277,839 14,847,533 12,437,599 11,840,910 Sales for resale - affiliates 8,844,050 87843.094 5,369,474 5,031.781 5.976,099 Total Average Revenue Per Kilowatt-Hour (cents):

76.470.785 73.458.739

=6,,

72.284.790

_727-V .V^V.JKRA A7f Alf OS 67.297.82'5 Residential 7.27 7.17 7.29 7.30 7.18 Commercial 6.61 6.48 6.58 6.55 6.55 Industrial 3.73 3.73 3.89 3.84 3.95 Total retail 5.67 5.57 5.67 5.60 5.62 Sales for resale 2.72 3.03 3.11 2.91 3.10 Total sales 4.73 4.74 4.95 4.91 4.95 Residential Average Annual Kilowatt-Hour Use Per Customer 15,198 13,981 14,875 14,097 14,370 Residential Average Annual Revenue Per Customer $1,104.28 $1,002.30 $1,084.26 $1,028.76 $1,031.21 Plant Nameplate Capacity Ratings (year-end) (megawatts) 12,153 12,153 12,122 11,379 11,151 Maximum Peak-Hour Demand (megawatts):

Winter 9,423 9,300 9,478 8,863 7,757 Summer 10,910 10,241 11,019 10,739 10,329 Annual Load Factor (percent) 62.9 62.5 59.3 59.7 62.9 Plant Availability (percent):

Fossil-steam 85.8 87.1 89.4 80.4 85.6 NucleAr ar2m 0o'

-7 00 00.3

1) a.l r\

YI.u 0n^

au..

Source of Energy Supply (percent):

Coal 55.5 56.8 63.0 64.1 65.3 Nuclear 17.1 15.8 16.9 17.8 16.3 Hydro 5.1 5.1 2.9 4.7 6.9 Gas 11.6 10.7 4.9 1.1 1.5 Purchased power -

From non-affiliates 4.0 4.4 4.6 4.5 3.3 From affiliates 6.7 7.2 7.7 7.8 6.7 Total 100.0 100.0 100.0 100.0 100.0 41

DIRECTORS AND OFFICERS Alabama Power Company 2002 Annual Report Directors Whit Armstrong John C. Webb, IV Barbara J. Knight 3 President, Chairman and CEO, President, Wdeb Lumber Company, Inc. Vice President The Citizens Bank James W. Wright Ellen N. Lindemarn 4 David J. Cooper Chairman and CEO, Vice President, Human Resources President First Tuskegee Bank Penny M. Manuel 5 Coopemrl. Smith Corporation Vice President and Chief Information EL Allen Franklin Officers Officer Chairman, President and CEO, Gordon G. Martin Southern Company Charles D. McCrary Vice President, Southern Division Presdent and Chief Exnutive Oflicer R. Kent Henslee Managing Partner, Hensce, Rdbertsm, William B. Hutchins, m Donald W. Reese Stawn & Knowles, LL.C. Executive Vice President, Chief Vice President Financial Officer and Treasurer Julia H Segars 3 Carl 1. Jones, Jr.

Chairman, President and CEO, C. Alan Martin Vice President and Chief Information Regions Finaricial Corporation Executive Vice President Officer Patricia M. King Steve RI Spencer Julian H. Smith, Jr.

President and CEO, Executive Vice President Vice President King Motor Company, Inc. W. Ronald Smith Robert Holmes, Jr.

James K Lowder Senior Vice President Vice President, Eastern Division Chaioma, Cheryl A. Thompson Robin A. Hurst The Colonial Company Senior Vice President Vice President, Mobile Division Wallace D. Malone, Jr. Terry IL Waters Chairman and CEO, Rodney 0. Mundy Senior Vice President and Counsel Vice President, Western Division SouthTrust Corporation Michael L Scott William EL Zales, Jr.

Charles D. McCrary Vice President, Corporate Secretary Senior Vice President President and CEO, and Assistant Treasurer Alabama Power Company Jerry L Stewart Senior Vice President L. Wayne Boston Mayer Mitchell Assistant Secretary and President, MDI, LLC Art P. Beattle Assistant Treasurer Vice President and Comptroller Dr. Malcolm Portera' J. Randy DeRieux Chancellor, The University of Willard L Bowers Assistant Treasurer Alabama System Vice President Robert Cole Giddens Robert D. Powers Christopher T. Bell Assistant Comptroller President, The Eufaula Agency Vice President Ceila H. Shorts Andreas Rensaler Marsha S. Johnson Assistant Secretary President, Mcc smart G(mbh Vice President, Birmingham Division Cynthia H. Wilson' C. Dowd Ritter Gerald L Johnson Assistant Secretary Chairman, President and CEO, Vice President AmSouth Bancorporation Kay L Worley 7 William B Johnson Assistant Secretary James HI Sanford Vice President Chairman, HOME PlareFarms, Inc. J. Bruce Jones 'Elected 2/03 Dr. William F. Walker' Vice President 4Retired 6/02 3Elected 11/02 Presiciot, Auburn University Bobby J. Kerley 4 Elected 4/02 Vice Pasids, SouthADivision 5Resigned 10/02 William IL Keller 2 'Resigned 8/02 Vice President 'Appointed 9/02 42

CORPORATE INFORMAllON Aabama Powver Company 2002 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 except the Flexible Money Market connection with any sale or purchase of, or Class A Preferred Stock any solicitation of offers to buy or sell Southern Company Services, Inc.

securities. Stockholder Services P.O. Box 54250 Profile Atlanta, GA 30308-0250 The Company produces and delivers (800) 554-7626 electricity as an integrated utility to both retail and wholesale customers within the State of For the Flexible Money Market Class A Alabama and to other utilities in the Preferred Stock Southeast. The Company sells electricity to The Bank of New York 1.4 million customers within its service area 101 Barclay Street of approximately 45,000 square miles. In New York, NY 10286 2002, retail energy sales accounted for 68 percent of the Company's total sales of Form 10-K 76.5 billion kilowatt-hours. A copy of Form 10-K as filed with the Securities and Exchange Commission will The Company is a wholly owned be provided upon written request to the subsidiary of Southern Company, which is the office of the Corporate Secretary. For parent company of five integrated Southeast additional information, contact the office utilities. There is no established public of the Corporate Secretary at (205) 257-trading market for the Company's common 3385.

stock.

Alabama Power Company Trustee, Registrar and Interest Paying Agent 600 North 18kh Street All series of First Mortgage Bonds, Birmingham, AL 35291 Senior Notes and Trust Preferred Securities (205) 257-1000 IPMorgan Chase Bank www.alabamapower.com Institutional Trust Services 4 New York Plaza, 15" Floor Auditors New York, NY 10004 Deloitte & Touche LLP 417 North 20e Street Suite 1000 Birmingham, AL 35203 Legal Counsel Balch & Bingham LLP P.O. Box 306 Birmingham, AL 35201 43