ML021200003

Annual Submission Reports

ML021200003
Person / Time
Site:	Farley
Issue date:	04/25/2002
From:	Derieux J Alabama Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML021200003 (45)

Text

J. Randy DeRieux 600 North 18th Street Assistant Treasurer and Post Office Box 2641 General Manager- -Birminghadm, Alabama 35291-0030 Corporate Finance and Tel 205.257.2454 Planning Fax 205.257.1023 April 25, 2002 ALABAMA 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. 2001 Annual Report which includes financial statements for the calendar year 2001, together with the report on such statements by Arthur Andersen & Co.,

independent public accountants;

2. Unaudited Financial Statements for the quarter ended March 31, 2002;

3. Cash Flow Projections for the period January 1, 2002 through December 31, 2002, 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. L. M. Stinson, General Manager- Plant Farley U. S. Nuclear Regulatory Commission, Washington, D.C.

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

ALABAMA POWER COMPANY STATEMENT OF INCOME (THOUSANDS OF DOLLARS) 3 Months Ended 3/31/02 OPERATING REVENUES:

Revenues $ 802,249 OPERATING EXPENSES:

Operation -

Fuel 208,634 Purchased & interchange power, net 48,501 Other 121,724 Maintenance 76,814 Depreciation & amortization 98,275 Taxes other than income taxes 57,500 Federal and State income taxes 50,994 Total Operating Expenses 662,442 OPERATING INCOME 139,807 OTHER INCOME (EXPENSES):

Allowance for equity funds used during construction 3,007 Income from subsidiary 861 Other, net (5,811)

INCOME BEFORE INTEREST CHARGES 137,864 INTEREST CHARGES:

Interest on long-term debt 59,487 Allowance for debt funds used during construction (1,940)

Amortization of debt discount, premium and expenses, net 3,134 Other interest charges 987 Net Interest Charges 61,668 NET INCOME 76,196 DIVIDENDS ON PREFERRED STOCK 3,656 NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 72,540 This statement reflects the usual accounting practices of the Company on the basis of interim figures and is subject to audit and end of year adjustments.

H:\NFINCSTMT.xls

ALABAMA POWER COMPANY Internal Cash Flow for Joseph M. Farley Nuclear Power Station (Thousands of Dollars) 2001 2002 Actual Projections Net Income $ 402,253 $ 456,787 Less Dividends Paid 408,842 446,041 Retained Earnings (6,589) 10,746 Adjustments:

Depreciation and Amortization 437,490 473,820 Deferred Income Taxes and Investment Tax Credits (21,569) (3,730)

Allowance for Equity Used During Construction 7,092 11,913 Total Adjustments 423,013 482,003 Internal Cash Flow $ 416,424 $ 492,749 Average Quarterly Cash Flow $ 104,106 $ 123,187 Percentage Ownership in all Operating Nuclear Units:

Joseph M. Farley Units 1 and 2 100%

Maximum Total Contingent Liability $ 20,000 H:\NFCASHFL.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 I, II & III is subject to audit and end of year (Stated in Thousands of Dollars) adjustments.

At At March 31, March 31, ASSETS 2002 2001 UTILITY PLANT:

Plant in service, at original cost ........................................................................... 13,227,382 12,557,522 5,184,726 Less - Accumulated provision for depreciation and amortization ......................... 5,393,858 7,833,524 7,372,796 Nuclear fuel, at amortized cost .............................................................................. 77,108 87,923 Construction work in progress ................................................................................ 457,469 796,709 8,368,101 8,257,428 OTHER PROPERTY AND INVESTMENTS:

Equity investments in subsidiaries ........................................................................ 45,685 39,924 Nuclear decommissioning trusts ......................................................................... 311,639 304,840 Miscellaneous ....................................................................................................... 16,987 14,037 374,311 358,801 CURRENT ASSETS:

Cash....................................................................................................................... 32,193 10,731 Special Deposits .................................................................................................... 0 0 Temporary cash investments ............................................................................... 0 0 Investment securities .......................................................................................... 0 0 Receivables Customer accounts receivable ......................................................................... 316,267 485,161 Other accounts and notes receivable ................................................................ 61,464 40,458 Affiliated companies ......................................................................................... 60,593 43,798 Accumulated provision for uncollectible accounts .............................................. (5,715) (5,974)

Refundable income taxes ..................................................................................... 0 0 Fossil fuel stock, at average cost........................................................................... 94,927 92,397 Materials and supplies, at average cost .............................................................. 168,820 157,723 Allowance Inventory .......................................................................................... 21,101 15,973 Prepayments 0 0 Income taxes ..................................................................................................

Other ................................................................................................................... 84,614 65,503 21,224 0 Other current assets - SFAS 133 ............................................................................

Vacation pay deferred ........................................................................................... 32,324 31,711 887,812 937,481 Debt expense, being am ortized ........................................................................... 8,109 8,409 Debt redem ption expense, being am ortized ........................................................ 75,179 74,029 Nuclear decontam ination and decom m issioning fund ............................................ 21,015 24,588 Prepaid pension cost ............................................................................................ 344,044 282,302 Regulatory assets ............................................................................................... 309,178 344,826 Miscellaneous .................................................................................................... 109,088 104,345 866,613 838,499 TOTAL ASSETS....................................................................................................... $ 10,496,837 $ 10,392,209 4/17/02 +

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

At At March 31, March 31, CAPITALIZATION AND LIABILITIES 2002 2001 CAPITALIZATION:

Common stock equity ............................................................................................. $ 3,277,133 $ 3,164,833 Preferred stock ....................................................................................................... 317,512 317,512 Company obligated mandatorily redeemable preferred securities *....................... 347,000 347,000 Long-term debt ....................................................................................................... 3,742,657 3,425,059 7,684,302 7,254,404 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 ........................................ 904 846 Notes payable to banks .......................................................................................... 0 56,000 Commercial paper .................................................................................................. 96,833 390,339 Accounts payable Affiliated companies ............................................................................................ 94,260 105,944 Other .................................................................................................................. 91,668 93,295 Customer deposits ................................................................................................. 43,419 38,217 Taxes accrued Federal and state income .................................................................................... 158,090 111,108 Other ................................................................................................................... 38,293 37,329 Interest accrued ..................................................................................................... 61,162 46,109 Distributions accrued .............................................................................................. 5,816 79 Vacation pay accrued ............................................................................................. 32,324 31,711 Miscellaneous ......................................................................................................... 53,492 51,099 676,261 962,076 DEFERRED CREDITS AND OTHER LIABILITIES:

Accumulated deferred income taxes ...................................................................... 1,369,097 1,398,836 Accumulated deferred investment tax credits ........................................................ 235,491 246,516 Prepaid capacity revenues, net .............................................................................. 39,099 52,634 Regulatory liabilities ............................................................................................... 198,571 217,894 Nuclear decontamination and decommissioning fund ............................................ 16,812 20,490 Natural disaster reserve ......................................................................................... 12,981 18,790 Miscellaneous ......................................................................................................... 264,223 220,569 2,136,274 2,175,729 TOTAL CAPITALIZATION AND LIABILITIES .......................................................... $ 10,496,837 10,392,209

• Substantially all assets of Alabama Power Capital Trust I, II & IIIare 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 Item 8 of the 1998 Form 10-K for further details.

Corporate Accounting Department 4/17/02 +

ALABAMANa 4j POWER A SOUTHERN COMPANY 2001 ANNUAL REPORT www.alabamapower.com

CONTENTS Alabama Power Company 2001 Annual Report I

SUMMARY

2 MESSAGE FROM THE BOARD OF DIRECTORS 3 LETTER TO INVESTORS 4 MANAGEMENT'S REPORT 5 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS 6 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION 16 FINANCIAL STATEMENTS 23 NOTES TO FINANCIAL STATEMENTS 36 SELECTED FINANCIAL AND OPERATING DATA 38 DIRECTORS AND OFFICERS 39 CORPORATE INFORMATION

SUMMARY

Percent 2001 2000 Change Financial Highlights (in millions):

Operating revenues $3,587 $3,667 (2.2)

Operating expenses $2,676 $2,726 (1.8)

Net income after dividends on preferred stock $387 $420 (7.9)

Operating Data:

Kilowatt-hour sales (in millions):

Retail 49,338 52,068 (5.2)

Sales for resale - non-affiliates 15,278 14,848 2.9 Sales for resale - affiliates 8,843 5,369 64.7 Total 73,459 72,285 1.6 Customers served at year-end (in thousands) 1,342 1,331 0.8 Peak-hour demand (in megawatts) 10,241 11,019 (7.1)

Capitalization Ratios (percent):

Common stock equity 42.9 43.9 Preferred stock 4.1 4.4 Company obligated mandatorily redeemable preferred securities 4.5 4.8 Long-term debt 48.5 46.9 Return on Average Common Equity (percent) 11.89 13.58 I

ii MESSAGE FROM THE BOARD OF DIRECTORS Alabama Power Company 2001 Annual Report On April 26, 2001, the Board of Directors of Alabama Power Company elected Charles D. McCrary as President and Chief Operating Officer, officially signaling the beginning of a transition in leadership at the Company. With this action, Mr.

McCrary, former Southern Company Chief Production Officer and President of Southern Company Generation and Energy Marketing, became the tenth President in the 96-year history of Alabama Power Company. On this same date, Elmer B.

Harris, who had served as President and Chief Executive Officer since March 1989, assumed the role of Chairman and CEO.

As the brief transition period neared its completion, on October 25, 2001, Mr. McCrary relinquished the role of Chief Operating Officer and was elected Chief Executive Officer of the Company, while also retaining the title of President. Mr. Harris remained as Chairman of the Board until his retirement from the Company on January 11, 2002, following 44 years of service to Alabama Power Company and Southern Company.

BOARD OF DIRECTORS ALABAMA POWER COMPANY 2

LETTER TO INVESTORS Aiabama Power Company 2001 Annual Report The true strength of a company is demonstrated, not in ideal times, but during times of challenge.

In 2001, Alabama Power Company showed its strength and stability, fulfilling its commitments to our customers, employees, shareholders and communities, even as the national economy faltered.

Even though a slowing economy and mild summer temperatures resulted in decreased usage of electricity in 2001 and thus decreased revenues, our shareholders did not suffer. The operating efficiencies implemented to meet our goals in 2001 should result in an even more robust performance in the future, as the national economy improves.

We also met the expectations of our customers in 2001 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 ranked in the top quartile in customer service in 2001, and our customers continued to pay prices that are well below the national average.

Alabama Power Company is planning ahead to ensure that our customers continue to enjoy affordable, reliable service. We continue to use a diverse fuel mix -- coal, hydro, oil, natural gas and nuclear -- to run our plants. The diverse fuel mix gives us the flexibility to keep our costs down when fuel costs rise. Furthermore, we are continuing to make arrangements for increased generating capacity in order to meet customer demand in the future.

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 dedicated to making every kilowatt-hour of electricity we produce cleaner, on average, than the one before. We continue to be a leader in developing technology to protect the environment. In 2001, Alabama Power Company successfully tested groundbreaking mercury-reduction technology at our Plant Gaston. We also tested switchgrass as a fuel at Plant Gadsden and our facility in Wilsonville continues to develop new ways to burn coal cleaner.

No matter how much the utility business may change, we believe the key to success will always be the same: Make every decision with the best interest of your customer, shareholder and employees in mind. Take every action based upon the highest standards of ethics and integrity.

Our business may change, yet these beliefs are constant.

Solid values, a strong commitment to our customers and sound business strategies allowed us to successfully face the challenges of 2001 and they allow us to move into the future in a position of strength.

Sincerely, Charles D. McCrary President and Chief Executive Officer March 22, 2002 3

MANAGEMENT'S REPORT Alabama Power Company 2001 Annual Report The management of Alabama Power Company has The audit committee of the board of directors, prepared -- and is responsible for -- the financial composed of four independent directors, provides a broad statements and related information included in this report. overview of management's financial reporting and control These statements were prepared in accordance with functions. Periodically, this committee meets with accounting principles generally accepted in the United management, the internal auditors and the independent States and necessarily include amounts that are based on public accountants to ensure that these groups are the best estimates and judgments of management. fulfilling their obligations and to discuss auditing, internal Financial information throughout this annual report is controls, and financial reporting matters. The internal consistent with the financial statements. auditors and independent public accountants have access to the members of the audit committee at any time.

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

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

is evaluated on an ongoing basis by the Company's 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, III President Executive Vice President, and Chief Executive Officer Chief Financial Officer, and Treasurer February 13, 2002 4

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Alabama Power Company: the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles We have audited the accompanying balance sheets and used and significant estimates made by management, as statements of capitalization of Alabama Power Company well as evaluating the overall financial statement (an Alabama corporation and a wholly owned subsidiary presentation. We believe that our audits provide a of Southern Company) as of December 31, 2001 and reasonable basis for our opinion.

2000, and the related statements of income, common stockholder's equity, and cash flows for each of the three In our opinion, the financial statements (pages 16-34) years in the period ended December 31, 2001. These referred to above present fairly, in all material respects, financial statements are the responsibility of the the financial position of Alabama Power Company as of Company's management. Our responsibility is to express December 31, 2001 and 2000, and the results of its an opinion on these financial statements based on our operations and its cash flows for each of the three years in audits. the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United We conducted our audits in accordance with auditing States.

standards generally accepted in the United States. Those standards require that we plan and perform the audit to As explained in Note 1 to the financial statements, obtain reasonable assurance about whether the financial effective January 1, 2001, Alabama Power Company statements are free of material misstatement. An audit changed its method of accounting for derivative includes examining, on a test basis, evidence supporting instruments and hedging activities.

Birmingham, Alabama February 13, 2002 5

I I MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 2001 Annual Report RESULTS OF OPERATIONS Revenues Earnings Operating revenues for 2001 were $3.6 billion, reflecting a decrease from 2000. The following table summarizes the Alabama Power Company's 2001 net income after principal factors that have affected operating revenues for dividends on preferred stock was $387 million, the past two years:

representing a $33 million (7.9 percent) decrease from the prior year. This decline is primarily attributable to a Increase (Decrease) decrease in territorial energy sales as a result of an Amount From Prior Year economic downturn and milder temperatures. 2001 2001 2000 (in thousands)

In 2000 earnings were $420 million, representing a 5 Retail -

percent increase from the prior year. This improvement Base revenues $2,033,814 $ (75,125) $ 80,264 was primarily attributable to an increase in territorial sales Fuel cost recovery partially offset by increased non-fuel operating expenses. and other 713,859 (129,909) 61,326 Total retail 2,747,673 (205,034) 141,590 The return on average common equity for 2001 was Sales for resale -

11.89 percent compared to 13.58 percent in 2000 and Non-affiliates 485,974 24,244 46,353 13.85 percent in 1999. Affiliates 245,189 78,970 73,780 Total sales for resale 731,163 103,214 120,133 Other operating revenues 107,554 20,749 20,264 Total operating revenues $3,586,390 $ (81,071) $281,987 Percent change (2.21)% 8.33%

Retail revenues of $2.7 billion in 2001 decreased

$205 million (6.9 percent) from the prior year, compared with an increase of $142 million (5 percent) in 2000. The primary contributors to the decrease in revenues in 2001 were the negative impact of milder temperatures on energy sales, an economic downturn in the Company's service territory, and a decrease in fuel revenues. Fuel revenues have no effect on net income because they represent the recording of revenues to offset fuel expenses. Fuel rates billed to customers are designed to fully recover fluctuating fuel costs over a period of time.

Lower natural gas prices, an increased fuel rate, and increased hydro production combined with decreased costs of purchased power have resulted in a $154 million (65 percent) reduction in under-recovered fuel costs at December 31, 2001 compared with the prior year. The Company expects to continue to reduce the balance of $83 million during 2002.

6

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report Other operating revenues in 2001 increased $21 million Kilowatt-hour (KWH) sales for 2001 and the percent (23.9 percent) over 2000. This increase is primarily change by year were as follows:

attributed to increased steam sales in conjunction with the operation of the Company's co-generation facilities, fuel KWH Percent Change sales, and rent from electric property. Since co-generation 2001 2001 2000 steam revenues are generally offset by fuel expenses, (millions) these revenues did not have a significant impact on earnings. Residential 15,881 (5.3)% 6.8%

Commercial 12,799 (1.5) 5.5 The $20 million (30.5 percent) increase in other Industrial 20,460 (7.4) 0.7 operating revenues in 2000 as compared to 1999 was due Other 198 (3.9) 2.3 primarily to an increase in steam sales in conjunction with Total retail 49,338 (5.2) 3.8 the operation of the Company's co-generation facilities. Sales for resale Non-affiliates 15,278 2.9 19.4 Energy sales for resale outside the service area are Affiliates 8,843 64.7 6.7 predominantly unit power sales under long-term contracts Total 73,459 1.6 6.9 to Florida utilities. Economy energy and energy sold under short-term contracts are also sold for resale outside Retail energy sales in 2001 decreased by 5.2 percent the service area. Revenues from long-term power due to milder temperatures and an economic downturn in contracts have both a capacity and energy component. the Company's service area. This was offset by an Capacity revenues reflect the recovery of fixed costs and a increase in sales for resale to affiliates. Increased return on investment under the contracts. Energy is operation of the Company's combined cycle facilities due generally sold at variable cost. These capacity and energy to lower natural gas prices and an increase in the components of the unit power contracts were as follows: Company's combined cycle capacity contributed to the increase in sales for resale.

2001 2000 1999 (in millions)

The increase in 2000 retail energy sales was primarily due to the strength of business and economic conditions in Capacity $125 $127 $122 the Company's service area. Residential energy sales Energy 134 128 112 experienced a 6.8 percent increase over the prior year Total $259 $255 $234 primarily as a result of warmer summer temperatures and cold winter weather conditions compared to 1999.

Capacity revenues from non-affiliates were relatively unchanged in 2001 compared to the prior two years. Expenses There are no scheduled declines in capacity until the termination of the contracts in 2010. In 2001 total operating expenses of $2.7 billion were down

$50 million or 1.8 percent compared with 2000. This Revenues from sales to affiliated companies within the decline is mainly due to an $18 million net decrease in fuel Southern electric system, as well as purchases of energy, and purchased power costs and a $56 million decrease in will vary from year to year depending on demand and the non-production operation and maintenance expenses, offset availability and cost of generating resources at each by a $19 million increase in depreciation. Fuel expenses, company. These transactions did not have a significant including purchased power, are offset by fuel revenues and impact on earnings. have no effect on net income.

In 2000 total operating expenses of $2.7 billion were up

$235 million or 9.4 percent compared with the prior year.

This increase was mainly due to a $183 million increase in fuel and purchased power costs, accompanied by a $23 million increase in maintenance expenses.

7

1 1.

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report Fuel costs constitute the single largest expense for the 8.4 percent increase in maintenance expense in 2000 as Company. The mix of fuel sources for generation of compared to 1999 is primarily attributable to an increase electricity is determined primarily by system load, the unit in the maintenance of overhead distribution lines and cost of fuel consumed, and the availability of hydro and additional accruals to partially replenish the natural nuclear generating units. The amount and sources of disaster reserve.

generation and the average cost of fuel per net KWH generated were as follows: Depreciation and amortization expense increased 5.2 percent in 2001 and 4.9 percent in 2000. These increases 2001 2000 1999 reflect additions to property, plant, and equipment.

Total generation (billions of KWHs) 68 65 63 Total net interest and other charges increased $10 Sources of generation million (4.0 percent) in 2001. The increase reflected a (percent) - decrease in Allowance for Funds Used During Coal 64 72 72 Construction (AFUDC) resulting in a smaller credit to Nuclear 18 19 20 interest expense than was recorded in 2000. Total net Hydro 6 3 5 interest and other charges increased $19 million (7.9 Oil & Gas 12 6 3 percent) in 2000 primarily from an increase in interest on Average cost of fuel per net long-term debt offset by an increase in AFUDC, which KWH generated resulted in a larger credit to interest expense.

(cents) -- 1.56 1.54 1.44 Effects of Inflation In 2001, total fuel and purchased power costs of $1.3 billion decreased $18 million (1.4 percent), while total The Company is subject to rate regulation and income tax energy sales increased 1,174 million kilowatt hours (1.6 laws that are based on the recovery of historical costs.

percent) compared with the amounts recorded in 2000. Therefore, inflation creates an economic loss because the Fuel and purchased power costs in 2000 increased $183 Company is recovering its costs of investments in dollars million (16 percent) compared to 1999. that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to Purchased power consists of purchases from affiliates have an adverse effect on the Company because of the in the Southern electric system and non-affiliated large investment in utility plant with long economic lives.

companies. Purchased power transactions among the Conventional accounting for historical cost does not Company and its affiliates will vary from period to period recognize this economic loss nor the partially offsetting depending on demand, the availability, and the variable gain that arises through financing facilities with fixed production cost of generating resources at each company. money obligations, such as long-term debt and preferred During 2001 purchased power transactions from non securities. Any recognition of inflation by regulatory affiliates decreased $20 million (12 percent) due to the authorities is reflected in the rate of return allowed.

addition in May 2001 of a combined cycle unit and an 82 percent increase in hydro generation compared to the Future Earnings Potential previous year. The hydro generation increase occurred from greater stream flows in 2001 compared to the General previous year.

The results of continuing operations for the past three The 6 percent decrease in other operation expense in years are not necessarily indicative of future earnings 2001 as compared to 2000 is primarily due to a decrease in potential. The level of future earnings depends on administrative and general expenses, which can be mainly numerous factors. The major factor is the ability of the attributed to insurance refunds. Company to achieve energy sales growth while containing cost in a more competitive environment. Growth in The 8.5 percent decrease in maintenance expense in energy sales is subject to a number of factors. These 2001 as compared to 2000 is primarily due to a decrease factors include weather, competition, new short- and long in power production expense as a result of timing of term contracts with neighboring utilities, energy maintenance for steam power generation facilities. The conservation practiced by customers, the elasticity of 8

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report demand, and the rate of economic growth in the for delivery beginning in 2004. Rate CNP will adjust Company's service area. retail rates when the contracted capacity delivery begins.

Assuming normal weather, sales to retail customers are In accordance with Financial Accounting Standards projected to grow approximately 2.4 percent annually on Board (FASB) Statement No. 87, Employers' Accounting average during 2002 through 2006. for Pensions, the Company recorded non-cash income of approximately $57 million in 2001. Future pension The Company currently operates as a vertically income is dependent on several factors including trust integrated utility providing electricity to customers within earnings and changes to the plan. For the Company, its traditional service area located in the state of Alabama. pension income is a component of the regulated rates and Prices for electricity provided by the Company to retail does not have a significant effect on net income. For more customers are set by the Alabama Public Service information see Note 2 to the financial statements.

Commission (APSC) under cost-based regulatory principles. The Company is involved in various matters being litigated. See Note 3 to the financial statements for Rates to retail customers served by the Company are information regarding material issues that could possibly regulated by the APSC. Rates for the Company can be affect future earnings.

adjusted periodically within certain limitations based on Compliance costs related to current and future earned retail rate of return compared with an allowed environmental laws, regulations, and litigation could return. The rates also provide for adjustments to recognize affect earnings if such costs are not fully recovered. The the placing of new generating facilities into retail service Clean Air Act and other important environmental items under Rate CNP (Certificated New Plant). Effective July are discussed later under "Environmental Matters."

2001, the Company's retail rates were adjusted by 0.6 percent under Rate CNP to recover costs for Plant Barry Industry Restructuring Unit 7, which was placed into commercial operation on May 1, 2001. Most recently, a 2 percent increase in retail The electric utility industry in the United States is rates was effective in October 2001, in accordance with the continuing to evolve as a result of regulatory and Rate Stabilization Equalization plan. See Note 3 to the competitive factors. Among the primary agents of change financial statements under "Retail Rate Adjustment has been the Energy Policy Act of 1992 (Energy Act).

Procedures" for additional information.

The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order In December 1995, the APSC issued an order to sell electricity to other utilities. This enhances the authorizing the Company to reduce balance sheet items incentive for IPPs to build cogeneration plants for a

-- such as plant and deferred charges -- at any time the utility's large industrial and/or commercial customers and Company's actual base rate revenues exceed the budgeted sell excess energy generation to other utilities. Also, revenues.

electricity sales for resale rates are affected by wholesale transmission access and numerous potential new energy In April 2000, the APSC approved an amendment to suppliers, including power marketers and brokers.

the Company's existing rate structure to provide for the recovery of retail costs associated with certified purchased Although the Energy Act does not permit retail power agreements. In November 2000 the APSC certified customer access, it was a major catalyst for the recent a seven-year purchased power agreement pertaining to restructuring and consolidation taking place within the 615 megawatts of the wholesale generating facilities, utility industry. Numerous federal and state initiatives are which were sold to Southern Power in June 2001 and are in varying stages to promote wholesale and retail under construction in Autaugaville, Alabama. All of the competition. Among other things these initiatives allow 615 megawatts will be delivered beginning in 2003. In customers to choose their electricity provider. Some addition the APSC certified a seven-year purchased power states have approved initiatives that result in a separation agreement with a third party for approximately 630 of the ownership and/or operation of generating facilities megawatts; one half of the power will be delivered from the ownership and/or operation of transmission and beginning in 2003 while the remaining half is scheduled distribution facilities. While various restructuring and 9

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report competition initiatives have been discussed in Alabama, sponsors to develop the SeTrans RTO. The creation of none have been enacted. In October 2000 the APSC SeTrans is not expected to have a material impact on the completed a two-year study of electric industry Company's financial statements. The outcome of this restructuring, concluding that (i) restructuring of the matter cannot now be determined.

electric utility industry in Alabama was not in the public interest and (ii) the APSC itself would not mandate retail Accounting Standards competition or electric industry restructuring without enabling state legislation. Electric utility restructuring CriticalPolicy would require numerous issues to be resolved, including significant ones relating to recovery of any stranded The Company's significant accounting policies are investments, full cost recovery of energy produced, and described in Note 1 to the financial statements. The other issues related to the energy crisis that occurred in Company's most critical accounting policy involves rate California. As a result of that crisis, many states have regulation. The Company is subject to the provisions of either discontinued or delayed implementation of FASB Statement No. 71, Accounting for the Effects of initiatives involving retail deregulation. Certain Types of Regulation. In the event that a portion of the Company's operation is no longer subject to these Continuing to be a low-cost producer could provide provisions, the Company would be required to write off opportunities to increase market share and profitability in related regulatory assets and liabilities that are not markets that evolve with changing regulation. specifically recoverable and determine if any other assets Conversely, if the Company does not remain a low-cost have been impaired. See Note 1 to the financial producer and provide quality service, then energy sales statements under "Regulatory Assets and Liabilities" for growth could be limited, and this could significantly erode additional information.

earnings.

New Accounting Standards The Company had 1,230 megawatts of wholesale generating facilities under construction in 2001 at Effective January 2001, the Company adopted FASB Autaugaville, Alabama. In June 2001 the Company sold Statement No. 133, Accounting for Derivative Instruments this project to Southern Power Company, a new Southern and Hedging Activities, as amended. Statement No. 133 Company subsidiary formed in 2001 to construct, own, establishes accounting and reporting standards for and manage wholesale generating assets in the Southeast. derivative instruments and for hedging activities. This The Company has entered into a purchased power statement requires that certain derivative instruments be agreement with Southern Power, through May 2010, for recorded in the balance sheet as either an asset or liability half of the capacity of these generating facilities. measured at fair value, and that changes in the fair value be recognized currently in earnings unless specific hedge In December 1999, the Federal Energy Regulatory accounting criteria are met. See Note 1 to the financial Commission (FERC) issued its final ruling on Regiopal statements under "Financial Instruments" for additional Transmission Organizations (RTOs). The order information. The impact on net income in 2001 was not encouraged utilities owning transmission systems to form material. An additional interpretation of Statement No.

RTOs on a voluntary basis. Southern Company and its 133 will result in a change - effective April 1, 2002 - in operating companies, including the Company, have accounting for certain contracts related to fuel supplies submitted a series of status reports informing the FERC of that contain quantity options. These contracts will be progress toward the development of a Southeastern RTO. accounted for as derivatives and marked to market.

In these status reports, Southern Company explained that However, due to the existence of the Company's cost it is developing a for-profit RTO known as SeTrans with a based fuel recovery clause, this change is not expected to number of non-jurisdictional cooperative and public have a material impact on net income.

power entities. Recently, Entergy Corporation and Cleco Power joined the SeTrans development process. In In June 2001 the FASB issued Statement No. 142, January 2002 the sponsors of SeTrans held a public Goodwill and Other Intangible Assets, which establishes meeting to form a Stakeholder Advisory Committee, new accounting and reporting standards for acquired which will participate in the development of the RTO. goodwill and other intangible assets and supersedes Southern Company continues to work with the other Accounting Principles Board Opinion No. 17. Statement 10

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report No. 142 addresses how intangible assets that are acquired Credit Rating Risk individually or with a group of other assets (but not those acquired in a business combination) should be accounted The Company does not have any credit agreements that for upon acquisition and on an ongoing basis. Goodwill would require material changes in payment schedules or and intangible assets that have indefinite useful lives will terminations as a result of a credit rating downgrade.

not be amortized but rather will be tested at least annually for impairment. Intangible assets that have finite useful Exposure to Market Risk lives will continue to be amortized over their useful lives, which are no longer limited to 40 years. The Company Due to cost-based rate regulation, the Company has adopted Statement No. 142 in January 2002 with no limited exposure to market volatility in interest rates, material impact on the financial statements. commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity Also in June 2001, the FASB issued Statement No. 143, prices, the Company enters into fixed price contracts for Asset Retirement Obligations, which establishes new the purchase and sale of electricity through the wholesale accounting and reporting standards for legal obligations electricity market. Realized gains and losses are associated with retiring assets, including decommissioning recognized in the income statement as incurred. At of nuclear plants. The liability for an asset's future December 31, 2001, exposure from these activities was retirement must be recorded in the period in which the not material to the Company's financial position, results liability is incurred. The cost must be capitalized as part of operations, or cash flows. Fair value of changes in of the related long-lived asset and depreciated over the energy trading contracts and year-end valuations are as asset's useful life. Changes in the liability resulting from follows:

the passage of time will be recognized as operating Changes expenses. Statement No. 143 must be adopted by January During the Year 1, 2003. The Company has not yet quantified the impact Fair Value (in thousands) of adopting Statement No. 143 on its financial statements.

Contracts beginning of year $ 567 FINANCIAL CONDITION Contracts realized or settled (509)

New contracts at inception Overview Changes in valuation techniques Current period changes 156 In 2001, despite significant cost control measures, the Contracts end of year $ 214 Company's earnings were adversely impacted by an economic downturn and milder temperatures. However, Source of Year-End over the last several years the Company's financial Valuation Prices condition has remained stable as a result of growth in Total Maturity retail energy sales and cost control measures combined Fair Value Year 1 1-3 Years with significant lowering of the cost of capital, achieved (in thousands) through the refinancing and/or redemption of higher-cost Actively quoted $(4,840) $(4,801) $(39) long-term debt and preferred stock. External sources 5,054 5,054 Models and other The Company had gross property additions of $636 methods -

million in 2001. The majority of funds needed for gross 214 $ 253 $(39)

Contracts end of Year $

property additions for the last several years have been provided from operating activities, principally from Also, based on the Company's overall variable rate earnings and non-cash charges to income such as long-term debt exposure at December 31, 2001, a near depreciation and deferred income taxes. The Statements term 100 basis point change in interest rates would not of Cash Flows provide additional details.

materially affect the financial statements.

For additional information, see Note 1 to the financial statements under "Financial Instruments."

11

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report In October 2001, the APSC approved a revision to the These capital requirements, lease obligations, and Company's Rate ECR (Energy Cost Recovery) allowing purchase commitments - discussed in notes 4 and 8 to the the recovery of specific costs associated with the sales of financial statements - are as follows:

natural gas that become necessary due to operating considerations at its electric generating facilities. This 2002 2003 2004 revision also includes the cost of financial tools used for (in millions) hedging market price risk up to 75 percent of the budgeted Bonds annual amount of natural gas purchases. The Company First mortgage $ 4.5 $ - $

may not engage in natural gas hedging activities that Pollution control -

extend beyond a rolling 42-month window. Senior Notes - 573.2 525.0 Leases Capital 0.9 0.9 1.0 Capital Structure Operating 27.9 26.5 25.5 Purchase commitments The Company's ratio of common equity to total Fuel 795.0 794.0 801.0 capitalization -- including short-term debt -- was 42.8 Purchased Power - 53.0 83.0 percent in 2001, 42.2 percent in 2000, and 42.4 percent in 1999. At the beginning of 2002, the Company had not used In August 2001, the Company issued $442 million of any of its available credit arrangements. Credit senior notes, the proceeds of which were used to redeem arrangements are as follows:

the $131.5 million outstanding principal of its First Expires Mortgage Bonds, 9% Series due December 1, 2004 and Total Unused 2002 2003 & Beyond (in millions) for other corporate purposes, including the repayment of a

$964 $964 $574 $390 portion of its short-term indebtedness.

Capital Requirements Environmental Matters In November 1990, the Clean Air Act Amendments of Capital expenditures are estimated to be $671 million for 1990 (Clean Air Act) were signed into law. Title IV of 2002, $592 million for 2003, and $673 million for 2004.

the Clean Air Act -- the acid rain compliance provision of See Note 4 to the financial statements for additional the law -- significantly affected Southern Company.

details.

Reductions in sulfur dioxide and nitrogen oxide emissions Actual construction costs may vary from estimates from fossil-fired generating plants were required in two because of changes in such factors as: business phases. Phase I compliance began in 1995.

conditions; environmental regulations; nuclear plant regulations; load projections; the cost and efficiency of Southern Company achieved Phase I compliance at its construction labor, equipment, and materials; and the cost affected plants by primarily switching to low-sulfur coal of capital. In addition there can be no assurance that costs and with some equipment upgrades. Construction related to capital expenditures will be fully recovered. expenditures for Phase I nitrogen oxide and sulfur dioxide emissions compliance totaled approximately $25 million Other Capital Requirements for the Company.

In addition to the funds required for the Company's Phase II sulfur dioxide compliance was required in construction program, approximately $1.1 billion will be 2000. The Company used emission allowances and fuel required by the end of 2004 for present sinking fund switching to comply with Phase II requirements. Also, requirements and maturities of long-term debt. The equipment to control nitrogen oxide emissions was Company plans to continue, when economically feasible, installed on additional system fossil-fired units as to retire higher cost debt and preferred stock and replace necessary to meet Phase II limits. Compliance with Phase these obligations with lower-cost capital if market II increased the Company's total construction conditions permit. expenditures through 2000 by $63 million.

12

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report In December 2000, the Alabama Department of are similar to those brought against and issued to several Environmental Management adopted revisions to the State other electric utilities. The complaint and notice of Implementation Plan for meeting the one-hour ozone violation allege that the Company had failed to secure standard. New emission limits to comply with these necessary permits or install additional pollution control requirements must be implemented in May 2003. Two equipment when performing maintenance and generating plants will be affected in the Birmingham area. construction at coal burning plants constructed or under Capital expenditures for compliance with these new rules construction prior to 1978. In August 2000, the U.S.

are currently estimated at approximately $240 million, of District Court in Georgia granted the Company's motion which $170 million remains to be spent. to dismiss for lack of jurisdiction in Georgia. On January 12, 2001, the EPA re-filed its claims against the Company In July 1997, the Environmental Protection Agency in federal district court in Birmingham, Alabama. The (EPA) revised the national ambient air quality standards case has been stayed since the spring of 2001, pending a for ozone and particulate matter. This revision made the ruling by the U.S. Court of Appeals for the Eleventh standards significantly more stringent. In the subsequent Circuit in the appeal of a very similar New Source Review litigation of these standards, the U. S. Supreme Court enforcement action against the Tennessee Valley found the EPA's implementation program for the new Authority (TVA). The TVA case involves many of the ozone standard unlawful and remanded it to the EPA. In same legal issues raised by the actions against the addition, the Federal District of Columbia Circuit Court of Company. Because the outcome of the TVA case could Appeals is considering other legal challenges to these have a significant adverse impact on the Company, it is standards. A court decision is expected in the spring of party to that case as well. The U.S. District Court in 2002. If the standards are eventually upheld, Alabama has indicated that it will revisit the issue of a implementation could be required by 2007 to 2010. continued stay in April 2002.

In September 1998, the EPA issued nitrogen oxide The Company believes that it complied with reduction rules to the states for implementation. The final applicable laws and the EPA's regulations and rule affects 21 states, including Alabama. Compliance is interpretations in effect at the time the work in question required by May 31, 2004 for most states including took place. However, an adverse outcome in this matter Alabama. Capital expenditures for compliance with these could require substantial capital expenditures that cannot new rules are currently estimated at approximately $175 be determined at this time and possibly require payment of million. substantial penalties. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each A significant portion of costs related to the acid rain generating unit. Prior to January 30, 1997, the penalty and ozone non-attainment provisions of the Clean Air Act was $25,000 per day. This could affect future results of is expected to be recovered through existing ratemaking operations, cash flows, and possibly financial condition provisions. However, there can be no assurance that all unless such costs can be recovered through regulated Clean Air Act costs will be recovered. rates.

On November 3, 1999, the EPA brought a civil action In December 2000, having completed its utility studies against the Company in the U.S. District Court in Atlanta, for mercury and other hazardous air pollutants (HAPS),

Georgia. The complaint alleges violations of the New the EPA issued a determination that an emission control Source Review provisions of the Clean Air Act with program for mercury, and perhaps other HAPS is respect to coal-fired generating facilities at the Company's warranted. The program is being developed under the Plants Miller, Barry, and Gorgas. The civil action Maximum Achievable Control Technology provisions of requests penalties and injunctive relief, including an order the Clean Air Act, and the regulations are scheduled to be requiring the installation of the best available control finalized by the end of 2004 with implementation to take technology at the affected units. The EPA concurrently place around 2007. In January 2001, the EPA proposed issued to the Company a notice of violation relating to guidance for the determination of Best Available Retrofit these specific facilities, as well as Plants Greene County Technology (BART) emission controls under the Regional and Gaston. In early 2000 the EPA filed a motion to Haze Regulations. Installation of BART controls is amend its complaint to add the violations alleged in its expected to take place around 2010. Litigation of the notice of violation. The complaint and notice of violation Regional Haze Regulations, including the BART 13

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report provisions, is ongoing in the Federal District of Columbia these laws could affect many areas of the Company's Circuit Court of Appeals. A court decision is expected in operations. The full impact of any such changes cannot be mid-2002. determined at this time.

Implementation of the final state rules for these Compliance with possible additional legislation related initiatives could require substantial further reductions in to global climate change, and other environmental and nitrogen oxide and sulfur dioxide and reductions in health concerns could significantly affect the Company.

mercury and other HAPS emissions from fossil-fired The impact of new legislation -- if any -- will depend on generating facilities and other industries in these states. the subsequent development and implementation of Additional compliance costs and capital expenditures applicable regulations.

resulting from the implementation of these rules and standards cannot be determined until the results of legal Sources of Capital challenges are known, and the states have adopted their final rules. The Company plans to obtain the funds required for construction and other purposes from sources similar to In October 1997, the EPA issued regulations setting those used in the past, which were primarily from internal forth requirements for Compliance Assurance Monitoring sources. However, the type and timing of any financings (CAM) in its state and federal operating permit programs. - if needed - will depend on market conditions and These regulations were amended by the EPA in March regulatory approval. In recent years financings primarily 2001 in response to a court order resolving challenges to have utilized unsecured debt and trust preferred securities.

the rules brought by environmental groups and industry.

Generally, this rule affects the operation and maintenance The Company may also meet short-term cash needs of electrostatic precipitators and could involve significant through a Southern Company subsidiary organized to additional ongoing expense. issue and sell commercial paper at the request and for the benefit of the Company and the other Southern Company The EPA and state environmental regulatory agencies operating companies. At December 31, 2001, the are reviewing and evaluating various other matters Company had outstanding $10 million of commercial including: control strategies to reduce regional haze; paper.

limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal As required by the Nuclear Regulatory Commission requirements. The impact of any new standards will and as ordered by the APSC, the Company has established depend on the development and implementation of external trust funds for nuclear decommissioning costs. In applicable regulations. 1994 the Company also established an external trust fund for postretirement benefits as ordered by the APSC. The The Company must comply with other environmental cumulative effect of funding these items over a long laws and regulations that cover the handling and disposal period will diminish internally funded capital and may of hazardous waste. Under these various laws and require capital from other sources. For additional regulations, the Company could incur substantial costs to information concerning nuclear decommissioning costs, clean up properties. The Company conducts studies to see Note 1 to the financial statements under "Depreciation determine the extent of any required cleanup and will and Nuclear Decommissioning."

recognize in the financial statements costs to clean up known sites. The Company has not incurred any Cautionary Statement Regarding Forward-Looking significant cleanup costs to date. Information Several major pieces of environmental legislation are This Annual Report includes forward-looking statements being considered for reauthorization or amendment by in addition to historical information. Forward-looking Congress. These include: the Clean Air Act; the Clean information includes, among other things, statements Water Act; the Comprehensive Environmental Response, concerning projected retail sales growth and scheduled Compensation, and Liability Act; the Resource completion of new generation. In some cases forward Conservation and Recovery Act; the Toxic Substances looking statements can be identified by terminology such Control Act; and the Endangered Species Act. Changes to as "may," "will," "should," "could," "expects," "plans,"

14

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2001 Annual Report "anticipates," "believes," "estimates," "predicts,"

"projects," "potential," "continue," or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental 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 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; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company; the effects of and changes in economic conditions in the areas in which the Company operates; the direct or indirect effects on the Company's business resulting from the terrorist incidents on September 11, 2001, or any similar such incidents or responses to such incidents; financial market conditions and the results of financing efforts; the timing and acceptance of the Company's new product and service offerings; the ability of the Company to obtain additional generating capacity at competitive prices; weather and other natural phenomena; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by the Company with the Securities and Exchange Commission.

15

STATEMENTS OF INCOME For the Years Ended December 31, 2001, 2000, and 1999 Alabama Power Company 2001 Annual Report 2001 2000 1999 (in thousands)

Operating Revenues:

Retail sales $2,747,673 $2,952,707 $2,811,117 Sales for resale -

Non-affiliates 485,974 461,730 415,377 Affiliates 245,189 166,219 92,439 Other revenues 107,554 86,805 66,541 Total operating revenues 3,586,390 3,667,461 3,385,474 Operating Expenses:

Operation -

Fuel 1,000,828 963,275 855,632 Purchased power -

Non-affiliates 144,991 164,881 93,204 Affiliates 147,967 184,014 180,563 Other 508,264 538,529 531,696 Maintenance 275,510 301,046 277,724 Depreciation and amortization 383,473 364,618 347,574 Taxes other than income taxes 214,665 209,673 204,645 Total operating expenses 2,675,698 2,726,036 2,491,038 Operating Income 910,692 941,425 894,436 Other Income (Expense):

Interest income, net 15,101 16,152 15,671 Equity in earnings of unconsolidated subsidiaries (Note 5) 4,494 3,156 2,650 Other, net (8,579) (2,226) (12,805)

Earnings Before Interest and Income Taxes 921,708 958,507 899,952 Interest and Other:

Interest expense, net 246,436 235,331 217,066 Distributions on preferred securities of subsidiary (Note 8) 24,775 25,549 24,662 Total interest and other, net 271,211 260,880 241,728 Earnings Before Income Taxes 650,497 697,627 658,224 Income taxes (Note 7) 248,597 261,555 241,880 Earnings Before Cumulative Effect of Accounting Change 401,900 436,072 416,344 Cumulative effect of accounting change less income taxes of $215 thousand 353 -

Net Income 402,253 436,072 416,344 Dividends on Preferred Stock 15,524 16,156 16,464 Net Income After Dividends on Preferred Stock $ 386,729 $ 419,916 $ 399,880 The accompanying notes are an integral part of these statements.

16

STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2001, 2000, and 1999 Alabama Power Company 2001 Annual Report 2001 2000 1999 (in thousands)

Operating Activities:

Net income $ 402,253 $ 436,072 $ 416,344 Adjustments to reconcile net income to net cash provided from operating activities -

Depreciation and amortization 437,490 412,998 403,332 Deferred income taxes and investment tax credits, net (21,569) 66,166 29,039 Other, net (122,651) (37,703) (12,661)

Changes in certain current assets and liabilities -

Receivables, net 88,325 (125,652) 33,509 Fossil fuel stock (38,663) 23,967 (1,344)

Materials and supplies (13,025) (10,662) (17,968)

Accounts payable (83,077) 107,702 (38,556)

Energy cost recovery, retail 154,320 (69,190) (97,869)

Other 34,503 23,336 5,930 Net cash provided from operating activities 837,906 827,034 719,756 Investing Activities:

Gross property additions (635,540) (870,581) (809,044)

Sales of property 102,068 Other (34,771) (49,414) (72,218)

Net cash used for investing activities (568,243) (919,995) (881,262)

Financing Activities:

Increase (decrease) in notes payable, net (271,347) 184,519 96,824 Proceeds -

Common stock 15,642 -

Other long-term debt 477,000 250,000 751,650 Preferred securities - 50,000 Capital contributions from parent company 107,313 204,371 204,347 Redemptions -

First mortgage bonds (138,991) (111,009) (470,000)

Other long-term debt (19,021) (5,987) (104,836)

Preferred stock - (50,000)

Payment of preferred stock dividends (14,942) (16,110) (15,788)

Payment of common stock dividends (393,900) (417,100) (399,600)

Other (9,908) (951) (15,864)

Net cash provided from (used for) financing activities (248,154) 87,733 46,733 Net Change in Cash and Cash Equivalents 21,509 (5,228) (114,773)

Cash and Cash Equivalents at Beginning of Period 14,247 19,475 134,248 Cash and Cash Equivalents at End of Period $ 35,756 $ 14,247 $ 19.475 Supplemental Cash Flow Information:

Cash paid during the period for -

Interest (net of amount capitalized) $246,316 $237,066 $229,305 Income taxes (net of refunds) 223,961 175,303 170,121 The accompanying notes are an integral part of these statements.

17

BALANCE SHEETS At December 31, 2001 and 2000 Alabama Power Company 2001 Annual Report Assets 2001 2000 (in thousands)

Current Assets:

Cash and cash equivalents $ 35,756 $ 14,247 Receivables -

Customer accounts receivable 281,985 337,870 Under-recovered retail fuel clause revenue 83,497 237,817 Other accounts and notes receivable 49,940 60,315 Affiliated companies 72,639 95,704 Accumulated provision for uncollectible accounts (5,237) (6,237)

Refundable income taxes Fossil fuel stock, at average cost 99,278 60,615 Materials and supplies, at average cost 191,324 178,299 Other 74,640 52,624 Total current assets 883,822 1,031,254 Property, Plant, and Equipment:

In service 13,159,560 12,431,575 Less accumulated provision for depreciation 5,309,557 5,107,822 7,850,003 7,323,753 Nuclear fuel, at amortized cost 88,777 94,050 Construction work in progress 357,906 744,974 Total property, plant, and equipment 8,296,686 8,162,777 Other Property and Investments:

Equity investments in unconsolidated subsidiaries (Note 5) 44,742 38,623 Nuclear decommissioning trusts 317,508 313,895 Other 12,244 13,612 Total other property and investments 374,494 366,130 Deferred Charges and Other Assets:

Deferred charges related to income taxes (Note 7) 334,830 345,550 Prepaid pension costs 314,100 255,256 Debt expense, being amortized 8,150 8,758 Premium on reacquired debt, being amortized 77,173 76,020 Department of Energy assessments 21,015 24,588 Other 108,031 95,772 Total deferred charges and other assets 863,299 805,944 Total Assets $10,418,301 $10,366,105 The accompanying notes are an integral part of these balance sheets.

18

BALANCE SHEETS At December 31, 2001 and 2000 Alabama Power Company 2001 Annual Report Liabilities and Stockholder's Equity 2001 2000 (in thousands)

Current Liabilities:

Securities due within one year (Note 8) $ 5,382 $ 844 Notes payable 9,996 281,343 Accounts payable -

Affiliated 98,268 124,534 Other 151,705 209,205 Customer deposits 42,124 36,814 Taxes accrued -

Income taxes 113,003 65,505 Other 19,023 19,471 Interest accrued 35,522 33,186 Vacation pay accrued 32,324 31,711 Other 93,589 97,743 Total current liabilities 600,936 900,356 Long-term debt (See accompanying statements) 3,742,346 3,425,527 Deferred Credits and Other Liabilities:

Accumulated deferred income taxes (Note 7) 1,387,661 1,401,424 Deferred credits related to income taxes (Note 7) 202,881 222,485 Accumulated deferred investment tax credits 238,225 249,280 Employee benefits provisions 99,919 71,813 Prepaid capacity revenues (Note 6) 40,730 58,377 Other 130,214 176,559 Total deferred credits and other liabilities 2099,630 2,179,938 Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding company junior subordinated notes (See accompanying statements) (Note 8) 347,000 347,000 Cumulative preferred stock (See accompanying statements) 317,512 317,512 Common stockholder's equity (See accompanying statements) 3,310,877 3,195,772 Total Liabilities and Stockholder's Eouity $10,418,301 $10,366,105 The accompanying notes are an integral part of these balance sheets.

19

i L STATEMENTS OF CAPITALIZATION At December 31, 2001 and 2000 Alabama Power Company 2001 Annual Report 2001 2000 2001 2000 (in thousands) (percentof total)

Long-Term Debt:

First mortgage bonds -

Maturity Interest Rates 2023 through 2024 7.30% - 7.75% $ 350,000 $ 488,991 Total first mortgage bonds 350,000 488,991 Senior notes -

Variable rate (2.28% at 1/1/02) due March 3, 2003 167,000 5.35% due November 15, 2003 156,200 156,200 7.850% due May 15, 2003 250,000 250,000 7.125% due August 15, 2004 250,000 250,000 4.875% due September 1, 2004 275,000 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 6.25% to 7.125% due 2010-2048 1J199,402 1,202,581 Total senior notes 2.882.602 2,443.781 Other long-term debt -

Pollution control revenue bonds -

Collateralized:

5.50% due 2024 24,400 24,400 Variable rates (1.61% to 1.95% at 1/1/02) due 2015-2017 89,800 89,800 Non-collateralized:

6.69% due 2021 50,000 65,000 Variable rates (1.75% to 2.05% at 1/1/02) due 2021-2031 395,940 360,940 Total other long-term debt (Note 8) 560,140 540,140 Capitalized lease obligations 3,323 4,165 Unamortized debt premium (discount), net (48,337) (50,706)

Total long-term debt (annual interest requirement -- $217.2 million) 3,747,728 3,426,371 Less amount due within one year 5,382 844 Long-term debt excluding amount due within one year $3,742,346 $3,425,527 48.5% 46.9%

20

STATEMENTS OF CAPITALIZATION (continued)

At December 31, 2001 and 2000 Alabama Power Company 2001 Annual Report 2001 2000 2001 2000 (in thousands) (percentof total)

Company Obligated Mandatorily Redeemable Preferred Securities: (Note 8)

$25 liquidation value -

7.375% $ 97,000 $ 97,000 7.60% 200,000 200,000 Auction rate (3.60% at 1/1/02) 50,000 50,000 Total (annual distribution requirement -- $24.2 million) 347,000 347,000 4.5 4.8 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 1/1/02 3.10% to 3.557% 70,000 70,000 Total (annual dividend requirement -- $15.2 million) 317,512 317,512 4.1 4.4 Common Stockholder's Equity:

Common stock, par value $40 per share -

Authorized - 6,000,000 shares Outstanding - 6,000,000 shares in 2001 and 5,608,955 shares in 2000 Par value 240,000 224,358 Paid-in capital 1,850,676 1,743,363 Premium on Preferred Stock 99 99 Retained earnings 1,220,102 1,227,952 Total common stockholder's equity 3,310,877 3,195,772 42.9 43.9 Total Capitalization $7,717,735 $7,285,811 100.0% 100.0%

The accompanying notes are an integral part of these statements.

21

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2001, 2000, and 1999 Alabama Power Company 2001 Annual Report Premium on Common Paid-In Preferred Retained Stock Capital Stock Earnings Total (in thousands)

Balance at January 1, 1999 $224,358 $1,334,645 $99 $1,224,965 $2,784,067 Net income after dividends on preferred stock - - - 399,880 399,880 Capital contributions from parent company 204,347 - - 204,347 Cash dividends on common stock - - - (399,600) (399,600)

Other - - 169 169 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 The accompanying notes are an integral part of these statements.

22

NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2001 Annual Report

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING Affiliate Transactions POLICIES The Company has an agreement with the system service General company under which the following services are rendered to the Company at cost: general and design engineering, Alabama Power Company (the Company) is a wholly purchasing, accounting and statistical, finance and owned subsidiary of Southern Company, which is the treasury, tax, information resources, marketing, auditing, parent company of five operating companies, a system insurance and pension administration, human resources, service company, Southern Communications Services systems and procedures, and other services with respect to (Southern LINC), Southern Nuclear Operating Company business and operations and power pool transactions.

(Southern Nuclear), Southern Power Company (Southern Costs for these services amounted to $183 million, $187 Power), and other direct and indirect subsidiaries. The million, and $218 million during 2001, 2000, and 1999, operating companies --Alabama Power Company, respectively.

Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and The Company also has an agreement with Southern Power Company -- provide electric service in four Nuclear to operate Plant Farley and provide the following southeastern states. Contracts among the operating nuclear-related services at cost: general executive and companies - related to jointly-owned generating facilities, advisory services; general operations, management and interconnecting transmission lines, and the exchange of technical services; administrative services including electric power-- are regulated by the Federal Energy procurement, accounting, statistical, and employee Regulatory Commission (FERC) and/or the Securities and relations; and other services with respect to business and Exchange Commission (SEC). The system service operations. Costs for these services amounted to $160 company provides, at cost, specialized services to million, $148 million, and $135 million during 2001, Southern Company and its subsidiary companies. 2000, and 1999, respectively.

Southern LINC provides digital wireless communications services to the operating companies and also markets these In 2001, the Company had under construction a 1,230 services to the public within the Southeast. Southern megawatt combined cycle facility in Autaugaville, Nuclear provides services to Southern Company's nuclear Alabama. In June 2001, the Company sold this project to power plants. Southern Power was established in 2001 to Southern Power Company, a new Southern Company construct, own, and manage Southern Company's affiliate formed in 2001 to construct, own, and manage competitive generation assets and sell electricity at wholesale generating assets in the Southeast.

market-based rates in the wholesale market.

Regulatory Assets and Liabilities Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 The Company is subject to the provisions of Financial (PUHCA). Both Southern Company and its subsidiaries Accounting Standards Board (FASB) Statement No. 71, are subject to the regulatory provisions of the PUHCA. Accounting for the Effects of Certain Types of The Company is also subject to regulation by the FERC Regulation. Regulatory assets represent probable future and the Alabama Public Service Commission (APSC). revenues associated with certain costs that are expected to The Company follows accounting principles generally be recovered from customers through the ratemaking accepted in the United States and complies with the process. Regulatory liabilities represent probable future accounting policies and practices prescribed by its reductions in revenues associated with amounts that are respective regulatory commissions. The preparation of expected to be credited to customers through the financial statements in conformity with accounting ratemaking process.

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

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

23

II NOTES (continued)

Alabama Power Company 2001 Annual Report Regulatory assets and (liabilities) reflected in the of spent nuclear fuel. The DOE failed to begin disposing Balance Sheets at December 31 relate to the following: of spent fuel in January 1998 as required by the contract, and the Company is pursuing legal remedies against the 2001 2000 government for breach of contract. Sufficient fuel storage (in millions) capacity is available at Plant Farley to maintain full-core Deferred income tax charges $335 $ 346 discharge capability until the refueling outage scheduled Deferred income tax credits (203) (222) in 2006 for Farley Unit 1 and the refueling outage Premium on reacquired debt 77 76 scheduled in 2008 for Farley Unit 2. Procurement of on Department of Energy assessments 21 25 site dry spent fuel storage capacity at Plant Farley is in Vacation pay 32 32 progress, with the intent to place the capacity in operation Natural disaster reserve (12) (18) as early as 2005.

Other, net 57 30 Total $ 307 $ 269 Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination In the event that a portion of the Company's operations and Decommissioning Fund, which is funded in part by a is no longer subject to the provisions of FASB Statement special assessment on utilities with nuclear plants. This No. 71, the Company would be required to write off assessment is being paid over a 15-year period, which related regulatory assets and liabilities that are not began in 1993. This fund will be used by the DOE for the specifically recoverable through regulated rates. In decontamination and decommissioning of its nuclear fuel addition the Company would be required to determine if enrichment facilities. The law provides that utilities will any impairment to other assets exists, including plant, and recover these payments in the same manner as any other write down the assets, if impaired, to their fair values. fuel expense. The Company estimates its remaining liability under this law to be approximately $21 million at Revenues and Fuel Costs December 31, 2001. This obligation is recognized in the accompanying Balance Sheets.

The Company currently operates as a vertically integrated utility providing electricity to retail customers within its Depreciation and Nuclear Decommissioning traditional service area located within the state of Alabama and to wholesale customers in the southeast. Revenues are Depreciation of the original cost of depreciable utility recognized as services are rendered. Unbilled revenues are plant in service is provided primarily by using composite accrued at the end of each fiscal period. Fuel revenues have straight-line rates, which approximated 3.2 percent in no effect on net income because they represent the 2001, 2000, and 1999. When property subject to recording of revenues to offset fuel expenses, including the depreciation is retired or otherwise disposed of in the fuel component of purchased energy. Fuel rates billed to normal course of business, its cost -- together with the cost customers are designed to fully recover fluctuating fuel of removal, less salvage -- is charged to accumulated costs over a period of time. provision for depreciation. Minor items of property included in the original cost of the plant are retired when The Company has a diversified base of customers. No the related property unit is retired. Depreciation expense single customer or industry comprises 10 percent or more includes an amount for the expected cost of of revenues. For all periods presented, uncollectible decommissioning nuclear facilities and removal of other accounts continue to average less than 1 percent of facilities.

revenues.

The Nuclear Regulatory Commission (NRC) requires all Fuel expense includes the amortization of the cost of licensees operating commercial nuclear power reactors to nuclear fuel and a charge based on nuclear generation for establish a plan for providing with reasonable assurance the permanent disposal of spent nuclear fuel. Total funds for decommissioning. The Company has established charges for nuclear fuel included in fuel expense external trust funds to comply with the NRC's regulations.

amounted to $58 million in 2001, $61 million in 2000, and Amounts previously recorded in internal reserves are being

$63 million in 1999. transferred into the external trust funds over periods approved by the APSC. The NRC's minimum external The Company has a contract with the U.S. Department funding requirements are based on a generic estimate of the of Energy (DOE) that provides for the permanent disposal cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. The Company 24

NOTES (continued)

Alabama Power Company 2001 Annual Report has filed plans with the NRC to ensure that -- over time - trust earnings rate of 7.0 percent. The Company expects the deposits and earnings of the external trust funds will the APSC to periodically review and adjust, if necessary, provide the minimum funding amounts prescribed by the the amounts collected in rates for the anticipated cost of NRC. decommissioning.

Site study cost is the estimate to decommission the Income Taxes facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of retirement The Company uses the liability method of accounting for date. The estimated costs of decommissioning -- both site deferred income taxes and provides deferred income taxes study costs and ultimate costs - based on the most current for all significant income tax temporary differences.

study for Plant Farley were as follows: Investment tax credits utilized are deferred and amortized to income over the average lives of the related property.

Site study basis (year) 1998 Allowance For Funds Used During Construction Decommissioning periods: (AFUDC)

Beginning year 2017 Completion year 2031 AFUDC represents the estimated debt and equity costs of (in millions) capital funds that are necessary to finance the construction Site study costs: of new facilities. While cash is not realized currently Radiated structures $629 from such allowance, it increases the revenue requirement Non-radiated structures 60 over the service life of the plant through a higher rate base Total $689 and higher depreciation expense. The amount of AFUDC Total (in millions) capitalized was $19 million in 2001, $43 million in 2000, Ultimate costs: and $23 million in 1999. The composite rate used to Radiated structures $1,868 determine the amount of allowance was 7.7 percent in Non-radiated structures 178 2001, 9.6 percent in 2000, and 8.8 percent in 1999.

Total $2,046 AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 3.3 percent in 2001, The decommissioning cost estimates are based on 8.4 percent in 2000, and 4.7 percent in 1999.

prompt dismantlement and removal of the plant from Property, Plant, and Equipment service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed Property, plant, and equipment is stated at original cost.

date of decommissioning, changes in NRC requirements, Original cost includes: materials; labor; minor items of or changes in the assumptions used in making estimates. property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other Annual provisions for nuclear decommissioning are benefits; and the estimated cost of funds used during based on an annuity method as approved by the APSC. construction. The cost of maintenance, repairs and The amount expensed in 2001 and fund balances as of replacement of minor items of property is charged to December 31, 2001 were: maintenance expense. The cost of replacements of (in millions) property--exclusive of minor items of property--is capitalized.

Amount expensed in 2001 $ 18 Financial Instruments Accumulated provisions:

External trust funds, at fair value $318 Effective January 2001, the Company adopted FASB Internal reserves 36 Statement No. 133, Accounting for Derivative Instruments Total $354 and Hedging Activities, as amended. The impact on net income was immaterial.

All of the Company's decommissioning costs are approved for recovery by the APSC through the The Company uses derivative financial instruments to ratemaking process. Significant assumptions include an hedge exposures to fluctuations in foreign currency estimated inflation rate of 4.5 percent and an estimated exchange rates and certain commodity prices. Gains and 25

fI NOTES (continued)

Alabama Power Company 2001 Annual Report losses on qualifying hedges are deferred and recognized either in income or as an adjustment to the carrying Carrying Fair amount of the hedged item when the transaction occurs. Amount Value (in millions)

The Company and its affiliates, through the system Long-term debt:

service company acting as their agent, enters into At December 31, 2001 $3,744 $3,800 commodity related forward and option contracts to limit At December 31, 2000 3,422 3,375 exposure to changing prices on certain fuel purchases and Preferred Securities:

electricity purchases and sales. Substantially all of the At December 31, 2001 347 346 Company's bulk energy purchases and sales contracts At December 31, 2000 347 344 meet the definition of a derivative under FASB Statement No. 133, Accounting for Derivative Instruments and The fair value for long-term debt and preferred Hedging Activities. In many cases these fuel and securities was based on either closing market prices or electricity contracts qualify for normal purchase and sale closing prices of comparable instruments.

exceptions under Statement No. 133 and are accounted for under the accrual method. Other contracts qualify as cash Cash and Cash Equivalents flow hedges of anticipated transactions, resulting in the For purposes of the financial statements, temporary cash deferral of related gains and losses and are recorded in investments are considered cash equivalents. Temporary other comprehensive income until the hedged transactions cash investments are securities with original maturities of occur. Any ineffectiveness is recognized currently in net 90 days or less.

income. Contracts that do not qualify for the normal purchase and sale exception and that do not meet the Materials and Supplies hedge requirements are marked to market through current period income. Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials.

In October 2001, the APSC approved a revision to the Materials are charged to inventory when purchased and Company's Rate ECR (Energy Cost Recovery) allowing then expensed or capitalized to plant, as appropriate, when the recovery of specific costs associated with the sales of installed.

natural gas that become necessary due to operating considerations at its electric generating facilities. This Natural Disaster Reserve revision also includes the cost of financial tools used for hedging market price risk up to 75 percent of the budgeted In accordance with an APSC order, the Company has annual amount of natural gas purchases. The Company established a Natural Disaster Reserve. The Company is may not engage in natural gas hedging activities that allowed to accrue $250 thousand per month until the extend beyond a rolling 42-month window. maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its The Company is exposed to losses related to financial authorized level are allowed whenever the balance in the instruments in the event of counterparties' reserve declines below $22.4 million. At December 3 1, nonperformance. The Company has established controls 2001, the reserve balance was $12 million.

to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's 2. RETIREMENT BENEFITS exposure to counterparty credit risk.

The Company has a defined benefit, trusteed, pension plan that covers substantially all employees. The Company Other Company financial instruments for which the carrying amount did not equal fair value at December 31 provides certain medical care and life insurance benefits for retired employees. Substantially all employees may are as follows:

become eligible for such benefits when they retire. The Company funds trusts to the extent deductible under federal income tax regulations or to the extent required by the APSC and the FERC. In late 2000 the Company adopted several pension and postretirement benefit plan changes that had the effect of increasing benefits to both current and future retirees.

26

NOTES (continued)

Alabama Power Company 2001 Annual Report The measurement date for plan assets and obligations 2001 2000 1999 is September 30 of each year. The weighted average rates (in millions) assumed in the actuarial calculations for both the pension Service cost $ 25 $ 23 $ 23 and postretirement benefit plans were: Interest cost 70 65 58 Expected return on plan assets (131) (119) (109) 2001 2000 Recognized net actuarial gain (22) (19) (13)

Discount 7.50% 7.50% Net amortization 1 (1) (1)

Annual salary increase 5.00 5.00 Net pension income $ (57) $ (51) $ (42)

Long-term return on plan assets 8.50 8.50 Postretirement Benefits Pension Plan Changes during the year in the projected benefit Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as obligations and in the fair value of plan assets were as follows: follows:

Projected Accumulated Benefit Obligations Benefit Obligations 2001 2000 2001 2000 (in millions) (in millions)

Balance at beginning of year $925 $896 Balance at beginning of year $264 $264 Service cost 25 23 Service cost 5 4 Interest cost 70 65 Interest cost 24 19 Benefits paid (56) (51) Benefits paid (18) (12)

Actuarial gain and Actuarial gain and employee transfers (1) (8) employee transfers (13) (11)

Amendments 48 Amendments 86 Balance at end of year $1,011 $925 Balance at end of year $348 $264 Plan Assets Plan Assets 2001 2000 2001 2000 (in millions) (in millions)

Balance at beginning of year $1,921 $1,647 Balance at beginning of year $192 $161 Actual return on plan assets (277) 302 Actual return on plan assets (24) 25 Benefits paid (56) (51) Employer contributions 19 18 Employee transfers (4) 23 Benefits paid (18) (12)

Balance at end of year $1,584 $1,921 Balance at end of year It $169 $192 The accrued pension costs recognized in the Balance The accrued postretirement costs recognized in the Sheets were as follows: Balance Sheets were as follows:

2001 2000 2001 2000 (in millions)

(in millions) Funded status $(179) $(72)

Funded status $ 573 $996 Unrecognized transition obligation 45 49 Unrecognized transition obligation (15) (20) Prior service cost 82 Unrecognized prior service cost 78 36 Unrecognized net actuarial gain (9) (35)

Unrecognized net actuarial gain (322) (757) Fourth quarter contributions 8 4 Prepaid asset recognized in the Accrued liability recognized in the Balance Sheets $314 $ 255 Balance Sheets $ (53) $(54)

Components of the pension plan's net periodic cost were as follows:

27

NOTES (continued)

Alabama Power Company 2001 Annual Report Components of the plans' net periodic cost were as 3. CONTINGENCIES AND REGULATORY follows: MATTERS 2001 2000 1999 General (in millions)

Service cost $ 5 $ 4 $ 5 The Company is subject to certain claims and legal actions Interest cost 24 19 18 arising in the ordinary course of business. In the opinion Expected return on plan assets (15) (13) (11) of management after consultation with legal counsel, the Net amortization 7 4 4 ultimate disposition of these matters is not expected to Net postretirement cost $ 21 $ 14 $ 16 have a material adverse effect on the Company's financial condition.

An additional assumption used in measuring the Environmental Litigation accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 9.25 On November 3, 1999, the Environmental Protection percent for 2001, decreasing gradually to 5.25 percent Agency (EPA) brought a civil action in U.S. District Court through the year 2010, and remaining at that level in Georgia against the Company. The complaint alleges thereafter. An annual increase or decrease in the assumed violations of the New Source Review provisions of the medical care cost trend rate of 1 percent would affect the Clean Air Act with respect to coal-fired generating accumulated benefit obligation and the service and interest facilities at the Company's Plants Miller, Barry, and cost components at December 31, 2001 as follows: Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the 1 Percent 1 Percent best available control technology at the affected units.

Increase Decrease The Clean Air Act authorizes civil penalties of up to (in millions)

$27,500 per day, per violation at each generating unit.

Benefit obligation $30 $26 Prior to January 30, 1997, the penalty was $25,000 per Service and interest costs 3 2 day.

Employee Savings Plan The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as The Company also sponsors a 401(k) defined contribution Plants Greene County and Gaston. In early 2000, the EPA plan covering substantially all employees. The Company filed a motion to amend its complaint to add the violations provides a 75 percent matching contribution up to 6 alleged in its notice of violation. The complaint and the percent of an employee's base salary. Total matching notice of violation are similar to those brought against and contributions made to the plan for the years 2001, 2000, issued to several other electric utilities. The complaint and 1999 were $12 million, $11 million, and $10 million, and the notice of violation allege that the Company failed respectively. to secure necessary permits or install additional pollution control equipment when performing maintenance and Work Force Reduction Programs construction at coal burning plants constructed or under construction prior to 1978. On August 1, 2000, the U.S.

The Company has incurred costs for work force reduction District Court granted the Company's motion to dismiss programs totaling $13.0 million, $2.6 million and $5.6 for lack of jurisdiction in Georgia. On January 12, 2001, million for the years 2001, 2000 and 1999, respectively. the EPA re-filed its claims against the Company in federal These costs were deferred and are being amortized in district court in Birmingham, Alabama.

accordance with regulatory treatment. The unamortized balance of these costs was $11.9 million at December 31, The Company's case has been stayed since the spring of 2001. 2001, pending a ruling by the U.S. Court of Appeals for the Eleventh Circuit in the appeal of a very similar New Source Review enforcement action against the Tennessee Valley Authority (TVA). The TVA case involves many of the same legal issues raised by the actions against the Company. Because the outcome of the TVA case could have a significant adverse impact on the Company, it is a 28

NOTES (continued)

Alabama Power Company 2001 Annual Report party to that case as well. The U.S. District Court in beginning in 2003 while the remaining half is scheduled Alabama has indicated that it will revisit the issue of a for delivery beginning in 2004. Rate CNP will adjust continued stay in April 2002. retail rates when the contracted capacity delivery begins.

The Company believes that it complied with applicable In October 2001, the APSC approved a revision to the laws and the EPA's regulations and interpretations in Company's Rate ECR (Energy Cost Recovery) allowing effect at the time the work in question took place. An the recovery of specific costs associated with the sales of adverse outcome of this matter could require substantial natural gas that become necessary due to operating capital expenditures that cannot be determined at this time considerations at its electric generating facilities. This and possibly require payment of substantial penalties. revision also includes the cost of financial tools used for This could affect future results of operations, cash flows, hedging market price risk up to 75 percent of the budgeted and possibly financial condition if such costs are not annual amount of natural gas purchases. The Company recovered through regulated rates. may not engage in natural gas hedging activities that extend beyond a rolling 42-month window.

Retail Rate Adjustment Procedures The Company's ratemaking procedures will remain in The APSC has adopted rates that provide for periodic effect until the APSC votes to modify or discontinue them.

adjustments based upon the Company's earned return on end-of-period retail common equity. The rates also 4. COMMITMENTS provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP Construction Program (Certificated New Plant). Both increases and decreases have been placed into effect since the adoption of these During 2001, the Company completed the replacement of rates. Effective July 2001, the Company's retail rates the steam generators at Plant Farley, as well as the were adjusted by 0.6 percent under Rate CNP to recover construction of new generating capacity at Plant Barry.

costs for Plant Barry Unit 7, which was placed into Significant construction will continue related to commercial operation on May 1, 2001. Most recently, a 2 transmission and distribution facilities and the upgrading percent increase in retail rates was effective in October of generating plants, including the expenditures necessary 2001 in accordance with the Rate Stabilization to comply with environmental regulation.

Equalization plan. The rate adjustment procedures allow a return on common equity range of 13.0 percent to 14.5 The Company currently estimates property additions to percent and limit increases or decreases in rates to 4 be $671 million in 2002, $592 million in 2003, and $673 percent in any calendar year. million in 2004.

In December 1995, the APSC issued an order In connection with the transfer of the Autaugaville authorizing the Company to reduce balance sheet items - construction project, the Company has assigned $71 such as plant and deferred charges -- at any time the million in vendor equipment contracts to Southern Power.

Company's actual base rate revenues exceed the budgeted While the Company could be obligated to assume revenues. During the years 2001, 2000, and 1999, the responsibility for these contracts if Southern Power fails to Company did not record any such reductions. meet these commitments, Southern Company has entered into limited keep-well arrangements whereby Southern In April 2000, the APSC approved an amendment to Company would contribute funds to Southern Power the Company's existing rate structure to provide for the either through loans or capital contributions in order to recovery of retail costs associated with certified purchased fund performance by Southern Power as equipment power agreements. In November 2000, the APSC purchaser under certain contingencies. Southern certified a seven-year purchased power agreement Company has also guaranteed Southern Power obligations pertaining to 615 megawatts of the wholesale generating totaling $6.6 million for the Company's construction of facilities which were sold to Southern Power in June 2001 transmission interconnection facilities to the plant.

and are under construction in Autaugaville, Alabama. All of the 615 megawatts will be delivered beginning in 2003. The capital budget is subject to periodic review and In addition the APSC certified a seven-year purchased revision, and actual capital costs incurred may vary from power agreement with a third party for approximately 630 estimates because of changes in such factors as: business megawatts; one half of the power will be delivered 29

ffi[

NOTES (continued)

Alabama Power Company 2001 Annual Report conditions; environmental regulations; nuclear plant Year Natural Gas regulations; load projections; the cost and efficiency of (MMBtu) construction labor, equipment, and materials; and the cost 2002 77,365,361 of capital. In addition there can be no assurance that costs 2003 72,139,927 related to capital expenditures will be fully recovered. 2004 45,600,417 2005 22,849,132 Purchased Power Commitments 2006 14,808,334 2007 and thereafter 5,609,190 The Company has entered into various long-term Total commitments 238,372,361 commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 2001 were as Additional commitments for fuel will be required in the follows: future to supply the Company's fuel needs.

Commitments Non Operating Leases Year Affiliate d Affiliated Total (in millions) The Company has entered into rental agreements for coal 2002 $ $ rail cars, vehicles, and other equipment with various terms 2003 37 16 53 and expiration dates. These expenses totaled $27.9 2004 49 34 83 million in 2001, $20.9 million in 2000, and $17.8 million 2005 49 37 86 in 1999. At December 31, 2001, estimated minimum 2006 49 38 87 rental commitments for noncancellable operating leases 2007 and thereafter 160 142 302 were as follows:

Total commitments $344 $267 $611 Year Commitments Fuel Commitments (in millions) 2002 $ 27.9 To supply a portion of the fuel requirements of its 2003 26.5 generating plants, the Company has entered into various 2004 25.5 long-term commitments for the procurement of fossil and 2005 21.6 nuclear fuel. In most cases these contracts contain 2006 14.4 provisions for price escalations, minimum purchase levels, 2007 and thereafter 38.1 and other financial commitments. Total estimated long Total minimum payments $154.0 term obligations at December 31, 2001, were as follows:

In addition to the rental commitments above, the Year Commitments Company has potential obligations upon expiration of (in millions) certain leases with respect to the residual value of the 2002 $ 795 leased property. These leases expire in 2004 and 2006, 2003 794 and the Company's maximum obligations are $25.7 2004 801 million and $66.0 million, respectively. At the 2005 571 termination of the leases, at the Company's option, the 2006 512 Company may negotiate an extension, exercise its 2007 and thereafter 1,020 purchase option, or the property can be sold to a third Total commitments $4,493 party. The Company expects that the fair market value of the leased property would substantially reduce or In addition, the system service company acts as agent eliminate the Company's payments under the residual for the five operating companies and Southern Power with value obligation.

regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of 5. JOINT OWNERSHIP AGREEMENTS delivery; therefore, only the volume commitments are firm. The Company's committed volumes allocated based The Company and Georgia Power own equally all of the on usage projections, as of December 31, 2001, are as outstanding capital stock of Southern Electric Generating follows: Company (SEGCO), which owns electric generating units with a total rated capacity of 1,020 megawatts, together 30

NOTES (continued)

Alabama Power Company 2001 Annual Report with associated transmission facilities. The capacity of 6. LONG-TERM POWER SALES AGREEMENTS these units is sold equally to the Company and Georgia Power under a contract which, in substance, requires General payments sufficient to provide for the operating expenses, taxes, interest expense and a return on equity, whether or The Company and the other operating companies of not SEGCO has any capacity and energy available. The Southern Company have entered into long-term term of the contract extends automatically for two-year contractual agreements for the sale and lease of capacity periods, subject to either party's right to cancel upon two and energy to certain non-affiliated utilities located year's notice. The Company's share of expenses totaled outside the system's service area. These agreements -

$80 million in 2001, $85 million in 2000, and $92 million expiring at various dates discussed below -- are firm and in 1999 and is included in "Purchased power from related to specific generating units. Because the energy is affiliates" in the Statements of Income. generally provided at cost under these agreements, profitability is primarily affected by capacity revenues.

In addition the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale Unit power from Plant Miller is being sold to Florida agreement for the purchase of certain pollution control Power Corporation (FPC), Florida Power & Light facilities at SEGCO's generating units, pursuant to which Company (FP&L), and Jacksonville Electric Authority

$24.5 million principal amount of pollution control revenue (JEA). Under these agreements approximately 1,237 bonds are outstanding. Georgia Power has agreed to megawatts of capacity are scheduled to be sold through reimburse the Company for the pro rata portion of such 2010. The Company's capacity revenues amounted to obligation corresponding to its then proportionate $125 million in 2001, $127 million in 2000, and $122 ownership of stock of SEGCO if the Company is called million in 1999.

upon to make such payment under its guaranty.

Alabama Municipal Electric Authority (AMEA)

At December 31, 2001, the capitalization of SEGCO Capacity Contracts consisted of $58 million of equity and $86 million of long term debt on which the annual interest requirement is $2.2 In 1986 the Company entered into a firm power sales million. SEGCO paid dividends totaling $0.7 million in contract with AMEA entitling AMEA to scheduled 2001, $5.1 million in 2000, and $4.3 million in 1999 of amounts of capacity (to a maximum 100 megawatts) for a which one-half of each was paid to the Company. period of 15 years (1986 Contract). In October 1991 the SEGCO's net income was $7.5 million, $5.9 million, and Company entered into a second firm power sales contract

$5.4 million for 2001, 2000, and 1999, respectively. with AMEA entitling AMEA to scheduled amounts of additional capacity (to a maximum 80 megawatts) for a The Company's percentage ownership and investment period of 15 years (1991 Contract). Under the terms of in jointly-owned generating plants at December 31, 2001, the contracts, the Company received payments from is as follows: AMEA representing the net present value of the revenues Total associated with the respective capacity entitlements, Megawatt Company discounted at effective annual rates of 9.96 percent and Facility (Type) Capacity Ownership 11.19 percent for the 1986 and 1991 contracts, respectively. The 1986 contract expired in July 2001, Greene County 500 60.00% (1) however, the payments for the 1991 contract will continue (coal) to be recognized as operating revenues and the discounts Plant Miller will be amortized to other interest expense as scheduled Units 1 and 2 1,320 91.84% (2) capacity is made available over the terms of the contract.

(coal)

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

(2) Jointly owned with Alabama Electric Cooperative, Inc. To secure AMEA's advance payments and the Company's performance obligation under the contracts, Company Accumulated the Company issued and delivered to an escrow agent first Facility Investment Depreciation mortgage bonds representing the maximum amount of (in millions) liquidated damages payable by the Company in the event Greene County $101 $ 49 of a default under the contracts. No principal or interest is Plant Miller payable on such bonds unless and until a default by the Units 1 and 2 747 326 Company occurs. As the liquidated damages decline, a 31

III NOTES (continued)

Alabama Power Company 2001 Annual Report portion of the bond equal to the decrease is returned to the 2001 2000 Company. At December 31, 2001, $38.1 million of the (in millions) 1991 bond was held by the escrow agent under the Deferred tax liabilities:

contract. Accelerated depreciation $1,034 $ 992 Property basis differences 390 405

7. INCOME TAXES Fuel cost adjustment 28 93 At December 31, 2001, the tax-related regulatory assets Premium on reacquired debt 29 30 and liabilities were $335 million and $203 million, Pensions 89 75 respectively. These assets are attributable to tax benefits Other 23 12 flowed through to customers in prior years and to taxes Total 1,593 1,607 applicable to capitalized interest. These liabilities are Deferred tax assets:

attributable to deferred taxes previously recognized at Capacity prepayments 13 18 rates higher than current enacted tax law and to Other deferred costs 14 14 unamortized investment tax credits. Postretirement benefits 21 24 Unbilled revenue 18 23 Details of the income tax provisions are as follows: Other 93 81 Total 159 160 2001 2000 1999 Total deferred tax liabilities, net 1,434 1,447 (in millions) Portion included in current liabilities, net (47) (46)

Total provision for income Accumulated deferred income taxes taxes: in the Balance Sheets $1,387 $1,401 Federal -

Current $234 $168 $194 Deferred investment tax credits are amortized over the Deferred (20) 60 24 lives of the related property with such amortization 214 228 218 normally applied as a credit to reduce depreciation in the State - Statements of Income. Credits amortized in this manner Current 37 27 19 amounted to $11 million in 2001, 2000, and 1999. At Deferred (2) 7 5 December 31, 2001, all investment tax credits available to 35 34 24 reduce federal income taxes payable had been utilized.

Total $249 $262 $242 A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial 2001 2000 1999 statements and their respective tax bases, which give rise Federal statutory rate 35.0% 35.0% 35.0%

to deferred tax assets and liabilities, are as follows: State income tax, net of federal deduction 3.5 3.1 2.4 Non-deductible book depreciation 1.5 1.4 1.6 Differences in prior years' deferred and current tax rates (1.3) (1.3) (1.3)

Other (0.5) (0.7) (0.9)

Effective income tax rate 38.2% 37.5% 36.8%

Southern Company files a consolidated federal and certain state income tax returns. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability.

32

NOTES (continued)

Alabama Power Company 2001 Annual Report

8. CAPITALIZATION and equipping of certain local district heating facilities and sewage and solid waste facilities at two of the Company's Mandatorily Redeemable Preferred Securities generation facilities.

Statutory business trusts formed by the Company, of Senior Notes which the Company owns all the common securities, have issued mandatorily redeemable preferred securities as In August 2001 the Company issued $442 million of follows: unsecured senior notes, the proceeds of which were used to redeem the $131.5 million outstanding principal of its Date of Maturity First Mortgage Bonds, 9% Series due December 1, 2004 Issue Amount Rate Notes Date and for other corporate purposes including the repayment (millions) (millions) of a portion of its short-term indebtedness. All of the Trust I 1/1996 $ 97 7.375% $100 3/2026 Company's senior notes are, in effect, subordinate to all Trust II 1/1997 200 7.60 206 12/2036 secured debt of the Company, including its first mortgage Trust III 2/1999 50 Auction 52 2/2029 bonds.

Substantially all of the assets of each trust are junior Capitalized Leases subordinated notes issued by the Company in the respective approximate principal amounts set forth above. The estimated aggregate annual maturities of capitalized The distribution rate of Trust III's auction rate securities lease obligations through 2006 are as follows: $0.9 million was 3.60% at January 1, 2002. in 2002, $0.9 million in 2003, $1.0 million in 2004, $0.4 million in 2005, and $0.1 million in 2006.

The Company considers that the mechanisms and obligations relating to the preferred securities, taken Securities Due Within One Year together, constitute a full and unconditional guarantee by the Company of the Trusts' payment obligations with A summary of the improvement fund requirements and respect to the preferred securities. scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows:

The Trusts are subsidiaries of the Company and accordingly are consolidated in the Company's financial 2001 2000 (in thousands) statements.

First mortgage bond maturities Pollution Control Bonds and redemptions $4,498 Other long-term debt maturities 884 844 Pollution control obligations represent installment Total long-term debt due within purchases of pollution control facilities financed by funds one year $5,382 $844 derived from sales by public authorities of revenue bonds.

The Company is required to make payments sufficient for The annual first mortgage bond improvement fund the authorities to meet principal and interest requirements requirement is 1 percent of the aggregate principal amount of such bonds. With respect to $114.2 million of such of bonds of each series authenticated, so long as a portion pollution control obligations, the Company has of that series is outstanding, and may be satisfied by the authenticated and delivered to the trustees a like principal deposit of cash and/or reacquired bonds, the certification amount of first mortgage bonds as security for its of unfunded property additions, or a combination thereof.

obligations under the installment purchase agreements.

No principal or interest on these first mortgage bonds is Bank Credit Arrangements payable unless and until a default occurs on the installment purchase agreements. The Company maintains committed lines of credit in the amount of $964 million (including $454 million of such In 2001, the Company sold, through a public authority, lines which are dedicated to funding purchase obligations

$20 million of pollution control bonds, the proceeds of relating to variable rate pollution control bonds). Of these which were used to pay certain costs incurred in lines, $574 million expire at various times during 2002 connection with the acquisition, construction, installation, and $390 million expire in 2004. In certain cases, such 33

III NOTES (continued)

Alabama Power Company 2001 Annual Report lines require payment of a commitment fee based on the The Company is a member of Nuclear Electric unused portion of the commitment or the maintenance of Insurance Limited (NEIL), a mutual insurer established to compensating balances with the banks. Because the provide property damage insurance in an amount up to arrangements are based on an average balance, the $500 million for members' nuclear generating facilities.

Company does not consider any of its cash balances to be restricted as of any specific date. Moreover, the Company Additionally, the Company has policies that currently borrows from time to time pursuant to arrangements with provide decontamination, excess property insurance, and banks for uncommitted lines of credit. The amount of premature decommissioning coverage up to $2.25 billion commercial paper outstanding at December 31, 2001 was for losses in excess of the $500 million primary coverage.

$10 million. This excess insurance is also provided by NEIL.

NEIL also covers the additional cost that would be At December 31, 2001, the Company had regulatory incurred in obtaining replacement power during a approval to have outstanding up to $1 billion of short-term prolonged accidental outage at a member's nuclear plant.

borrowings.

Members can purchase this coverage, subject to a Assets Subject to Lien deductible waiting period of between 8 to 26 weeks, with a maximum per occurrence per unit limit of $490 million.

The Company's mortgage, as amended and supplemented, After this deductible period, weekly indemnity payments securing the first mortgage bonds issued by the Company, would be received until either the unit is operational or constitutes a direct lien on substantially all of the until the limit is exhausted in approximately three years.

Company's fixed property and franchises.

Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated Dividend Restrictions funds available to the insurer under that policy. The current maximum annual assessments for the Company The Company's first mortgage bond indenture contains' under the three NEIL policies would be $35 million.

various common stock dividend restrictions that remain in effect as long as the bonds are outstanding. At Following the terrorist attacks of September 2001, both December 31, 2001, retained earnings of $796 million ANI and NEIL confirmed that terrorist acts against were restricted against the payment of cash dividends on commercial nuclear power stations would be covered common stock under terms of the mortgage indenture. under their insurance. However, both companies revised their policy terms on a prospective basis to include an

9. NUCLEAR INSURANCE industry aggregate for all terrorist acts. The NEIL aggregate, which applies to all claims stemming from Under the Price-Anderson Amendments Act of 1988 (the terrorism within a 12 month duration, is $3.24 billion plus Act), the Company maintains agreements of indemnity any amounts that would be available through reinsurance with the NRC that, together with private insurance, cover or indemnity from an outside source. The ANI cap is third-party liability arising from any nuclear incident

$200 million in a policy year.

occurring At Plant Farley. The Act provides funds-up to

$9.5 billion for public liability claims that could arise from For all on-site property damage insurance policies for a single nuclear incident. Plant Farley is insured against commercial nuclear power plants, the NRC requires that this liability to a maximum of $200 million by American the proceeds of such policies shall be dedicated first for Nuclear Insurers (ANI), with the remaining coverage the sole purpose of placing the reactor in a safe and stable provided by a mandatory program of deferred premiums which could be assessed, after a nuclear incident, against condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination all owners of nuclear reactors. The Company could be and debris removal operations ordered by the NRC, and assessed up to $88 million per incident for each licensed any further remaining proceeds are to be paid either to the reactor it operates but not more than an aggregate of $10 Company or to its bond trustees as may be appropriate million per incident to be paid in a calendar year for each under the policies and applicable trust indentures.

reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $176 All retrospective assessments, whether generated for million per incident but not more than an aggregate of $20 liability, property or replacement power may be subject to million to be paid for each incident in any one year. applicable state premium taxes.

34

NOTES (continued)

Alabama Power Company 2001 Annual Report

10. QUARTERLY FINANCIAL INFORMATION (Unaudited)

Summarized quarterly financial data for 2001 and 2000 are as follows:

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

March 2001 $ 850 $180 $ 70 June 2001 904 194 75 September 2001 1,061 362 180 December 2001 772 175 62 March 2000 $ 746 $172 $ 68 June 2000 900 229 103 September 2000 1,137 390 209 December 2000 884 151 40 The Company's business is influenced by seasonal weather conditions.

35

SELECTED FINANCIAL AND OPERATING DATA 1997-2001 Alabama Power Company 2001 Annual Report 2001 2000 1999 1998 1997 Operating Revenues (in thousands) $3,586,390 $3,667,461 $3,385,474 $3,386,373 $3,149,111 Net Income after Dividends on Preferred Stock (in thousands) $386,729 $419,916 $399,880 $377,223 $375,939 Cash Dividends on Common Stock (in thousands) $393,900 $417,100 $399,600 $367,100 $339,600 Return on Average Common Equity (percent) 11.89 13.58 13.85 13.63 13.76 Total Assets (in thousands) $10,418,301 $10,366,105 $9,648,704 $9,225,698 $8,812,867 Gross Property Additions (in thousands) $635,540 $870,581 $809,044 $610,132 $451,167 Capitalization (in thousands):

Common stock equity $3,310,877 $3,195,772 $2,988,863 $2,784,067 $2,750,569 Preferred stock 317,512 317,512 317,512 317,512 255,512 Company obligated mandatorily redeemable preferred securities 347,000 347,000 347,000 297,000 297,000 Long-term debt 3,742,346 3,425,527 3,190,378 2,646,566 2,473,202 Total (excluding amounts due within one year) $7,717,735 $7,285,811 $6,843,753 $6,045,145 $5,776,283 Capitalization Ratios (percent):

Common stock equity 42.9 43.9 43.7 46.1 47.6 Preferred stock 4.1 4.4 4.6 5.3 4.4 Company obligated mandatorily redeemable preferred securities 4.5 4.8 5.1 4.9 5.2 Long-term debt 48.5 46.9 46.6 43.7 42.8 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+ AA- AA- AA- AA Preferred Stock Moody's Baal a2 a2 a2 a2 Standard and Poor's BBB+ BBB+ A- 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 1,139,542 1,132,410 1,120,574 1,106,217 1,092,161 Commercial 196,617 193,106 188,368 182,738 177,362 Industrial 4,728 4,819 4,897 5,020 5,076 Other 751 745 735 733 728 Total 1,341,638 1,331,080 1,314,574 1,294,708 1,275,327 Employees (year-end): 6,706 6,871 6,792 6,631 6,531 36

SELECTED FINANCIAL AND OPERATING DATA 1997-2001 (continued)

Alabama Power Company 2001 Annual Report 2001 2000 1999 1998 1997 Operating Revenues (in thousands):

Residential $ 1,138,499 $1,222,509 $ 1,145,646 $ 1,133,435 $ 997,507 Commercial 829,760 854,695 807,098 779,169 724,148 Industrial 763,934 859,668 843,090 853,550 775,591 Other 15,480 15,835 15,283 14,523 13,563 Total retail 2,747,673 2,952,707 2,811,117 2,780,677 2,510,809 Sales for resale - non-affiliates 485,974 461,730 415,377 448,973 431,023 Sales for resale - affiliates 245,189 166,219 92,439 103,562 161,795 Total revenues from sales of electricity 3,478,836 3,580,656 3,318,933 3,333,212 3,103,627 Other revenues 107,554 86,805 66,541 53,161 45,484 Total $3,586,390 $3,667,461 $3,385,474 $3,386,373 $3,149,111 Kilowatt-Hour Sales (in thousands):

Residential 15,880,971 16,771,821 15,699,081 15,794,543 14,336,408 Commercial 12,798,711 12,988,728 12,314,085 11,904,509 11,330,312 Industrial 20,460,022 22,101,407 21,942,889 21,585,117 20,727,912 Other 198,102 205,827 201,149 196,647 180,389 Total retail 49,337,806 52,067,783 50,157,204 49,480,816 46,575,021 Sales for resale - non-affiliates 15,277,839 14,847,533 12,437,599 11,840,910 12,329,480 Sales for resale - affiliates 8,843,094 5,369,474 5,031,781 5,976,099 8,993,326 Total 73,458,739 72,284,790 67,626,584 67,297,825 67,897,827 Average Revenue Per Kilowatt-Hour (cents):

Residential 7.17 7.29 7.30 7.18 6.96 Commercial 6.48 6.58 6.55 6.55 6.39 Industrial 3.73 3.89 3.84 3.95 3.74 Total retail 5.57 5.67 5.60 5.62 5.39 Sales for resale 3.03 3.11 2.91 3.10 2.78 Total sales 4.74 4.95 4.91 4.95 4.57 Residential Average Annual Kilowatt-Hour Use Per Customer 13,981 14,875 14,097 14,370 13,254 Residential Average Annual Revenue Per Customer $1,002.30 $1,084.26 $1,028.76 $1,031.21 $922.21 Plant Nameplate Capacity Ratings (year-end) (megawatts) 12,153 12,122 11,379 11,151 11,151 Maximum Peak-Hour Demand (megawatts):

Winter 9,300 9,478 8,863 7,757 8,478 Summer 10,241 11,019 10,739 10,329 9,778 Annual Load Factor (percent) 62.5 59.3 59.7 62.9 62.7 Plant Availability (percent):

Fossil-steam 87.1 89.4 80.4 85.6 86.3 Nuclear 83.7 88.3 91.0 80.2 88.8 Source of Energy Supply (percent):

Coal 56.8 63.0 64.1 65.3 65.7 Nuclear 15.8 16.9 17.8 16.3 17.9 Hydro 5.1 2.9 4.7 6.9 7.5 Oil and gas 10.7 4.9 1.1 1.5 0.7 Purchased power From non-affiliates 4.4 4.6 4.5 3.3 2.4 From affiliates 7.2 7.7 7.8 6.7 5.8 Total 100.0 100.0 100.0 100.0 100.0 37

DIRECTORS AND OFFICERS Alabama Power Company 2001 Annual Report Officers Donald W. Reese Directors Vice President Whit Armstrong Elmer B. Harris I Julian H1 Smith, Jr.

President, Chairman and CEO, Chairman Vice President The Citizens Bank Charles D. McCrary W. Ronald Smith David J. Cooper President & Chief Executive Officer Vice President, Eastern Division President, Michael D. Garrett 2 Cheryl A. Thompson Cooper/T. Smith Corporation Executive Vice President Vice President, Mobile Division RI Allen Franklin William B. Hutchins, mll Terry H. Waters President, Chairman and CEO, Executive Vice President, Chief Vice President, Western Division Southern Company Financial Officer & Treasurer William E. Zales, Jr.

Elmer B. Harris C. Alan Martin Vice President, Corporate Secretary &

Chairman Executive Vice President Assistant Treasurer Alabama Power Company Steve R. Spence? E. Wayne Boston R. Kent Henslee Executive Vice President Assistant Secretary and Managing Partner, Henslee, Robertson, Assistant Treasurer Strawn & Knowles, LIL.C. Robert Holmes, Jr. 3 Senior Vice President J. Randy DeRieux Carl E. Jones, Jr. Assistant Treasurer President and CEO, Robin A. Hurst Regions Financial Corporation Senior Vice President Robert Cole Giddens Assistant Comptroller Patricia M. King Rodney 0. Mundy President and CEO, Senior Vice President & Counsel Stuart Griffin 9 King Motor Company Assistant Secretary Michael L Scott James K Lowder Senior Vice President Ceila HR Shorts Chairman, Assistant Secretary Jerry L Stewart 0

The Colonial Company Senior Vice President Cynthia H. Wilson 1 Wallace D. Malone, Jr. Assistant Secretary Christopher C. Womack 4 Chairman and CEO, Senior Vice President t Retired 1/02 SouthTrust Corporation 2 Resigned 4/01; Elected President of Art P. Beattie Charles D. McCrary* Vice President & Comptroller Mississippi Power Co. 4/01 3

President & CEO Elected 4/01 Alabama Power Company Willard L Bowers s "4ElectedSenior Vice President of Vice President Georgia Power Co. 12/01 Dr. Thomas C. Meredith 5 Elected 1/02 Chancellor, Christopher T. Bell 6 6 VicePreskidt Elected 5/01 The University of Georgia System 7 Elected 7/01 Mayer Mitchell Marsha S. Johnson 7 "8Elected 9/01 President, Mitchell Brothers, Inc. Vice President, Binringham Division 9 Resigned 2/02 Gerald L Johnson 8 '0 Appointed 2/02 Dr. William V. Muse Chancellor, East Carolina University Vice President "*Seemessage from the Board of Robert D. Powers William B. Johnson 8 Directors President, The Eufaula Agency Vice President Andreas Renschler J. Bruce Jones President, Mcc smart Gmbh Vice President C. Dowd Ritter Bobby J. Kerley 3 Chairman, President and CEO, Vice President, Southeast Division AmSouth Bancorporation William B. Keller James H. Sanford Vice President Chainnan, HOME Place Farms, Inc. Penny M_.Manuel 3 John Cox Webb, IV Vice President & Chief Information President, Webb Lumber Company Officer James W. Wright Gordon G. Martin 6 Chairman and CEO, Vice President, Southern Division First Tuskegee Bank 38

CORPORATE INFORMATION Alabama Power Company 2001 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 Auction Class A connection with any sale or purchase of, or Preferred Stock 1988 & 1993 Series 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 Auction Class A Preferred Stock 1988 Alabama. The Company sells electricity to and 1993 Series more than 1.3 million customers within its The Bank of New York service area of approximately 45,000 square 101 Barclay Street miles. In 2001, retail energy sales accounted New York, NY 10286 for 67 percent of the Company's total sales of 73.5 billion kilowatt-hours. Form 10-K A copy of Form 10-K as filed with the The Company is a wholly owned Securities and Exchange Commission will subsidiary of Southern Company, which ip the be provided upon written request to the parent company of integrated Southeast office of the Corporate Secretary. For utilities. There is no established public additional information, contact the office trading market for the Company's common of the Corporate Secretary at (205) 257 stock. 3385.

Trustee, Registrar and Interest Paying Agent Alabama Power Company All series of First Mortgage Bonds, 600 North 18th Street Senior Notes and Trust Preferred Securities Birmingham, AL 35291 JPMorgan Chase Bank (205) 257-1000 Institutional Trust Services www.alabamapower.com 450 West 33'd Street, 15th Floor New York, NY 1000 1-2697 2001 Auditors Arthur Andersen LLP 420 North 20t Street Suite 1800 Birmingham, AL 35203 Legal Counsel Balch & Bingham LLP P.O. Box 306 Birmingham, AL 35201 39