ML061290148

Annual Submission Reports

ML061290148
Person / Time
Site:	Farley
Issue date:	04/26/2006
From:	Derieux J Alabama Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML061290148 (61)

Text

J. Randy DeRieux 600 North 18th Street Assistant Treasurer and Post Office Box 2641 Manager - Birmingham, Alabama 15291-0040 Treasury/Finance Tel 205.257.2454 Fax 205.257.1023 ALABAMA so POWER Always on.:

A SOUTHERN COMPANY April 26, 2006 100 Years. Lighting the way.

U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555-0001 Joseph M. Farley Nuclear Plant Annual Submission ReDorts 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 $30,000,000 within three months after submission of the statement. In this connection, enclosed are the following:

1. 2005 Annual Report which includes financial statements for the calendar year 2005, together with the report on such statements by Deloitte & Touche LLP, independent public accountants;

2. Unaudited Financial Statements for the quarter ended March 31, 2006;

3. Cash Flow Projections for the period January 1, 2006 through December 31, 2006, showing that cash flow of $30,000,000 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~jm 7 Enclosures cc: w/enclosures Southern Nuclear Operating Companv Mr. J. T. Gasser, Executive Vice President Mr. J. R. Johnson, General Manager - Plant Farley U. S. Nuclear Regulatory Commission Dr. W. D. Travers, Regional Administrator Mr. R. E. Martin, NRR Project Manager - Farley k Jooq Mr. C. A. Patterson, Senior Resident Inspector - Farley

ALABAMA POWER COMPANY STATEMENT OF INCOME (THOUSANDS OF DOLLARS) 3 Months Ended 3/3132006 .- , , "

I1 )

OPERAlING REVENUES: . . -, j Revenues $ 1,072,707 OPERATING EXPENSES:

Operation -. - A , .,

Fuel 341,767 Purchased &Interchange power, net 78,751 Other 169,013 Maintenance 109,50 Depreciation & amortation 109,862 Taxes other than ncome taxes 65,657 Federal and State inoome taxes 53,363 Total Operating Expenses 927,913 OPERATING INCOME 144,794 I.1 ....

OTHER INCOME (EXPENSES): .. ....

i Allowance for equity funds used during construction 5,529 Income from subsidiary 1,075 Other, net i.)

INCOME BEFORE INTEREST CHARGES 145,369 INTEREST CHARGES:

Interest on longterm debt 5,992 Allowance for debt funds used during construction . (2A423)

Amortization of debt discount, premium and expenses, net 3,337 Other Interest charges _ 249 Net Interest Charges 57,155 NET INCOME 88,214 DIVIDENDS ON PREFERRED STOCK 6,072 NET INCOME AFTER DIVIDENDS ON PREFERRED STOCK $ 82.142 ThWs statement reflects te usual accounting Practices of te Company on te basis of Interim figures and Is subject to audit and end of year adqustments.

This statement reflects the usual ALABAMA POWER COMPANY accounting practices of the Company BALANCE SHEET on the basis of Interim figures and CONSOLIDATED WITH ALABAMA POWER CAPITAL TRUSTS IV & V Is subject to audit and end of year (Stated nThousands o Dolars) adjustments.

At Al ASSETS Uarch 31. 2006, March 31, 2005 UTLJTY PLANT.

Plant inservice, at original cost .................... .. ...._ .._... $ $ . 15541,825 Less - Aooumuiated provision for depredation and amobmtion............. ... $ 6,997,337 i ',769,038

$ 9.454.488 Nuclear hAL at amortized ..................

.. .- $ 128,0 410.2006.

Constrction rukinvxoo ss.......... ........................... ...... W23,939 4783806

. S10.104,605 9,691.380 OTHER PROPERTYAND NVESTMENTS:

Equity Investments In . ..... ... $ 37,581 47,363 Investment inumconsoldated abidlarles..... $ 9.530 0.279 Nuclear deconunissioning busts..... ................................... $ 476.961 44S,277 Miscel anao .. ... _..

....... _ .... _ S. 33,138 62 227.771 WM~

$ 659,210 CURRENT ASSETS:

Cash . ......... _._ _....

...._.. ....... _._ 13,171 18,625 Spedial Deposits.. ..... . __ . .. _._

._.. ._........ ..... S 0 Tempoary cash hnestnts....................... - ..... . ...... .. .................... -.. 110400 Investment securrtes..... ................. ... .......... . ... . ............ . .

S o

Receivables .

Customer accounts rsoelvabW ...... .......... S M965 398.651 Other accounts and notes scehabe........_.... 43,230 Affilatad c panes. _. . .. ..... 59,130 518.338 Accunitated provisian br uncollectibe accounts . ...... . . ........... S (6,167)

Rel.idable Income laxes..... ... 11 3,408 27,444 Fossi el ,stoc,at average casL...__.... 134,612 84,087 Materials and suplies, at average osL....................... S Allowance hventbry..........._ 12,659 Prepayments -

Income taxes . .............

S' S

I, # O Other. ...... .. ._, I 94.38 Other current assets -SFAS 133. ..... II 24=68 61.171 Vacation paydeferred ......._._. _ . .. I 44.985 3B,494 51,1111O 0 1'.M6.040)

Debt expense. being . 11 .. . 38.92 29.60 Debt redemption evpense, being d.................................. S 09.576 tO7,347 Amated mi.oellaneous qawat p - .............. S 4 , 65 Prepaid pension cost ............. ............... $ 521.211 493,456 ReTtrya ssets........................ .. $ 8151.687 653,UO I llsce llaneous ........ _ _._._._._...______

__.____ S 107 .073 _ 4.068

$ I 23.02 TOTAL ASSETS __._. _._w~__.

_~___ S X 3 .646.76 $ 12,1S676.67 41261200M +

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

CAPITALIZATION AND U^ABIJTMS Al Al Mlarch 31, 2006 March 31, 2005 CAPITALIZATION: I II

$ 3,769.305 $ 3.605.473 Preferred stock .. ....... ... ..... ..... _ ...... S 465,047 464.948 Company obigated mandatorD redeemable preferred securities .... S 309.279 309.279 Long4tern debt .. ............. _ ____ _$ 4,356,731 3,35,527 e,900o362 8,3156227 CURRENT LIABBLITIES:

Preferred stock due or to be redeemed Mn one year .............. . ... S C16.

0 L 4errn debt due or lo be redeemed Mn oe ysar.................._ S 3M,645, r . 395.006 Notes payable to banks.... _..............._._._._._ . ........

. 0 Commercial paper ... ......... . . _.._ . .. _ .. . ....... . S 0 Accounts payable.

Affiliated ompanes. .............. ..... ......... 1 ,S 114.826 10925

$ 1J7,639 Other-_ ._-'_ ._.___. .___ 144,393 Customer deposits.___.......___._ . . _ ._ _.. ____._ $ t8,877 6t1460 Taxes accrued -

Federal and state Incom e ........ _.___. $ 124.120 37051 Other ..... . ... ..... _ . ......... .$; 60,451 -48,335 hnterest .cw_. _.

_._ ... _._...... . . ........ _............. $ 6S,383 61,744 xued tnterest Paybce bo Uced Subs......................................... S 8.370 8.119 Vacation pay acued............ . __ . ... . . .5 .. _ 3.6 3S.494 Miscellaneous .. ..... . ..... S 106598 65.290 947.995 DEFERRED CREDITS AND OTHER LIABLITIES:

Accumulated deferred hIcome taxes............................ S 2.06M M7

• 1,903,332 Accumulated deferred hwestment taxradlt..._ _ _._.__. $ 194.58 202.614 Asset Retirement Ob flonL........................ _ _ __ S. 453.450 390.051 Prepaid capacdty reve nets... s Reguatory liabilities .. ........ _ ._ .._. ...______ S 100.744 114,932 Accumulated miscelaneous peratftg paislons......................................... S. 6.541 Natural disaster reserve ......... _ ._ _ _ S2. 3.698 4.471 Miscellaneous .. ............... $ 824,310 782,161 S .628.957 3,41S 264 TOTAL CAPITALIZATION AND UBLmES......... ....... .... S __13.6J48.6 S 1_2676.467 farlthtvdetaffs. I '

4 26+20064

ALABAMA POWER COMPANY Internal Cash Flow for Joseph M. Farley Nuclear Power Station (Thousands of Dollars) 2005 2006 Actual Projections Net Income $ 532,184 $ 482,369 Less Dividends Paid 432,659 464,889 Retained Earnings 99,525 17,480 Adjustments:

Depreciation and Amortization 498,914 517,326 Deferred Income Taxes and Investment Tax Credits 106,765 38,369 Allowance for Equity Used During Construction (20281) (19.425)

Total Adjustments 585,398 636,270 Internal Cash Flow $ 684.923 S 553,750 Average Quarterly Cash Flow $ 1711231 $ 138438 Percentage Ownership In atl Operating Nuclear Units:

Joseph M.Farley Units 1 and 2 100%

Maxdmum Total ContingentLUability $ 3,00

i 2005 Annual Report ALABAMA POWER COMPANY ALABAMAAZ~ 4WAlways on M POWER A SOUTHERN COMPANY 100 years. Lighting the way.

CONTENTS Alabama Power Company 2005 Annual Report I

SUMMARY

2 LETTER TO INVESTORS 3 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 4 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 23 FINANCIAL STATEMENTS 30 NOTES TO FINANCIAL STATEMENTS 51 SELECTED FINANCIAL AND OPERATING DATA 53 DIRECTORS AND OFFICERS 54 CORPORATE INFORMATION

SUMMARY

Percent 2005 2004 Change Financial Highlights (in millions):

Operating revenues $4,648 $4,236 9.7 Operating expenses $3,634 $3,216 13.0 Net income after dividends on preferred stock $508 $481 5.6 Operating Data:

Kilowatt-hour sales (in millions):

Retail 55,684 54,244 2.7 Sales for resale - non-affiliates 15,443 15,483 (0.3)

Sales for resale - affiliates 5,735 7,234 (20.7)

Total 76,862 76,961 (0.1)

Customers served at year-end (in thousands) 1,403 1,385 1.3 Peak-hour demand (in megawatts) 11,162 10,938 2.0 Capitalization Ratios (percent):

Common stock equity 46.7 43.8 Preferred stock 5.7 5.6 Long-term Payable to affiliated trusts 3.8 3.8 Long-term debt 43.8 46.8 (Excluding long-term debt due within one year)

Return on Average Common Equity (percent) 13.72 13.53 1

2005 Letter to Investors As Alabama Power celebrates its centennial anniversary in 2006, we pause to reflect on how much our industry - and our world - have changed during the past 100 years. The one constant in that century of change has been the way we conduct our business - honestly and ethically.

The year 2005 was particularly challenging for Alabama Power, as we faced increasingly stringent environmental requirements, rising fuel costs and some of the most devastating storms in our company's, and country's, history.

I am proud to report that we met the challenges and produced outstanding results in virtually every area of the company. We again met our financial goals and kept our promises to our shareholders.

For the second year in a row, Alabama Power ranked number one in overall customer value. We continue to offer our customers prices at least 15 percent below the national average and a 99.9 percent reliability rate.

We also earned awards from the Edison Electric Institute for our response and assistance efforts following the devastation of Hurricanes Dennis and Katrina.

Our employees responded to Hurricane Dennis, which left 241,214 customers without power, with one of the most efficient turnarounds in our company's history. Power was restored to 99 percent of customers in just two days.

The following month, Hurricane Katrina, the second-worst storm in company history, left 636,891 customers without service and caused more damage to our transmission system than any storm experienced by the company. Crews restored service to 99 percent of our customers in eight days before leaving to assist in restoration efforts in Mississippi and Louisiana.

Our efforts to lessen our impact on the environment continued in 2005, as we announced more than $800 million in new environmental projects to significantly reduce emissions of nitrogen oxide, sulfur dioxide and mercury. Our 'Renew Our Rivers" program continued to receive national accolades and reached the milestone of removing 5 million pounds of debris from Alabama waterways.

Alabama Power was founded on the principle that nothing can be good for our company unless it is first good for those we serve - our shareholders, our customers, our employees and our communities.

This philosophy has served us well for 100 years, and I have every confidence that it will continue to guide us through the century ahead.

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Alabama Power Company We have audited the accompanying balance sheets and effectiveness of the Company's internal control over statements of capitalization of Alabama Power Company financial reporting. Accordingly, we express no such (the "Company") (a wholly owned subsidiary of Southern opinion. An audit also includes examining, on a test Company) as of December 31, 2005 and 2004, and the basis, evidence supporting the amounts and disclosures in related statements of income, comprehensive income, the financial statements, assessing the accounting common stockholder's equity, and cash flows for each of principles used and significant estimates made by the three years in the period ended December 31, 2005. management, as well as evaluating the overall financial These financial statements are the responsibility of the statement presentation. We believe that our audits Company's management. Our responsibility is to express provide a reasonable basis for our opinion.

an opinion on these financial statements based on our audits. In our opinion, the financial statements (pages 23 to

50) present fairly, in all material respects, the financial We conducted our audits in accordance with the position of Alabama Power Company at December 31, standards of the Public Company Accounting Oversight 2005 and 2004, and the results of its operations and its Board (United States). Those standards require that we cash flows for each of the three years in the period ended plan and perform the audit to obtain reasonable assurance December 31, 2005, in conformity with accounting about whether the financial statements are free of material principles generally accepted in the United States of misstatement. The Company is not required to have, nor America.

were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are (C Lf appropriate in the circumstances, but not for the purpose Birmingham, Alabama of expressing an opinion on the February 27, 2006 3

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Alabama Power Company 2005 Annual Report customer satisfaction surveys and reliability indicators OVERVIEW to evaluate the Company's results.

Business Activities Peak season equivalent forced outage rate (Peak Alabama Power Company (the Company) operates as a Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations vertically integrated utility providing electricity to retail during the months when generation needs are greatest.

customers within its traditional service area located within The rate is calculated by dividing the number of hours of the State of Alabama and to wholesale customers in the forced outages by total generation hours. Peak Season Southeast. EFOR performance excludes the impact of hurricanes and certain outage events caused by manufacturer defects.

Many factors affect the opportunities, challenges, and The 2005 Peak Season EFOR exceeded target levels risks of the Company's primary business of selling primarily due to equipment malfunctions at Plant Barry electricity. These factors include the ability to maintain a units 5 and 6, which resulted in unexpected outages.

stable regulatory environment, to achieve energy sales Transmission and distribution system reliability growth while containing costs, and to recover rising costs. performance is measured by the frequency and duration These costs include those related to growing demand, of outages. Performance targets for reliability are set increasingly stringent environmental standards, fuel internally based on historical performance, expected prices, and restoration following major storms. weather conditions, and expected capital expenditures.

The 2005 performance was above target on these On July 10, 2005 and August 29, 2005, Hurricanes reliability measures. Net income is the primary Dennis and Katrina, respectively, hit the coast of component of the Company's contribution to Southern Alabama and continued north through the state, causing Company's earnings per share goal. The Company's significant damage in parts of the Company's service 2005 results compared with its targets for each of these territory including the Company's distribution and indicators are reflected in the following chart.

transmission facilities. Approximately 241,000 and 637,000, respectively, of the Company's 1.4 million Key 2005 2005 customers were without electrical service immediately Performance Target Actual after Hurricanes Dennis and Katrina. Indicator Performance Performance Customer Top quartile in In 2005, the Company successfully completed a retail Satisfaction customer surveys Top quartile rate proceeding with the Alabama Public Service Peak Season 2.75% or less 3.83%

Commission (PSC) to recover the costs associated with EFOR Income $0mlo $8iin these storms and to replenish the Company's natural Net Income $501 million $508 million disaster reserve. In other actions, the Alabama PSC also approved a higher fuel recovery rate and amended the See RESULTS OF OPERATIONS herein for additional information on the Company's financial Company's Rate Stabilization and Equalization Plan (Rate performance. The strong financial performance achieved RSE) to use forward-looking test periods. These in 2005 reflects the focus that management places on these regulatory actions are expected to assist the Company's indicators, as well as the commitment shown by the continued focus on providing reliable electrical service to Company's employees in achieving or exceeding customers while maintaining a stable financial position. management's expectations.

Key Performance Indicators Earnings In striving to maximize shareholder value while The Company's financial performance remained strong in providing cost effective energy to customers, the 2005 despite the challenges of major hurricane Company continues to focus on several key indicators. restorations and rising fuel costs. The Company's net These indicators include customer satisfaction, plant income after dividends on preferred stock of $508 million availability, system reliability, and net income. The in 2005 increased $27 million (5.6 percent) over the prior Company's financial success is directly tied to the year. This improvement is primarily due to retail and satisfaction of its customers. Key elements of ensuring wholesale revenue growth, increases in transmission customer satisfaction include outstanding service, high revenues, partially offset by higher non-fuel operating reliability, and competitive prices. Management uses expenses.

4

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report The Company's 2004 net income after dividends on Amount preferred stock was $481 million, representing an $8 2005 2004 2003 million (1.8 percent) increase from the prior year. This (in millions) improvement was primarily due to retail sales growth, Retail -- prior year $3,293 $3,051 $2,951 increases in other revenues, and lower interest expense, Change in -

partially offset by higher non-fuel operating expenses.

Base rates 35 41 51 The Company's 2003 net income after dividends on Sales growth 50 48 68 preferred stock was $473 million, representing a $12 Weather 18 12 (61) million (2.5 percent) increase from the prior year. This Fuel cost recovery improvement was due primarily to higher retail sales, and other 225 141 42 higher sales for resale, increases in customer fees revenues, Retail -- current year 3,621 3,293 3,051 and lower interest expense, partially offset by higher non- Sales for resale --

fuel operating expenses. Non-affiliates 551 484 488 Affiliates 289 308 277 The ROE for 2005 was 13.72 percent compared to Total sales for resale 840 792 765 13.53 percent in 2004 and 13.75 percent in 2003. Other operating revenues 187 151 144 Total operating revenues $4,648 $4,236 $3,960 RESULTS OF OPERATIONS Percent change 9.7% 7.0% 6.7%

A condensed income statement is as follows: Retail revenues in 2005 were $3.6 billion. Revenues Increase (Decrease) increased $328 million (10.0 percent) in 2005, $242 Amount From Prior Year million (7.9 percent) in 2004, and $100 million (3.4 2005 2005 2004 2003 percent) in 2003. These increases were primarily due to (in millions) increased fuel revenue and retail base rate increases of 0.5 Operating revenues $4,648 $412 $276 $250 percent in April 2005, 1.0 percent in January 2005, 0.8 Fuel 1,457 271 119 98 percent in July 2004, and 2.6 percent in July 2003. See Purchased power 457 44 98 66 FUTURE EARNINGS POTENTIAL - "PSC Matters" Other operation herein and Note 3 to the financial statements under "Retail and maintenance 1,044 97 26 67 Regulatory Matters" for additional information.

Depreciation and amortization 427 1 13 15 Fuel rates billed to customers are designed to fully Taxes other than recover fluctuating fuel and purchased power costs over a income taxes 249 6 14 11 period of time. Fuel revenues generally have no effect on Total operating expenses 3,634 419 270 257 net income because they represent the recording of Operating income 1,014 (7) 6 (7) revenues to offset fuel and purchased power expenses.

Total other income and (expense) (197) 6 30 20 See FUTURE EARNINGS POTENTIAL - "PSC Matters Income taxes 285 (29) 23 (2) - Retail Fuel Cost Recovery" herein and Note 3 to the Net income 532 28 13 15 financial statements under "Retail Regulatory Matters -

Dividends on preferred stock 24 1 5 3 Fuel Cost Recovery" for additional information.

Net income after dividends onpreferredstock $ 508 $ 27 $ 8 $ 12 Sales for resale to non-affiliates are predominantly unit power sales under long-term contracts to Florida Revenues utilities. Revenues from unit power sales contracts have both capacity and energy components. Capacity revenues Operating revenues for 2005 were $4.6 billion, reflecting a reflect the recovery of fixed costs and a return on

$412 million increase from 2004, The following table investment under the contracts. Energy is generally sold summarizes the principal factors that have affected at variable cost. These capacity and energy components operating revenues for the past three years: of the unit power contracts were as follows:

S

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report 2005 2004 2003 million increase from rent from associated companies primarily related to leased transmission facilities.

(in thousands)

Unit power -

Capacity $147,609 $134,615 $130,022 Other operating revenues in 2004 increased $7.0 Energy 169,080 146,809 145,342 million (4.9 percent) from 2003 due to an increase of $7.7 Total $316.689 $281,424 $275.364 million in revenues from gas-fueled co-generation steam facilities -- primarily as a result of higher gas prices - and No significant declines in the amount of capacity are a $2.4 million increase in revenues from rent from electric scheduled until the termination of the contracts in 2010. property offset by a $2.0 million decrease in transmission revenues.

Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity Other operating revenues in 2003 increased $47 sales are made at market-based rates that generally provide million (48.6 percent) from 2002 due to an increase of a margin above the Company's variable cost to produce $19.4 million in revenues from gas-fueled co-generation the energy. Revenues associated with other power sales to steam facilities -- primarily as a result of higher gas prices non-affiliates were as follows: -- and a $14.8 million increase in revenues from Alabama PSC approved fees charged to customers for connection, 2005 2004 2003 reconnection, and collection when compared to the same (in thousands) period in 2002.

Other power sales -

Capacity and other $116,181 $ 90,673 $ 96,263 Since co-generation steam revenues are generally Variable cost of energy 118,537 111,742 115,829 offset by fuel expense, these revenues did not have a Total $234,718 $202,415 $212,092 significant impact on earnings.

Revenues from sales to affiliated companies within the Energy Sales Southern Company electric system, as well as purchases of energy, will vary from year to year depending on demand Changes in revenues are influenced heavily by the volume and the availability and cost of generating resources at of energy sold each year. Kilowatt-hour (KWH) sales for each company. These affiliated sales and purchases are 2005 and the percent change by year were as follows:

made in accordance with the Intercompany Interchange Contract (IIC) as approved by the Federal Energy KWH Percent Change Regulatory Commission (FERC). In 2005, sales for resale 2005 2005 2004 2003 revenues decreased $19.4 million primarily due to a 20.7 (millions) percent decrease in kilowatt-hour sales to affiliates as a result of a decrease in the availability of the Company's Residential 18,074 4.1% 2.4% (2.5)%

generating resources due to an increase in customer Commercial 14,062 1.7 2.8 0.7 demand within the Company's service territory. Sales for Industrial 23,350 2.2 5.8 2.3 resale revenues increased $31.1 million in 2004 due to Other 198 0.2 (2.4) (1.1) increases in fuel-related expenses. Sales for resale Total retail 55,684 2.7 3.9 0.3 revenues increased $89.1 million in 2003 due to increased Sales for resale -

capacity payments received from affiliates. Excluding the Non-affiliates 15,443 (0.3) (9.4) 9.9 capacity revenues, these transactions do not have a Affiliates 5,735 (20.7) (23.2) 6.5 significant impact on earnings since the energy is generally Total 76,862 (0.1) (2.2) 2.9 sold at marginal cost and energy purchases are generally offset by energy revenues through the Company's energy Retail energy sales in 2005 were 2.7 percent higher cost recovery clause. than 2004 despite interruptions during Hurricanes Dennis and Katrina. Energy sales in the residential sector led the Other operating revenues in 2005 increased $35.0 growth with a 4.1 percent increase in 2005 due primarily million (23.2 percent) from 2004 due to an increase of $20 to increased demand. Commercial sales increased 1.7 million in revenues from gas-fueled co-generation steam percent in 2005 primarily due to continued customer facilities primarily as a result of higher gas prices, and growth. Industrial sales increased 2.2 percent during the

$7.7 million increase in transmission revenues and a $3.9 6

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report year with chemical, primary metals and automotive amortization expense increased $13 million (3.1 percent) leading the growth in industrial energy consumption. In primarily due to an increase in utility plant in service.

addition, the paper sector chose to purchase rather than self-generate which contributed to increased sales. The total operating expenses in 2003 were approximately $3.0 billion, an increase of $257 million (9.6 Energy sales in the residential sector grew by 2.4 percent) over the previous year. This increase is mainly due percent in 2004 primarily due to continued customer to a $98 million increase in fuel expense primarily related growth and a return to normal summer temperatures. to an.increase in the average cost of natural gas and coal. In Commercial sales increased 2.8 percent in 2004 primarily addition, purchased power expenses increased a total of $66 due to continued customer growth. Industrial sales million, maintenance expense increased $30 million rebounded 5.8 percent during the year with primary primarily related to transmission and distribution overhead metals, chemical, and paper sectors leading the growth. lines, and depreciation and amortization expense increased

$15 million.

In 2003, residential energy sales experienced a 2.5 percent decrease over the prior year and total retail energy Fuel and PurchasedPower Expenses sales grew by 0.3 percent primarily as a result of milder-than-normal summer temperatures compared to the Fuel costs constitute the single largest expense for the previous year. Although retail sales to industrial Company. The mix of fuel sources for generation of customers increased 2.3 percent in 2003 and 3.1 percent in electricity is determined primarily by demand, the unit 2002, overall sales to industrial customers remained cost of fuel consumed, and the availability of fossil and depressed due to the effect of sluggish economic nuclear generating units and hydro generation. The conditions. amount and sources of generation and the average cost of fuel per net KWH generated and the average cost of Assuming normal weather, sales to retail customers purchased power were as follows:

are projected to grow approximately 1.3 percent annually on average during 2006 through 2010. 2005 2004 2003 Total OperatingExpenses Total generation (billions of KWHs) 71 70 72 In 2005 total operating expenses increased $419 million Sources of generation (13.0 percent) to $3.6 billion. This change from 2004 (percent) --

includes an increase in fuel expense of $271 million (22.8 Coal 67 65 64 percent) related to higher natural gas and coal prices. In Nuclear 19 19 19 addition, purchased power expenses increased $45 million Hydro 6 6 8 (10.8 percent) primarily due to a 17.9 percent increase in Gas 8 10 9 purchased power prices. Maintenance expenses increased Average cost of fuel per net

$48 million primarily from transmission and distribution KWH generated (cents) 2.02 1.69 1.54 expense. These increases are mainly a result of the Average cost of purchased Alabama PSC accounting order to recognize the previously power per net KWH (cents) 6.49 4.79 3.61 deferred costs of Hurricane Ivan storm damage restoration and to partially replenish a balance in the natural disaster Fuel expense increased 22.8 percent In 2005 primarily reserve. See Note 3 to the financial statements under due to an increase in the average cost of fuel as a result of "Retail Regulatory Matters - Natural Disaster Cost a 26.5 percent increase in the average price of natural gas Recovery" for additional information. and an 18.5 percent increase in the average coal price.

Fuel expense increased 11.1 percent in 2004 primarily due Total operating expenses in 2004 grew $270 million to a 30.5 percent increase in the average price of natural (9.2 percent) to $3.2 billion. This increase over the gas and a 3.1 percent increase in the average price of coal.

previous year was primarily related to an increase in natural Fuel expense increased 10.1 percent in 2003 due to a 58.3 gas and coal prices. In addition, purchased power expenses percent increase in the average price of natural gas and a increased $98 million (31.0 percent) primarily due to a 71.7 2.2 percent increase in the average price of coal.

percent increase in energy purchased, while purchased power prices decreased by 1.9 percent. Depreciation and 7

V MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Purchased power consists of purchases from affiliates amount of construction work in progress over the prior in the Southern Company electric system and non- year. AFUDC also increased $1.4 million (12.8 affiliated companies. Purchased power transactions percent) in 2003 due to an increase in the applicable among the Company and its affiliates will vary from AFUDC rate. See Note I to the financial statements period to period depending on demand and the availability under "AFUDC" for additional information.

and variable production cost of generating resources at each company. Purchased power from non-affiliates In 2005 interest expense, net of amounts capitalized increased $2.5 million (1.0 percent) in 2005. This was increased $3.8 million to $197.4 million due to an increase due to a 14.3 percent increase in purchased power prices in average debt outstanding during the year. This reversed over the previous year. In 2004, purchased power from the trend of the past two years when refinancing activities non-affiliates increased $75 million (68 percent) due to a resulted in $20.7 million (9.7 percent) and $11.4 million 71.7 percent increase in energy purchased offset by a 1.9 (5.1 percent) decreases in 2004 and 2003, respectively.

percent decrease in purchased power prices compared to 2003. In 2003, purchased power from non-affiliates Effects of Inflation increased $20 million (22 percent) due to a 19.3 percent increase in price and a 9.5 percent increase in energy The Company is subject to rate regulation that is based on purchased when compared to 2002. the recovery of costs. When historical costs are included, or when inflation exceeds projected costs used, in rate A significant upward trend in the cost of coal and regulation, the effects of inflation can create an economic natural gas has emerged since 2003, and volatility in these loss since the recovery of costs could be in dollars that markets is expected to continue. Increased coal prices have less purchasing power. The inflation rate has been have been influenced by a worldwide increase in demand relatively low in recent years and any adverse effect of as a result of rapid economic growth in China as well as by inflation on the Company has not been substantial. Any increases in mining costs. Higher natural gas prices in the recognition of inflation by regulatory authorities is United States are the result of increased demand and reflected in the rate of return allowed in the Company's slightly lower gas supplies despite increased drilling approved electric rates.

activity. Natural gas supply interruptions, such as those caused by the 2004 and 2005 hurricanes, result in an FUTURE EARNINGS POTENTIAL immediate market response; however, the long-term impact of this price volatility may be reduced by imports General of natural gas and liquefied natural gas. Fuel expenses, including purchased power, are offset by fuel revenues The Company operates as a vertically integrated utility through the Company's energy cost recovery clause and providing electricity to retail customers within its generally have no effect on net income. The Company traditional service area located in the State of Alabama continuously monitors the under/over recovered balance and to wholesale customers in the Southeast. Prices for and files for a revised fuel rate when management deems electricity provided by the Company to retail customers appropriate. See Future Earnings Potential - "PSC Matters are set by the Alabama PSC under cost-based regulatory

- Retail Fuel Cost Recovery" herein and Note 3 to the principles. Prices for electricity relating to jointly owned financial statements under "Retail Regulatory Matters - generating facilities, interconnecting transmission lines, Fuel Cost Recovery" for additional information. and the exchange of electric power are set by the FERC.

Retail rates and earnings are reviewed and may be Other Expenses adjusted periodically within certain limitations. See ACCOUNTING POLICIES - "Application of Critical Depreciation and amortization expense increased 0.1 Accounting Policies and Estimates - Electric Utility percent in 2005, 3.1 percent in 2004, and 3.6 percent in Regulation" herein and Note 3 to the financial statements 2003. These increases reflect additions to property, plant, under "FERC Matters" and "Retail Regulatory Matters" and equipment. for additional information about these and other regulatory matters.

Allowance for equity funds used during construction (AFUDC) increased $4.1 million (25.6 The results of operations for the past three years are percent) and $3.5 million (28.2 percent) in 2005 and not necessarily indicative of future earnings potential.

2004, respectively, primarily due to increases in the The level of the Company's future earnings depends on 8

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report numerous factors that affect the opportunities, challenges, on the date of the alleged violation. An adverse outcome and risks of the Company's primary business of selling in this matter could require substantial capital expenditures electricity. These factors include the Company's ability to that cannot be determined at this time and could possibly maintain a stable regulatory environment that continues to require payment of substantial penalties. This could affect allow for the recovery of all prudently incurred costs. future results of operations, cash flows, and possibly Future earnings for the electricity business in the near financial condition if such costs are not recovered through term will depend, in part, upon growth in energy sales, regulated rates.

which is subject to a number of factors. These factors include weather, competition, new energy contracts with In December 2002 and October 2003, the EPA issued neighboring utilities, energy conservation practiced by final revisions to its NSR regulations under the Clean Air customers, the price of electricity, the price elasticity of Act. A coalition of states and environmental demand, and the rate of economic growth in the organizations filed petitions for review of these Company's service area. regulations. On June 24, 2005, the U.S. Court of Appeals for the District of Columbia Circuit upheld, in part, the Environmental Matters EPA's December 2002 revisions to its NSR regulations, which included changes to the regulatory exclusions and New Source Review Actions methods of calculating emissions increases. However, the court vacated portions of those revisions, including' those In November 1999, the Environmental Protection Agency addressing the exclusion of certain pollution control (EPA) brought a civil action in the U.S. District Court for projects. The October 2003 revisions, which clarified the the Northern District of Georgia against the Company, scope of the existing Routine Maintenance, Repair and alleging that the Company had violated the New Source Replacement exclusion, have been stayed by the Court of Review (NSR) provisions of the Clean Air Act and related Appeals pending its review of the rules. On October 20, state laws with respect to coal-fired generating facilities at 2005, the EPA also published a proposed rule clarifying the Company's Plants Miller, Barry, and Gorgas. The the test for determining when an emissions increase EPA concurrently issued to the Company a notice of subject to the NSR requirements has occurred. The violation relating to these specific facilities, as well as impact of these revisions and proposed rules will depend Plants Greene County and Gaston. In early 2000, the EPA on adoption of the final rules by the EPA and the State of filed a motion to amend its complaint to add the violations Alabama's implementation of such rules, as well as the alleged in its notice of violation. The civil action requests outcome of any additional legal challenges, and, therefore, penalties and injunctive relief, including an order cannot be determined at this time.

requiring the installation of the best available control:

technology at the affected units. The Northern District of Carbon Dioxide Litigation Georgia granted the Company's motion to dismiss for lack of jurisdiction in Georgia. The EPA refiled its claims In July 2004, attorneys general from eight states, each against the Company in the U.S. District Court for the outside of Southern Company's service territory, and the Northern District of Alabama. On June 3, 2005, the U.S. corporation counsel for New York City filed a complaint District Court for the Northern District of Alabama issued in the U.S. District Court for the Southern District of New a decision in favor of the Company on two primary legal York against Southern Company and four other electric issues in the case; however, the decision does not resolve power companies. A nearly identical complaint was filed the case, nor does it address other legal issues associated by three environmental groups in the same court. The complaints allege that the companies' emissions of carbon with the EPA's allegations. In accordance with a separate court order, the Company and the EPA are currently dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Under participating in mediation with respect to the EPA's common law public and private nuisance theories, the claims. plaintiffs seek a judicial, order (1) holding each defendant jointly and severally liable for creating, contributing to, The Company believes that it complied with applicable and/or maintaining global warming and (2) requiring each laws and the EPA regulations and interpretations in effect at of the defendants to cap its emissions of carbon dioxide the time the work in question took place. The Clean Air Act and then reduce those emissions by a specified percentage authorizes maximum civil penalties of $25,000 to $32,500 each year for at least a decade. Plaintiffs have not, per day, per violation at each generating unit, depending however, requested that damages be awarded in 9

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report connection with their claims. Southern Company believes many areas of the Company's operations; however,,the these claims are without merit and notes that the full impact of any such changes cannot be determined complaint cites no statutory or regulatory basis for the at this time.

claims. In September 2005, the U.S. District Court for the Southern District of New York granted Southern Air Quality Company's and the other defendants' motions to dismiss these cases. The plaintiffs filed an appeal to the U.S. Compliance with the Clean Air Act and resulting Court of Appeals for the Second Circuit on October 19, regulations has been and will continue to be a 2005. The ultimate outcome of these matters cannot be significant focus for the Company. Through 2005, the determined at this time. Company had spent approximately $745 million in reducing sulfur dioxide (SO2 ) and nitrogen oxide (NOJ)

EnvironmentalStatutes and Regulations emissions and in monitoring emissions pursuant to the Clean Air Act. Additional controls have been General announced and are currently being installed at several plants to further reduce SO2 and NO, emissions, The Company's operations are subject to extensive maintain compliance with existing regulations, and to regulation by state and federal environmental agencies meet new requirements.

under a variety of statutes and regulations governing environmental media, including air, water, and land Approximately $594 million of these expenditures resources. Applicable statutes include the Clean Air Act; related to reducing NO, emissions pursuant to state and the Clean Water Act; the Comprehensive Environmental federal requirements in connection with the EPA's one-Response, Compensation, and Liability Act; the Resource hour ozone standard and the 1998 regional NO, Conservation and Recovery Act; the Toxic Substances reduction rules. In 2004, the regional NO. reduction Control Act; the Emergency Planning & Community rules were implemented for the northern two-thirds of Right-to-Know Act, and the Endangered Species Act. Alabama. See Note 3 to the financial statements under Compliance with these environmental requirements "Retail Regulatory Matters" for information regarding involves significant capital and operating costs, a major the Company's recovery of costs associated with portion of which is expected to be recovered through environmental laws and regulations.

existing ratemaking provisions. Through 2005, the Company had invested approximately $961 million in In 2005, the EPA revoked the one-hour ozone capital projects to comply with these requirements, with standard and published the final set of rules for annual totals of $256 million, $177 million, and $100 implementation of the new, more stringent eight-hour million for 2005, 2004, and 2003, respectively. Over the ozone standard. The area within the Company's service next decade, the Company expects that capital area that has been designated as nonattainment under the expenditures to assure compliance with existing and new eight-hour ozone standard includes Jefferson and Shelby regulations could exceed an additional $2.2 billion, Counties, near Birmingham. State implementation plans, including $285 million, $426 million, and $406 million including new emission control regulations necessary to for 2006, 2007, and 2008, respectively. Because the bring those areas into attainment are required for most Company's compliance strategy is impacted by changes areas by June 2007. These state implementation plans to existing environmental laws and regulations, the cost, could require further reductions in NO, emissions from availability, and existing inventory of emission power plants.

allowances, and the Company's fuel mix, the ultimate outcome cannot be determined at this time.

Environmental costs that are known and estimable at this In November 2005, the State of Alabama, through the time are included in capital expenditures discussed under Alabama Department of Environmental Management, FINANCIAL CONDITION AND LIQUIDITY - "Capital submitted a request to the EPA to redesignate the Requirements and Contractual Obligations" herein. Birmingham eight-hour ozone non-attainment area to attainment for the standard. On January 25, 2006, the Compliance with possible additional federal or state EPA published a proposal in the Federal Register to legislation or regulations related to global climate approve the redesignation request. If ultimately approved change, air quality, or other environmental and health by the EPA, the area would be designated to be in concerns could also significantly affect the Company. attainment. The final outcome of this matter cannot now New environmental legislation or regulations, or be determined.

changes to existing statutes or regulations could affect 10

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report During 2005, the EPA's fine particulate matter provides for an emissions allowance trading market.

nonattainment designations became effective for The Company anticipates that emission controls several areas within the Company's service area, and installed to achieve compliance with the Clean Air the EPA proposed a rule for the implementation of the Interstate Rule and the eight-hour ozone and fine-fine particulate matter standard. The EPA plans to particulate standards will also result in mercury finalize the proposed implementation rule in 2006. emission reductions. However, the long-term State plans for addressing the nonattainment capability of emission control equipment to reduce designations are required by April 2008 and could mercury emissions is still being evaluated, and the require further reductions in SO2 and NO, emissions installation of additional control technologies may be from power plants. The EPA has also published required.

proposed revisions to lower the levels of particulate matter currently allowed. The impacts of the eight-hour ozone standard, the fine particulate matter designations, the Clean Air The EPA issued the final Clean Air Interstate Rule Interstate Rule, the Clean Air Visibility Rule, and the on March 10, 2005. This cap-and-trade rule addresses Clean Air Mercury Rule on the Company will depend SO2 and NO, emissions from power plants that were on the development and implementation of rules at the found to contribute to nonattainment of the eight-hour state level. States implementing the Clean Air Mercury ozone and fine particulate matter standards in Rule and the Clean Air Interstate Rule, in particular, downwind states. Twenty-eight eastern states, have the option not to participate in the national cap-including the State of Alabama, are subject to the and-trade programs and could require reductions requirements of the rule. The rule calls for additional greater than those mandated by the federal rules. Such reductions of NO, and/or SO2 to be achieved in two impacts will also depend on resolution of pending legal phases, 2009/2010 and 2015. These reductions will be challenges to the Clean Air Interstate Rule, the Clean accomplished by the installation of additional emission Air Mercury Rule, and a related petition from the State controls at the Company's coal-fired facilities or by the of North Carolina under Section 126 of the Clean Air purchase of emission allowances from a cap-and-trade Act, also related to the interstate transport of air program. pollutants. Therefore, the full impacts of these regulations on the Company cannot be determined at The Clean Air Visibility Rule (formerly called the this time. The Company has developed and continually Regional Haze Rule) was finalized on July 6, 2005. updates a comprehensive environmental compliance The goal of this rule is to restore natural visibility strategy to comply with the continuing and new conditions in certain areas (primarily national parks and environmental requirements discussed above. As part wilderness areas) by 2064. The rule involves the of this strategy, the Company plans to install additional application of Best Available Retrofit Technology SO2 , NO,, and mercury emission controls within the (BART) requirements and a review each decade, next several years to assure continued compliance with beginning in 2018, of progress toward the goal. BART applicable air quality requirements.

requires that sources that contribute to visibility impairment implement additional emission reductions, Water Quality if necessary, to make progress toward remedying current visibility concerns. For power plants, the Clean In July 2004, the EPA published final rules under the Air Visibility Rule allows states to determine that the Clean Water Act for the purpose of reducing Clean Air Interstate Rule satisfies BART requirements impingement and entrainment of fish and fish larvae at for S02 and NO,. However, additional requirements power plants' cooling water intake structures. The new could be imposed. By December 17, 2007, states must rules require baseline biological information and, submit implementation plans that contain emission perhaps, installation of fish protection technology near reduction strategies for implementing BART some intake structures at existing power plants.

requirements and for achieving sufficient and reasonable progress toward the goal. The full impact of these new rules will depend on the results of studies and analyses performed as part of On March 15, 2005, the EPA announced the final the rules' implementation and the actual requirements Clean Air Mercury Rule, a cap-and-trade program for established by state regulatory agencies, and therefore, the reduction of mercury emissions from coal-fired cannot now be determined.

plants. The rule sets caps on mercury emissions to be implemented in two phases, 2010 and 2018, and 11

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report EnvironmentalRemediation approval must be obtained with respect to a market-based contract with an affiliate.

The Company must comply with other environmental laws and regulations that cover the handling and In December 2004, the FERC initiated a proceeding disposal of waste and release of hazardous substances. to assess Southern Company's generation dominance Under these various laws and regulations, the Company within its retail service territory. The ability to charge could incur substantial costs to clean up properties. market-based rates in other markets is not an issue in The Company conducts studies to determine the extent that proceeding. In February 2005, Southern Company of any required cleanup and has recognized in its submitted responsive information. In February 2006, financial statements the costs to clean up known sites. the FERC suspended the proceeding to allow the parties Amounts for cleanup and ongoing monitoring costs to conduct settlement discussions. Any new market-were not material for any year presented. The based rate transactions in its retail service territory Company may be liable for some or all required entered into after February 27, 2005 are subject to cleanup costs for additional sites that may require refund to the level of the default cost-based rates, environmental remediation. pending the outcome of the proceeding. The impact of such sales to the Company through December 31, 2005 Global Climate Issues is not expected to exceed $3.6 million. The refund period covers 15 months. In the event that the FERC's Domestic efforts to limit greenhouse gas emissions default mitigation measures for entities that are found have been spurred by international discussions to have market power are ultimately applied, the surrounding the Framework Convention on Climate Company may be required to charge cost-based rates Change, and specifically the Kyoto Protocol, which for certain wholesale sales in the Southern Company proposes constraints on the emissions of greenhouse retail service territory, which may be lower than gases for a group of industrialized countries. The Bush negotiated market-based rates. The final outcome of Administration has not supported U.S. ratification of this matter will depend on the form in which the final the Kyoto Protocol or other mandatory carbon dioxide methodology for assessing generation market power reduction legislation; however, in 2002, it did announce and mitigation rules may be ultimately adopted and a goal to reduce the greenhouse gas intensity of the cannot be determined at this time.

U.S., the ratio of greenhouse gas emissions to the value of U.S. economic output, by 18 percent by 2012. A In addition, in May 2005, the FERC started an year later, the Department of Energy (DOE) announced investigation to determine whether Southern Company the Climate VISION program to support this goal. satisfies the other three parts of the FERC's market-based Energy-intensive industries, including electricity rate analysis: transmission market power, barriers to entry, generation, are the initial focus of this program. and affiliate abuse or reciprocal dealing. The FERC Southern Company is involved in the development of a established a new refund period related to this expanded voluntary electric utility sector climate change initiative investigation. Any and all new market-based rate in partnership with the government. In a memorandum transactions both inside and outside Southern Company's of understanding signed in December 2004 with the retail service territory involving any Southern Company DOE under Climate VISION, the utility sector pledged subsidiary, including the Company, will be subject to to reduce its greenhouse gas emissions rate by 3 percent refund to the extent the FERC orders lower rates as a result to 5 percent by 2010 - 2012. The Company is of this new investigation, with the 15-month refund period continuing to evaluate future energy and emission profiles relative to the Climate VISION program and is beginning July 19, 2005. The impact of such sales to the analyzing voluntary programs to support the industry Company through December 31, 2005, is not expected to initiative. exceed $8.9 million, of which $2.6 million relates to sales inside the retail service territory discussed above. The FERC Matters FERC also directed that this expanded proceeding be held in abeyance pending the outcome of the proceeding on the Market-BasedRate A uthority IIC discussed below.

The Company has authorization from the FERC to sell The Company believes that there is no meritorious power to non-affiliates at market-based prices. The basis for this proceeding and is vigorously defending itself Company also has FERC authority to make short-term in this matter. However, the final outcome of this matter, opportunity sales at market rates. Specific FERC including any remedies to be applied in the event of an 12

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report adverse ruling in this proceeding, cannot now be prospectively to interconnection agreements.

determined. Subsidiaries of Tenaska, Inc., as counterparties to two previously executed interconnection agreements with Intercompany Interchange Contract the Company, have filed complaints at the FERC requesting that the FERC modify the agreements and The Company's generation fleet in its retail service that the Company refund a total of $11 million territory is operated under the IIC, as approved by the previously paid for interconnection facilities, with FERC. In May 2005, the FERC initiated a new interest. These proceedings are still pending at the proceeding to examine (1) the provisions of the IIC among FERC. The Company has also received similar requests from other entities totaling approximately $7 Alabama Power, Georgia Power, Gulf Power, Mississippi million. The Company has opposed all such requests.

Power, Savannah Electric, Southern Power, and SCS, as The impact of Order 2003 and its subsequent rehearings agent, under the terms of which the power pool of on the Company and the final results of these matters Southern Company is operated, and, in particular, the cannot be determined at this time.

propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have Transmission violated the FERC's standards of conduct applicable to utility companies that are transmission providers, and (3) In December 1999, the FERC issued its final rule on whether Southern Company's code of conduct defining Regional Transmission Organizations (RTOs). Since Southern Power as a "system company" rather than a that time, there have been a number of additional "marketing affiliate" is just and reasonable. In connection proceedings at the FERC designed to encourage further with the formation of Southern Power, the FERC voluntary formation of RTOs or to mandate their authorized Southern Power's inclusion in the IIC in 2000. formation. However, at the current time, there are no The FERC also previously approved Southern Company's active proceedings that would require the Company to code of conduct. The FERC order directs that the participate in an RTO. Current FERC efforts that may administrative law judge who presided over a proceeding potentially change the regulatory and/or operational involving approval of PPAs between Southern Power, structure of transmission include rules related to the Georgia Power, and Savannah Electric be assigned to standardization of generation interconnection, as well preside over the hearing in this proceeding and that the as an inquiry into, among other things, market power by vertically integrated utilities. See "Market-Based Rate testimony and exhibits presented in that proceeding be Authority" and "Generation Interconnection preserved to the extent appropriate. Hearings are Agreements" herein for additional information. The scheduled for September 2006. Effective July 19,2005, final outcome of these proceedings cannot now be revenues from transactions under the IIC involving any determined. However, the Company's financial Southern Company subsidiaries, including the Company, condition, results of operations and cash flows could be are subject to refund to the extent the FERC orders any adversely affected by future changes in the federal changes to the IIC. regulatory or operational structure of transmission.

The Company believes that there is no meritorious Hydro Relicensing basis for this proceeding and is vigorously defending itself in this matter. However, the final outcome of this In July 2005, the Company filed two applications with the matter, including any remedies to be applied in the FERC for new 50-year licenses for the Company's seven event of an adverse ruling in this proceeding, cannot hydroelectric developments on the Coosa River (Weiss, now be determined. Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin) and for the Lewis Smith and Bankhead developments on Generation Interconnection Agreements the Warrior River. The FERC licenses for all of these nine projects expire in 2007.

In July 2003, the FERC issued its final rule on the standardization of generation interconnection In 2006, the Company will initiate the process of agreements and procedures (Order 2003). Order 2003 developing a relicensing application for the Martin shifts much of the financial burden of new transmission hydroelectric project located on the Tallapoosa River.

investment from the generator to the transmission The current Martin license will expire in 2013.

provider. The FERC has indicated that Order 2003, which was effective January 20, 2004, is to be applied 13

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Upon or after the expiration of each license, the The Company's retail rates, approved by the United States Government, by act of Congress, may take Alabama PSC, also provide for adjustments to over the project or the FERC may relicense the project recognize the placing of new generating facilities into either to the original licensee or to a new licensee. The retail service and the recovery of retail costs associated FERC may grant relicenses subject to certain requirements with certificated PPAs under Rate Certificated New that could result in additional costs to the Company. The Plant (CNP). In October 2004, the Alabama PSC final outcome of these matters cannot be determined at amended Rate CNP to also allow for the recovery of the this time. Company's retail costs associated with environmental laws, regulations, or other such mandates. The rate Nuclear Relicensing mechanism began operation in January 2005 and provides for the recovery of these costs pursuant to a The Company filed an application with the Nuclear factor that is calculated annually. Environmental costs Regulatory Commission (NRC) in September 2003 to to be recovered include operation and maintenance extend the operating license for Plant Farley for an expenses, depreciation, and a return on invested capital.

additional 20 years. In May 2005, the NRC granted the Retail rates increased approximately 1.0 percent in Company a 20-year extension of the operating license January 2005 and 1.2 percent in January 2006. It is for both units at Plant Farley. As a result of the license currently anticipated that retail rates will increase extension, amounts previously contributed to the approximately 0.5 percent in 2007. In conjunction with external trust are currently projected to be adequate to the Alabama PSC's approval of this rate mechanism, meet the decommissioning obligations. Therefore, in the Company agreed to a moratorium through 2006 on June 2005, the Alabama PSC approved the Company's retail rate increases under Rate RSE.

request to suspend, effective January 1, 2005, the inclusion in its annual cost of service of $18 million in Effective July 2003, the Company's retail rates decommissioning costs and to also suspend the were adjusted by approximately 2.6 percent under Rate associated obligation to make semi-annual CNP as a result of two new certificated PPAs that contributions to the external trust. See Note 1 to the began in June 2003. An additional increase of 0.8 financial statements under "Nuclear Decommissioning" percent in retail rates, or $25 million annually, was for additional information. effective July 2004 under Rate CNP for new certificated PPAs. In April 2005, an adjustment to Rate PSC Matters CNP decreased retail rates by approximately 0.5 percent, or $19 million annually. The projected annual Retail Rate Adjustments true-up adjustment to be effective in April 2006 is expected to increase retail rates by 0.5 percent, or $19 In October 2005, the Alabama PSC approved a revision million annually. See Note 3 to the financial statements to Rate RSE requested by the Company. Effective under "Retail Regulatory Matters - Rate CNP" for January 2007, Rate RSE adjustments will be based on additional information.

forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two- Retail Fuel Cost Recovery year period, when averaged together, cannot exceed 4 percent per year and any annual adjustment is limited to The Company has established fuel cost recovery rates 5 percent. Rates remain unchanged when the return on approved by the Alabama PSC. As a result of increased common equity ranges between 13.0 percent and 14.5 fuel costs for coal and gas, the Company filed a fuel cost percent. If the Company's actual retail return on recovery increase under the provisions of its energy cost common equity is above the allowed equity return recovery rate (Rate ECR). In December 2005, the range, customer refunds will be required; however, Alabama PSC approved an increase of the energy billing there is no provision for additional customer billings factor for retail customers from 1.788 cents per KWH to should the actual retail return on common equity fall 2.400 cents per KWH, effective with billings beginning below the allowed equity return range. The Company January 2006. This change to the billing factor represents will make its initial submission of projected data for on average an increase of approximately $6.12 per month calendar year 2007 by December 1, 2006. See Note 3 for a customer billing of 1,000 KWHs. This approved to the financial statements under "Retail Regulatory increase was intended to allow for the recovery of energy Matters - Rate RSE" for further information. costs based on an estimate of future energy costs, as well as the collection of the existing under recovered energy costs by the end of 2007. In addition, during 2007, the 14

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Company will be allowed to include a carrying charge Alabama PSC order gives the Company authority to associated with the under recovered fuel costs in the fuel record a deficit balance in the NDR when costs of expense calculation. As a result of the order, the Company uninsured storm damage exceed any established reserve reclassified $186.9 million of the under-recovered balance. The order also approved a separate monthly regulatory clause revenues from current assets to deferred NDR charge consisting of two components beginning charges and other assets in the balance sheet as of January 2006. The first component is intended to December 31, 2005. See Note 3 to the financial statements establish and maintain a target reserve balance of $75 under "Retail Regulatory Matters - Fuel Cost Recovery" million for future storms and is an on-going part of for additional information. customer billing. The Company currently expects that the target reserve balance could be achieved within five years.

Rate ECR revenues, as recorded on the financial The second component of the NDR charge is intended to statements, are adjusted for the difference in actual allow recovery of the existing deferred hurricane related recoverable costs and amounts billed in current regulated operation and maintenance costs and any future reserve rates. Accordingly, this approved increase in the billing deficits over a 24-month period. The maximum total factor will have no significant effect on the Company's NDR charge consisting of both components is $ 10 per revenues or net income, but will increase annual cash month per non-residential customer account and $5 per flow. month per residential customer account.

NaturalDisaster Cost Recovery As revenue from the NDR charge is recognized, an equal amount of operation and maintenance expense The Company maintains a reserve for operation and related to the NDR will also be recognized. As a result, maintenance expense to cover the cost of damages from this increase in revenue and expense will not have an major storms to its transmission and distribution facilities.

impact on net income but will increase the annual cash On July 10, 2005 and August 29, 2005, Hurricanes Dennis flow.

and Katrina, respectively, hit the coast of Alabama and continued north through the state, causing significant Other Matters damage in parts of the service territory of the Company.

Approximately 241,000 and 637,000 of the Company's In accordance with Financial Accounting Standards Board 1.4 million customer accounts were without electrical (FASB) Statement No. 87, Employers' Accounting for service immediately after Hurricanes Dennis and Katrina, Pensions, the Company recorded non-cash pre-tax pension respectively. The Company sustained significant damage income of approximately $21 million, $36 million, and to its distribution and transmission facilities during these $52 million in 2005, 2004, and 2003, respectively.

storms. Postretirement benefit costs for the Company were $28 million, $22 million, and $23 million in 2005, 2004, and In August 2005, the Company received approval from 2003, respectively. Both pension and postretirement the Alabama PSC to defer the Hurricane Dennis storm- benefit costs are expected to trend upward. Such amounts related operation and maintenance costs (approximately are dependent on several factors including trust earnings

$28 million), which resulted in a negative balance in the! and changes to the plans. A portion of pension and natural disaster reserve (NDR). In October 2005, the postretirement benefit costs is capitalized based on Company also received similar approval from the construction-related labor charges. Pension and Alabama PSC to defer the Hurricane Katrina storm-related postretirement benefit costs are a component of the operation and maintenance costs (approximately $30 regulated rates and generally do not have a long-term million). See Note 1 and Note 3 to the financial effect on net income. For more information regarding statements under "Natural Disaster Reserve" and "Natural pension and postretirement benefits, see Note 2 to the Disaster Cost Recovery," respectively, for additional financial statements.

information on these reserves. The natural disaster reserve deficit balance at December 31, 2005 was $50.6 The Company is involved in various other matters million. being litigated and regulatory matters that could affect future earnings. See Note 3 to the financial statements for In December 2005, the Alabama PSC approved a information regarding material issues.

request by the Company to replenish the depleted NDR and allow for recovery of future natural disaster costs. The 15

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report ACCOUNTING POLICIES As reflected in Note I to the financial statements under "Regulatory Assets and Liabilities," significant Application of Critical Accounting Policies and regulatory assets and liabilities have been recorded.

Estimates Management reviews the ultimate recoverability of these regulatory assets and liabilities based on The Company prepares its financial statements in applicable regulatory guidelines and accounting accordance with accounting principles generally principles generally accepted in the United States.

accepted in the United States. Significant accounting However, adverse legislative, judicial, or regulatory policies are described in Note I to the financial actions could materially impact the amounts of such statements. In the application of these policies, certain regulatory assets and liabilities and could adversely estimates are made that may have a material impact on impact the Company's financial statements.

the Company's results of operations and related disclosures. Different assumptions and measurements Contingent Obligations could produce estimates that are significantly different from those recorded in the financial statements. The Company is subject to a number of federal and state Management has reviewed and discussed critical laws and regulations, as well as other factors and accounting policies and estimates with the Audit conditions that potentially subject it to environmental, Committee of Southern Company's Board of Directors. litigation, income tax, and other risks. See "FUTURE EARNINGS POTENTIAL" herein and Note 3 to the Electric Utility Regulation financial statements for more information regarding certain of these contingencies. The Company The Company is subject to retail regulation by the periodically evaluates its exposure to such risks and Alabama PSC and wholesale regulation by the FERC. records reserves for those matters where a loss is These regulatory agencies set the rates the Company is considered probable and reasonably estimable in permitted to charge customers based on allowable accordance with generally accepted accounting costs. As a result, the Company applies FASB principles. The adequacy of reserves can be Statement No. 71, Accounting for the Effects of Certain significantly affected by external events or conditions Types of Regulation (Statement No. 71), which that can be unpredictable; thus, the ultimate outcome of requires the financial statements to reflect the effects of such matters could materially affect the Company's rate regulation. Through the ratemaking process, the financial statements. These events or conditions include regulators may require the inclusion of costs or the following:

revenues in periods different than when they would be recognized by a non-regulated company. This

• Changes in existing state or federal regulation by treatment may result in the deferral of expenses and the governmental authorities having jurisdiction over air recording of related regulatory assets based on quality, water quality, control of toxic substances, anticipated future recovery through rates or the deferral hazardous and solid wastes, and other environmental of gains or creation of liabilities and the recording of matters.

related regulatory liabilities. The application of

• Changes in existing income tax regulations or Statement No. 71 has a further effect on the Company's changes in Internal Revenue Service interpretations of financial statements as a result of the estimates of existing regulations.

allowable costs used in the ratemaking process. These

• Identification of additional sites that require estimates may differ from those actually incurred by the environmental remediation or the filing of other Company; therefore, the accounting estimates inherent complaints in which the Company may be asserted to in specific costs such as depreciation, nuclear be a potentially responsible party.

decommissioning, and pension and postretirement

• Identification and evaluation of other potential benefits have less of a direct impact on the Company's lawsuits or complaints in which the Company may be results of operations than they would on a non- named as a defendant.

regulated company.

• Resolution or progression of existing matters through the legislative process, the court systems, or the EPA.

16

MANAGEMENT'S DISCUSSION AND ANALYSIS (continned)

Alabama Power Company 2005 Annual Report Unbilled Revenues not have any effect on the Company's income statement.

Revenues related to the sale of electricity are recorded when electricity is delivered to customers. However, the Stock Options determination of KWH sales to individual customers is based on the reading of their meters, which is performed On January 1, 2006, the Company adopted FASB on a systematic basis throughout the month. At the end of Statement No. 123R, Share-Based Payment, on a each month, amounts of electricity delivered to customers, modified prospective basis. This statement requires but not yet metered and billed, are estimated. that compensation cost relating to share-based payment transactions be recognized in financial statements. That Components of the unbilled revenue estimates include cost will be measured based on the grant date fair value total KWH territorial supply, total KWH billed, estimated of the equity or liability instruments issued. Although total electricity lost in delivery, and customer usage. the compensation expense required under the revised These components can fluctuate as a result of a number of statement differs slightly, the impacts on the factors including weather, generation patterns, power Company's financial statements are similar to the pro delivery volume, and other operational constraints. These forma disclosures included in Note 1 to the financial factors can be unpredictable and can vary from historical statements under "Stock Options."

trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have FINANCIAL CONDITION AND LIQUIDITY a material impact on the Company's results of operations.

Overview New Accounting Standards The Company's financial condition continued to be Income Taxes strong at December 31, 2005. Net cash flow from operating activities totaled $0.9 billion, $1.0 billion, and In December 2004, the FASB issued FASB Staff $ 1.1 billion for 2005, 2004, and 2003, respectively. The Position 109-1, Application of FASB Statement No. 109, $106 million decrease for 2005 in operating activities Accounting for Income Taxes, to the Tax Deduction on primarily relates to an increase in under recovered fuel Qualified Production Activities Provided by the cost and storm damage costs related to Hurricanes Dennis American Jobs Creation Act of 2004 (FSP 109-1), which and Katrina. These increases were partially offset by the requires that the generation deduction be accounted for deferral of income tax liabilities arising from accelerated as a special tax deduction rather than as a tax rate depreciation deductions. The $104 million decrease from reduction. The Company adopted FSP 109-1 in the first 2003 to 2004 resulted from under recovered fuel cost and quarter of 2005 with no material impact on its financial storm damage costs related to Hurricane Ivan partially statements. offset by accelerated depreciation reductions. Fuel and storm damage costs are recoverable in future periods.

Conditional Asset Retirement Obligations Under recovered fuel cost is included in the balance sheets as under recovered regulatory clause revenue and deferred Effective December 31, 2005, the Company adopted under recovered regulatory clause revenues. Under the provision of FASB Interpretation No. 47 (FIN 47), recovered storm damage cost is included in the balance Conditional Asset Retirement Obligations, which sheets as other current assets and other regulatory assets.

requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are See FUTURE EARNINGS POTENTIAL - "Fuel Cost conditional on future events. Prior to December 2005, Recovery" and "Natural Disaster Cost Recovery" herein the Company did not recognize asset retirement for additional information.

obligations for asbestos removal and disposal of polychlorinated biphenyls in certain transformers Significant balance sheet changes for 2005 include an because the timing of their retirements was dependent increase of $668 million in gross plant. In 2004 on future events. For additional information, see Note 1 significant balance sheet changes included the $478 to the financial statements under "Asset Retirement million increase in long-term debt primarily due to the Obligations and Other Costs of Removal." At replacement of debt due within one year with long-term December 31, 2005, the Company recorded additional debt, and an increase of $408 million in gross plant.

asset retirement obligations (and assets) of approximately $35 million. The adoption of FIN 47 did 17

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report The Company's ratio of common equity to total The Company maintains committed lines of credit in capitalization -- including short-term debt -- was 42.2 the amount of $878 million, of which $428 million will percent in 2005, 42.6 percent in 2004, and 43.3 percent in expire at various times during 2006. $251 million of the 2003. See Note 6 to the financial statements for additional credit facilities expiring in 2006 allow for the execution of information. term loans for an additional one-year period. -See Note 6 to the financial statements under "Bank Credit The Company has received investment grade ratings Arrangements" for additional information.

from the major rating agencies.

The Company may also meet short-term cash needs Sources of Capital through a Southern Company subsidiary organized to issue and sell commercial paper and extendible The Company plans to obtain the funds required for construction and other purposes from sources similar to commercial notes at the request and for the benefit of the those used in the past, which were primarily from Company and the other Southern Company retail operating cash flows. In recent years, the Company has operating companies. Proceeds from such issuances for primarily utilized unsecured debt, preferred stock, and the benefit of the Company are loaned directly to the preferred securities. However, the type and timing of any Company and are not commingled with proceeds from financings -- if needed -- will depend on market such issuances for the benefit of any other retail operating conditions and regulatory approval. company. The obligations of each company under these arrangements are several and there is no cross affiliate Security issuances are subject to regulatory approval credit support.

by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company must file As of December 31, 2005 the Company had $136 registration statements with the Securities and Exchange million in commercial paper outstanding, $55 million in Commission (SEC) under the Securities Act of 1933, as extendible commercial notes outstanding, and $125 amended (1933 Act). The amounts of securities million in loans outstanding under an uncommitted credit authorized by the Alabama PSC, as well as the amounts arrangement. As of December 31, 2004, the Company had registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the no extendible commercial notes and no commercial paper capital markets. outstanding.

Financing Activities The Company obtains financing separately without credit support from any affiliate. See Note 6 to the During 2005, the Company issued $250 million of long-financial statements under "Bank Credit Arrangements" term debt. In addition, the Company issued one million for additional information. The Southern Company system new shares of common stock to Southern Company at does not maintain a centralized cash or money pool. $40.00 a share and realized proceeds of $40 million. The Therefore, funds of the Company are not commingled with proceeds of these issues were used to repay short-term funds of any other company. indebtedness, and for other general corporate purposes. In November 2005, the Company incurred obligations in The Company's current liabilities frequently exceed connection with the issuance of $21.5 million of variable current assets because of the continued use of short-term rate pollution control bonds. The proceeds were used to debt as a funding source to meet scheduled maturities of refund $21.5 million 5.50% fixed rate pollution control long-term debt as well as cash needs which can fluctuate bonds.

significantly due to the seasonality of the business.

In January and February 2006, the Company issued To meet short-term cash needs and contingencies, the $600 million of long-term debt. The proceeds of these Company has various internal and external sources of issues were used to repay short-term indebtedness and for liquidity. At the beginning of 2006, the Company had other general corporate purposes. In conjunction with approximately $22 million ofcash and cash equivalents and these transactions, the Company terminated $600 million

$878 million of unused credit arrangements with banks, as notional amount of interest rate swaps at a gain of $18 described below. In addition, the Company has substantial million. The gain will be amortized to interest expense cash flow from operating activities and access to the over a 10-year period.

capital markets, including commercial paper programs, to meet liquidity needs.

18

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Credit Rating Risk In addition, the Company's Rate ECR allows the recovery of specific costs associated with the sales of The Company does not have any credit arrangements that natural gas that become necessary due to operating would require material changes in payment schedules or considerations at the Company's electric generating terminations as a result of a credit rating downgrade. facilities. Rate ECR also allows recovery of the cost of However, the Company is party to certain derivative financial instruments used for hedging market price risk agreements that could require collateral and/or accelerated payment in the event of a credit rating change to below up to 75 percent of the budgeted annual amount of natural investment grade. These agreements are primarily for gas purchases. The Company may not engage in natural natural gas price risk management activities. At December gas hedging activities that extend beyond a rolling 42-31, 2005, the Company's exposure to these agreements month window. Also, the premiums paid for natural gas was not material. financial options may not exceed 5 percent of the Company's natural gas budget for that year.

Market Price Risk At December 31, 2005, exposure from these activities Due to cost-based rate regulations, the Company has was not material to the Company's financial position, limited exposure to market volatility in interest rates, results of operations, or cash flows. The changes in fair commodity fuel prices, and prices of electricity. To value of energy related derivative contracts and year-end manage the volatility attributable to these exposures, the valuations were as follows at December 3 1:

Company nets the exposures to take advantage of natural offsets and enters into various derivative transactions for Changes in Fair Value the remaining exposures pursuant to the Company's 2005 2004 (in thousands) policies in areas such as counterparty exposure and risk management practices. Company policy is that derivatives Contracts beginning of year $ 4,017 $ 6,413 are to be used primarily for hedging purposes and Contracts realized or settled (38,320) (26,384) mandates strict adherence to all applicable risk New contracts at inception - -

management policies. Derivative positions are monitored Changes in valuation techniques using techniques including, but not limited to, market Current period changes(a) 63,281 23,988 valuation, value at risk, stress testing, and sensitivity Contracts end of year $ 28,978 $ 4,017 (a) Current period changes also include the changes in fair value of new analysis. contracts entered into during the period.

To mitigate future exposure to changes in interest rates, the Company has entered into forward starting Source of 2005 Year-End

_ Valuation Prices interest rate swaps that have been designated as hedges.

The weighted average interest rate on $271.5 million of Total Maturity long-term variable interest rate exposure that has not been Fair Value 2006 2007-2008 (in thousands) hedged at January 1, 2006 was 4.45 percent. If the Company sustained a 100 basis point change in interest Actively quoted $29,177 $19,392 $9,785 rates for all unhedged variable rate long-term debt, the External sources (199) (199) -

change would affect annualized interest expense by Models and other approximately $2.7 million at January 1, 2006. The methods -

Company is not aware of any facts or circumstances that Contracts end of Year $28,978 $19,193 $9,785 would significantly affect such exposures in the near term.

For further information, see Notes 1 and 6 to the financial Unrealized gains and losses from mark-to-market statements under "Financial Instruments." adjustments on derivative contracts related to the Company's fuel hedging programs are recorded as To mitigate residual risks relative to movements in regulatory assets and liabilities. Realized gains and losses electricity prices, the Company enters into fixed-price from these programs are included in fuel expense and are contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, into recovered through the Company's fuel cost recovery clause. Gains and losses on derivative contracts that are similar contracts for gas purchases. The Company has not designated as hedges are recognized in the income implemented fuel hedging programs at the instruction of statement as incurred. At December 31, 2005, the fair the Alabama PSC.

19

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report value of derivative energy contracts was reflected in the In addition to the funds required for the Company's financial statements as follows: construction program, approximately $1.6 billion will be Amounts required by the end of 2008 for maturities of long-term (in thousands) debt. The Company plans to continue, when economically Regulatory liabilities, net $29,044 feasible, to retire higher cost securities and replace these Other comprehensive income obligations with lower-cost capital if market conditions Net income (66) permit.

Total fair value $28,978 As discussed in Note I to the financial statements Unrealized pre-tax gains (losses) on energy contracts under "Nuclear Fuel Disposal Costs," in 1993 the DOE recognized in income were not material for any year implemented a special assessment over a 15-year period presented. on utilities with nuclear plants to be used for the decontamination and decommissioning of its nuclear fuel The Company is exposed to market price risk in the enrichment facilities. The final installment is scheduled to event of nonperformance by counterparties to the occur in 2006.

derivative energy contracts. The Company's policy is to enter into agreements with counterparties that have The Company has also established an external trust investment grade credit ratings by Moody's and Standard fund for postretirement benefits as ordered by the

& Poor's or with counterparties who have posted Alabama PSC. The cumulative effect of funding these collateral to cover potential credit exposure. Therefore, items over a long period will diminish internally funded the Company does not anticipate market risk exposure capital for other purposes and may require the Company from nonperformance by the counterparties. For to seek capital from other sources. For additional additional information, see Notes 1 and 6 to the financial information, see Note 2 to the financial statements under statements under "Financial Instruments." "Postretirement Benefits."

Capital Requirements and Contractual Obligations Other funding requirements related to obligations associated with scheduled maturities of long-term debt and preferred securities, as well as the related interest, The construction program of the Company is currently preferred stock dividends, leases, and other purchase estimated to be $0.9 billion for 2006, $ 1.1 billion for commitments, are as follows. See Notes 1, 6, and 7 to 2007, and $ 1.1 billion for 2008. Environmental the financial statements for additional information.

expenditures included in these amounts are $285 million,

$426 million, and $406 million for 2006, 2007, and 2008, respectively (including $305 million on selective catalytic reduction facilities and $658 million on scrubbers). In addition, over the next three years, the Company estimates spending $244 million on Plant Farley (including $184 million for nuclear fuel), $793 million on distribution facilities, and $394 million on transmission additions. See Note 7 to the financial statements under "Construction Program" for additional details.

Actual construction costs may vary from this estimate because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; FERC rules and transmission regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

20

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Contractual Obligations 2007- 2009- After 2006 2008 2010 2010 Total (in millions)

Long-term debt$) --

Principal $ 546.7 $1,078.8 $ 350.1 $2,444.4 $ 4,420.0 Interest 191.7 325.3 252.7 2,165.7 2,935.4 Commodity derivative obligations"b) 9.3 0.1 - - 9.4 Preferred stock dividends(C) 24.3 48.6 48.6 - 121.5 Operating leases 23.6 28.5 17.0 29.1 98.2 Purchase commitments(d) --

Capital(e) 950.9 2,208.1 - - 3,159.0 Coal 1,064.9 1,551.7 863.6 323.6 3,803.8 Nuclear fuel 18.3 20.0 8.6 25.5 72.4 Natural gas( 0 545.2 413.9 45.4 89.4 1,093.9 Purchased power 87.0 177.0 125.0 2.0 391.0 Long-term service agreements 17.8 37.0 38.4 87.4 180.6 Postretirement benefits(g) 24.9 44.6 - - 69.5 DOE 4.7 - 4.7 Total $3,509.3 $5,933.6 $1,749.4 $5,167.1 $16,359.4 (a) All amounts are reflected based on final maturity dates. The Company plans to continue to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January I.,

2006, as reflected inthe statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk.

(b) For additional information, see Notes I and 6 to the financial statements herein.

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

(d) The Company generally does not enter into non-cancelable commitments for other operation and maintenance expenditures. Total other operation and maintenance expenses for 2005, 2004, and 2003 were $1.04 billion, $947 million, and $921 million, respectively.

(e) The Company forecasts capital expenditures over a three-year period. Amounts represent current estimates of total expenditures excluding those amounts related to contractual purchase commitments for uranium and nuclear fuel conversion, enrichment, and fabrication services. At December 31, 2005, significant purchase commitments were outstanding in connection with the construction program.

(f) Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected have been estimated based on the New York Mercantile Exchange future prices at December 31, 2005.

(g) The Company forecasts postretirement trust contributions over a three-year period. No contributions related to the Company's pension trust are currently expected during this period. See Note 2 to the financial statements for additional information related to the pension and postretirement plans, including estimated benefit payments. Certain benefit payments will be made through the related trusts. Other benefit payments will be made from the Company's corporate assets.

21

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2005 Annual Report Cautionary Statement Regarding Forward-Looking Statements The Company's 2005 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales growth and retail rates, storm damage cost recovery and repairs, environmental regulations and expenditures, earnings growth, the Company's projections for postretirement benefit trust contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules, and estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will, ".could,""should," ".expects,"'.plans," ".anticipates," "believes," "estimates,"

"projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, implementation of the Energy Policy Act of 2005, and also changes in environmental, tax, and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings, or inquiries, including the pending EPA civil action against the Company, and FERC matters;

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

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

• available sources and costs of fuels;

• ability to control costs;

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

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases relating to fuel cost recovery;

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

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

• the direct or indirect effect on the Company's business resulting from terrorist incidents and the threat of terrorist incidents;

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

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

' catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, or other similar occurrences;

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

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

' other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the Securities and Exchange Commission.

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

22

STATEMENTS OF INCOME For the Years Ended December 31, 2005, 2004, and 2003 Alabama Power Company 2005 Annual Report 2005 2004 2003 (in thousands)

Operating Revenues:

Retail sales $3,621,421 $3,292,828 $3,051,463 Sales for resale --

Non-affiliates 551,408 483,839 487,456 Affiliates 288,956 308,312 277,287 Other revenues 186,039 151,012 143,955 Total operating revenues 4,647,824 4,235,991 3,960,161 Operating Expenses:

Fuel 1,457,301 1,186,472 1,067,821 Purchased power --

Non-affiliates 188,733 186,187 110,885 Affiliates 268,751 226,697 204,353 Other operations 682,308 634,030 611,418 Maintenance 361,832 313,407 309,451 Depreciation and amortization 426,506 425,906 412,919 Taxes other than income taxes 248,854 242,809 228,414 Total operating expenses 3,634,285 3,215,508 2,945,261 Operating Income 1,013,539 1,020,483 1,014,900 Other Income and (Expense):

Allowance for equity funds used during construction 20,281 16,141 12,594 Interest income 17,144 15,677 15,220 Interest expense, net of amounts capitalized (197,367) (193,590) (214,302)

Interest expense to affiliate trusts (16,237) (16,191)

Distributions on mandatorily redeemable preferred securities - - (15,255)

Other income (expense), net (20,461) (24,728) (31,702)

Total other income and (expense) (196,640) (202,691) (233,445)

Earnings Before Income Taxes 816,899 817,792 781,455 Income taxes 284,715 313,024 290,378 Net Income 532,184 504,768 491,077 Dividends on Preferred Stock 24,289 23,597 18,267 Net Income After Dividends on Preferred Stock $ 507,895 $ 481,171 $ 472 810 The accompanying notes are an integral part of these financial statements.

23

STATEMENTS OF CASH FLOWS For the Years Ended December 31,2005,2004, and 2003 Alabama Power Company 2005 Annual Report 2005 2004 2003 (in thousands)

Operating Activities:

Net income $532,184 $ 504,768 $ 491,077 Adjustments to reconcile net income to net cash provided from operating activities --

Depreciation and amortization 498,914 497,010 487,370 Deferred income taxes and investment tax credits, net 106,765 252,858 153,154 Deferred revenues (12,502) (11,510) (17,932)

Allowance for equity funds used during construction (20,281) (16,141) (12,594)

Pension, postretirement, and other employee benefits (22,117) (31,184) (38,953)

Tax benefit of stock options 17,400 10,672 8,680 Hedge settlements (21,445) 2,241 (7,957)

Storm damage accounting order 48,000 - -

Other, net (15,491) 26,826 14,177 Changes in certain current assets and liabilities --

Receivables (255,481) (126,432) (13,416)

Fossil fuel stock (44,632) 30,130 (13,251)

Materials and supplies (16,935) (26,229) (4,651)

Other current assets 1,199 7,438 (953)

Accounts payable 80,951 (31,899) 77,128 Accrued taxes (5,381) (24,568) (33,507)

Accrued compensation 3,273 (7,041) 664 Other current liabilities 33,675 (42,544) 29,058 Net cash provided from operating activities 908,096 1,014,395 1,118,094 Investing Activities:

Property additions (860,807) (768,334) (643,231)

Nuclear decommissioning trust fund purchases (224,716) (269,277) (350,271)

Nuclear decommissioning trust fund sales 223,850 248,992 329,986 Cost of removal net of salvage (61,314) (37,369) (35,440)

Other (9,738) (5,008) 1,193 Net cash used for investing activities (932,725) (830,996) (697,763)

Financing Activities:

Increase (decrease) in notes payable, net 315,278 - (36,991)

Proceeds --

Senior notes 250,000 900,000 1,415,000 Preferred stock - 100,000 125,000 Common stock 40,000 40,000 50,000 Capital contributions from parent company 22,473 17,541 17,826 Pollution control bonds 21,450 - -

Redemptions --

Senior notes (225,000) (725,000) (1,507,000)

Pollution control bonds (21,450)

Other long-term debt (5) (1,445) (943)

Payment of preferred stock dividends (22,759) (23,639) (18,181)

Payment of common stock dividends (409,900) (437,300) (430,200)

Other (2,697) (16,597) (14,775)

Net cash used for financing activities (32,610) (146,440) (400,264)

Net Change in Cash and Cash Equivalents (57,239) 36,959 20,067 Cash and Cash Equivalents at Beginning of Year 79,711 42,752 22,685 Cash and Cash Equivalents at End of Year S 22,472 $ 79.711 $ 42.752 Supplemental Cash Flow Information:

Cash paid during the period for -

Interest (net of $8,161, $6,832, and $6,367 capitalized, respectively) $179,658 $188,556 $185,272 Income taxes (net of refunds) 159,600 69,068 161,004 The accompanying notes are an integral part of these financial statements.

24

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BALANCE SHEETS At December 31, 2005 and 2004 Alabama Power Company 2005 Annual Report Assets 2005 2004 (in thousands)

Current Assets:

Cash and cash equivalents $ 22,472 $ 79,711 Receivables --

Customer accounts receivable 275,702 233,286 Unbilled revenues 95,039 96,486 Under recovered regulatory clause revenues 132,139 119,773 Other accounts and notes receivable 50,008 52,145 Affiliated companies 77,304 61,149 Accumulated provision for uncollectible accounts (7,560) (5,404)

Fossil fuel stock, at average cost 102,420 57,787 Vacation pay 37,646 36,494 Materials and supplies, at average cost 244,417 237,919 Prepaid expenses 58,845 61,898 Assets from risk management activities 53,192 11,268 Other 52,561 11,693 Total current assets 1,194,185 1,054,205 Property, Plant, and Equipment:

In service 15,300,346 14,632,342 Less accumulated provision for depreciation 5,313,731 5,097,930 9,986,615 9,534,412 Nuclear fuel, at amortized cost 127,199 93,388 Construction work in progress 469,018 474,670 Total property, plant, and equipment 10,582,832 10,102,470 Other Property and Investments:

Equity investments in unconsolidated subsidiaries 46,913 45,455 Nuclear decommissioning trusts, at fair value 466,963 445,634 Other 41,457 40,942 Total other property and investments 555,333 532,031 Deferred Charges and Other Assets:

Deferred charges related to income taxes 388,634 316,528 Prepaid pension costs 515,281 489,193 Deferred under recovered regulatory clause revenues 186,864 Other regulatory assets 128,437 163,273 Other 138,341 123,825 Total deferred charges and other assets 1,357,557 1,092,819 Total Assets $13,689,907 $12,781,525 The accompanying notes are an integral part of these financial statements.

25

BALANCE SHEETS At December 31, 2005 and 2004 Alabama Power Company 2005 Annual Report Liabilities and Stockholder's Equity 2005 2004 (in thousands)

Current Liabilities:

Securities due within one year $ 546,645 $ 225,005 Notes payable 315,278 Accounts payable --

Affiliated 190,744 141,096 Other 266,174 198,834 Customer deposits 56,709 47,664 Accrued taxes --

Income taxes 63,844 28,498 Other 31,692 29,688 Accrued interest 46,018 40,029 Accrued vacation pay 37,646 36,494 Accrued compensation 92,784 76,858 Other 72,991 34,289 Total current liabilities 1,720,525 858,455 Long-term Debt (See accompanying statements) 3,560,186 3,855,257 Long-term Debt Payable to Affiliated Trusts (See accompanying statements) 309,279 309,279 Deferred Credits and Other Liabilities:

Accumulated deferred income taxes 2,070,746 1,885,120 Deferred credits related to income taxes 101,678 148,395 Accumulated deferred investment tax credits 196,585 205,353 Employee benefit obligations 208,663 194,837 Asset retirement obligations 446,268 383,621 Other cost of removal obligations 600,104 597,147 Other regulatory liabilities 194,135 206,765 Other 23,966 62,045 Total deferred credits and other liabilities 3,842,145 3,683,283 Total Liabilities 9,432,135 8,706,274 Cumulative Preferred Stock (See accompanying statements) 465,046 465,047 Common Stockholder's Equity (See accompanying statements) 3,792,726 3,610,204 Total Liabilities and Stockholder's Equitv $13.689.907 $12,781,525 Commitments and Contingent Matters (See notes)

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

26

STATEMENTS OF CAPITALIZATION At December 31, 2005 and 2004 Alabama Power Company 2005 Annual Report 2005 2004 2005 2004 (in thousands) (percent of total)

Long-Term Debt:

Long-term notes payable --

5.49% due November 1, 2005 C l- $ 225,000 2.65% to 2.80% due 2006 520,000 520,000 Floating rate (1.94% at 1/1/06) due 2006 26,500 195,000 3.50% to 7.125% due 2007 500,000 500,000 Floating rate (2.14% at 1/1/06) due 2007 168,500 3.125% to 5.375% due 2008 410,000 410,000 Floating rate (4.58% at 1/1/06) due 2009 250,000 250,000 4.70% due 2010 100,000 100,000 5.125% to 5.875% due 2011-2035 1,575,000 1,325,000 Total long-term notes payable $3,550,000 $3,525,000 Other long-term debt --

Pollution control revenue bonds --

Collateralized:

Variable rates (2.01% to 2.16% at 1/1/06) due 2015-2017 89,800 89,800 5.50% due 2024 2,950 24,400 Non-collateralized:

Variable rates (2.01% to 3.74% at 1/1/06) due 2021-2031 467,390 445,940 Total other long-term debt 560,140 560,140 Capitalized lease obligations 564 52 Unamortized debt premium (discount), net (3,873) (4,930)

Total long-term debt (annual interest requirement -- $175.4 million) 4,106,831 4,080,262 Less amount due within one year 546,645 225,005 Long-term debt excluding amount due within one year $3,560,186 $3,855,257 43.8% 46.8%

27

STATEMENTS OF CAPITALIZATION (continued)

At December 31, 2005 and 2004 Alabama Power Company 2005 Annual Report 2005 2004 2005 2004 (in thousands) (percent of total)

Long-term Debt Payable to Affiliated Trusts:

4.75% to 5.5% due 2042 (annual interest requirement -- $16.2 million) 309,279 309,279 3.8 3.8 Cumulative Preferred Stock:

$ 100 par or stated value -- 4.20% to 4.92%

Authorized -- 3,850,000 shares Outstanding -- 475,115 shares 47,610 47,611

$1 par value -- 4.95% to 5.83%

Authorized -- 27,500,000 shares Outstanding -- 12,000,000 shares: $25 stated value 294,105 294,105 Outstanding -- 1,250 shares: $100,000 stated value 123,331 123,331 Total cumulative preferred stock (annual dividend requirement -- $24.3 million) 465,046 465,047 5.7 5.6 Common Stockholder's Equity:

Common stock, par value $40 per share --

Authorized - 15,000,000 shares Outstanding - 9,250,000 shares in 2005 370,000 330,000 and 8,250,000 shares in 2004 Paid-in capital 1,995,056 1,955,183 Retained earnings 1,439,144 1,341,049 Accumulated other comprehensive income (loss) (11,474) (16,028)

Total common stockholder's equity 3,792,726 3,610,204 46.7 43.8 Total Capitalization $8.127.237 $8,239,787 100.0% 100.0%

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

28

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2005, 2004, and 2003 Alabama Power Company 2005 Annual Report Other Common Paid-In Retained Comprehensive Stock Capital Earnings Income (loss) Total (in thousands)

Balance at December 31, 2002 $240,000 $1,900,563 $1,250,594 $(13,417) $3,377,740 Net income after dividends on preferred stock - - 472,810 - 472,810 Issuance of common stock 50,000 - - 50,000 Capital contributions from parent company - 26,506 - - 26,506 Other comprehensive income (loss) - - - 5,450 5,450 Cash dividends on common stock - - (430,200) - (430,200)

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

Balance at December 31, 2003 290,000 1,927,069 1,291,558 (7,967) 3,500,660 Net income after dividends on preferred stock - - 481,171 - 481,171 Issuance of common stock 40,000 - - - 40,000 Capital contributions from parent company - 28,213 - - 28,213 Other comprehensive income (loss) - - - (8,061) (8,061)

Cash dividends on common stock - - (437,300) - (437,300)

Other - (99) 5,620 - 5,521 Balance at December 31, 2004 330,000 1,955,183 1,341,049 (16,028) 3,610,204 Net income after dividends on preferred stock - - 507,895 - 507,895 Issuance of common stock 40,000 - - - 40,000 Capital contributions from parent company - 39,873 - - 39,873 Other comprehensive income (loss) - - - 4,554 4,554 Cash dividends on common stock - - (409,900) - (409,900)

Other - - 100 - 100 Balance at December 31. 2005 $370,000 $1,995,056 $1.439.144 $(11,474) $3,792,726 The accompanying notes are an integra! part of these financial statements.

STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31,2005, 2004, and 2003 Alabama Power Company 2005 Annual Report 2005 2004 2003 (in thousands)

Net income after dividends on preferred stock $507,895 $481,171 $472,810 Other comprehensive income (loss):

Change in additional minimum pension liability, net of tax of

$(1,422), $(2,482) and $(2,301), respectively (2,338) (4,083) (3,785)

Change in fair value of marketable securities, net of tax of $252 - 414 -

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

$5,523, $(4,807) and $1,330, respectively 9,085 (7,906) 2,188 Less: Reclassification adjustment for amounts included in net income, net of tax of $(1,333), $2,136 and $4,285, respectively (2,193) 3,514 7,047 Total other comprehensive income (loss) 4,554 (8,061) 5,450 Comprehensive Income $512,449 $473,110 $478,260 The accompanying notes are an integral part of these financial statements.

29

NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2005 Annual Report

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING SoutherntCompany was registered as a holding POLICIES company under the Public Utility Holding Company Act of 1935, as amended (PUHCA), until its repeal on General February 8, 2006. Both Southern Company and its subsidiaries, including the Company, were subject to the Alabama Power Company (the Company) is a wholly regulatory provisions of the PUHCA. The Company is owned subsidiary of Southern Company, which is the subject to regulation by the FERC and the Alabama Public parent company of five retail operating companies, Service Commission (PSC). The Company follows Southern Power Company (Southern Power), Southern accounting principles generally accepted in the United Company Services (SCS), Southern Communications States and complies with the accounting policies and Services (SouthernLINC Wireless), Southern Company practices prescribed by its regulatory commissions. The Holdings (Southern Holdings), Southern Nuclear preparation of financial statements in conformity with Operating Company (Southern Nuclear), Southern accounting principles generally accepted in the United Telecom, and other direct and indirect subsidiaries. The States requires the use of estimates, and the actual results retail operating companies -- the Company, Georgia may differ from those estimates.

Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Affiliate Transactions Company -- provide electric service in four Southeastern states. The Company operates as a vertically integrated The Company has an agreement with SCS under which the utility providing electricity to retail customers within its following services are rendered to the Company at direct traditional service area located within the State of or allocated cost: general and design engineering, Alabama and to wholesale customers in the Southeast. purchasing, accounting and statistical analysis, finance and Southern Power constructs, owns, and manages Southern treasury, tax, information resources, marketing, auditing, Company's competitive generation assets and sells insurance and pension administration, human resources, electricity at market-based rates in the wholesale market. systems and procedures, and other services with respect to Contracts among the retail operating companies and business and operations and power pool transactions.

Southern Power -- related to jointly-owned generating Costs for these services amounted to $246 million, $224 facilities, interconnecting transmission lines, or the million, and $217 million during 2005, 2004, and 2003, exchange of electric power -- are regulated by the Federal respectively. Cost allocation methodologies used by SCS Energy Regulatory Commission (FERC). SCS -- the were approved by the Securities and Exchange system service company -- provides, at cost, specialized Commission (SEC) prior to the repeal of PUHCA, and services to Southern Company and its subsidiary management believes they are reasonable.

companies. SouthernLINC Wireless provides digital The Company has an agreement with Southern wireless communications services to the retail operating Nuclear under which Southern Nuclear operates the companies and also markets these services to the public Company's Plant Farley and provides the following within the Southeast. Southern Telecom provides fiber nuclear-related services at cost: general executive and cable services within the Southeast. Southern Holdings is advisory services, general operations, management and an intermediate holding subsidiary for Southern technical services, administrative services including Company's investments in synthetic fuels and leveraged procurement, accounting, statistical analysis, employee leases and various other energy-related businesses. relations, and other services with respect to business and Southern Nuclear operates and provides services to operations. Costs for these services amounted to $157 Southern Company's nuclear power plants, including the million, $169 million, and $153 million during 2005, Company's Plant Farley. On January 4, 2006, Southern 2004, and 2003, respectively.

Company completed the sale of substantially all the assets of Southern Company Gas, its competitive retail natural The Company jointly owns Plant Greene County with gas marketing subsidiary. Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates The equity method is used for subsidiaries in which Plant Greene County, and Mississippi Power reimburses the Company has significant influence but does not the Company for its proportionate share of expenses control and for variable interest entities where the which were $8.2 million in 2005, $7.2 million in 2004, Company is not the primary beneficiary. Certain prior and $6.6 million in 2003. See Note 4 for additional years' data presented in the financial statements have been information.

reclassified to conform with current year presentation.

30

NOTES (continued)

Alabama Power Company 2005 Annual Report Southern Company holds a 30 percent ownership Mississippi Power in the last two years, assistance interest in Alabama Fuel Products, LLC (AFP), which provided to aid in storm restoration, including company produces synthetic fuel. The Company has an agreement labor, contract labor, and materials, has caused an increase with an indirect subsidiary of Southern Company that in these activities. The total amount of storm restoration provides services for AFP. Under this agreement, the provided to Georgia Power and Gulf Power in 2004 and to Company provides certain accounting functions, including Mississippi Power in 2005 was $2.4 million, $2.3 million processing and paying fuel transportation invoices, and the and $8.0 million, respectively. In 2004 and 2005, the Company is reimbursed for its expenses. Amounts billed Company received assistance from affiliated companies in under this agreement totaled approximately $31.5 million, the amount of $5.6 million and $5.0 million, respectively,

$28.7 million, and $27.5 million in 2005, 2004 and 2003, for aid in major storm restoration. These activities were respectively. In addition, the Company purchases billed at cost.

synthetic fuel from AFP for use at several of the Company's plants. Fuel purchases for 2005, 2004, and The retail operating companies, including the 2003 totaled $265.7 million, $236.9 million, and $209.2 Company, and Southern Power jointly enter into various million, respectively. types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each In June 2003, the Company entered into an agreement participating company may be jointly and severally liable with Southern Power under which the Company operates for the obligations incurred under these agreements. See and maintains Plant Harris at cost. In 2005, 2004 and Note 7 under "Fuel Commitments" for additional 2003, the Company billed Southern Power $1.9 million, information.

$1.8 million and $0.8 million, respectively, for operation and maintenance. Under a power purchase agreement Revenues (PPA) with Southern Power, the Company's purchased power costs from Plant Harris in 2005, 2004 and 2003 Energy and other revenues are recognized as services are totaled $63.6 million, $59.0 million and $41.7 million, provided. Capacity revenues are generally recognized on respectively. The Company also provides the fuel, at cost, a levelized basis over the appropriate contract periods.

associated with the PPA and the fuel cost recognized by Unbilled revenues are accrued at the end of each fiscal the Company in 2005 was $81.3 million, $65.7 million in period. Electric rates for the Company include provisions 2004, and $33.9 million in 2003. Additionally, the to adjust billings for fluctuations in fuel costs, fuel Company recorded $8.3 million of prepaid capacity hedging, the energy component of purchased power costs, expenses included in other deferred charges and other and certain other costs. Revenues are adjusted for assets in the balance sheets at December 31, 2005 and differences between these actual costs and amounts billed 2004. See Note 3 under "Retail Regulatory Matters" and in current regulated rates. Under or over recovered Note 7 under "Purchased Power Commitments" for regulatory clause revenues are recorded in the balance additional information. sheets and are recovered or returned to customers through adjustments to the billing factors. The Company The Company has an agreement with SouthermLINC continuously monitors the under/over recovered balance Wireless to provide digital wireless communications and files for a revised fuel rate when management deems services to the Company. Costs for these services appropriate. See "Retail Regulatory Matters - Fuel Cost amounted to $5.7 million, $5.3 million, and $4.9 million Recovery" in Note 3 for additional information.

during 2005, 2004, and 2003, respectively.

The Company has a diversified base of customers. No Also, see Note 4 for information regarding the single customer or industry comprises 10 percent or more Company's ownership in and PPA with Southern Electric of revenues. For all periods presented, uncollectible Generating Company (SEGCO) and Note 5 for accounts averaged less than one percent of revenues.

information on certain deferred tax liabilities due to affiliates. Fuel Costs Fuel costs are expensed as the fuel is used. Fuel expense The Company provides incidental services to, and includes the cost of purchased emission allowances as receives such services from, other Southern Company they are used. Fuel expense also includes the amortization subsidiaries which are generally minor in duration and/or of the cost of nuclear fuel and a charge, based on nuclear amount. However, with the hurricane damage generation, for the permanent disposal of spent nuclear experienced by Georgia Power, Gulf Power and fuel. Total charges for nuclear fuel included in fuel 31

NOTES (continued)

Alabama Power Company 2005 Annual Report expense totaled $64 million in 2005, $61 million in 2004, In the event that a portion of the Company's and $64 million in 2003. operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to Regulatory Assets and Liabilities write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In The Company is subject to the provisions of Financial addition, the Company would be required to determine if Accounting Standards Board (FASB) Statement No. 71, any impairment to other assets exists, including plant, and Accounting for the Effects of Certain Types of write down the assets, if impaired, to their fair values. All Regulation. Regulatory assets represent probable future regulatory assets and liabilities are currently reflected in revenues associated with certain costs that are expected to rates.

be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future Nuclear Fuel Disposal Costs reductions in revenues associated with amounts that are expected to be credited to customers through the The Company has a contract with the U.S. Department of ratemaking process. Energy (DOE) that provides for the permanent disposal of Regulatory assets and (liabilities) reflected in the spent nuclear fuel. The DOE failed to begin disposing of balance sheets at December 31 relate to: spent nuclear fuel in 1998 as required by the contract, and the Company is pursuing legal remedies against the 2005 2004 Note government for breach of contract. Construction of an on-(in millions) site dry spent fuel storage facility at Plant Farley was Deferred income tax charges $ 389 $ 317 (a) completed in 2005 and can be expanded to accommodate Loss on reacquired debt 102 109 (b) spent fuel through the life of the plant.

DOE assessments 5 9 (c)

Vacation pay 38 36 (d) Also, the Energy Policy Act of 1992 established a Rate CNP under recovery 31 18 (e) Uranium Enrichment Decontamination and Natural disaster reserve 51 38 (e) Decommissioning Fund, which is funded in part by a Fuel-hedging assets 9 6 (f) special assessment on utilities with nuclear plants. This Other assets 13 13 (e) assessment has been paid over a 15 year period; the final Asset retirement obligations (139) (159) (a) installment is scheduled to occur in 2006. This fund will Other cost of removal obligations (600) (597) (a) be used by the DOE for the decontamination and Deferred income tax credits (102) (148) (a) decommissioning of its nuclear fuel enrichment facilities.

Deferred purchased power (19) (19) (e) The law provides that utilities will recover these payments Mine reclamation and remediation (16) (25) (e) in the same manner as any other fuel expense. The Fuel-hedging liabilities (38) (10) (f) Company estimates its remaining liability at December 31, Other liabilities (11) (1) (e) 2005 under this law to be approximately $5 million.

Total $(287) $(413)

Note: The recovery and amortization periods for these regulatory Income Taxes assets and (liabilities) are as follows:

(a) Asset retirement and removal liabilities are recorded, deferred The Company uses the liability method of accounting for income tax assets are recovered, and deferred tax liabilities are deferred income taxes and provides deferred income taxes amortized over the related property lives, which may range up to 50 years. Asset retirement and removal liabilities will be settled for all significant income tax temporary differences.

and trued up following completion of the related activities. Investment tax credits utilized are deferred and amortized (b) Recovered over the remaining life of the original issue which to income over the average life of the related property.

may range up to 50 years.

(c) Assessments for the decontamination and decommissioning of the DOE nuclear fuel enrichment facilities are recorded annually Property, Plant, and Equipment from 1993 through 2006.

(d) Recorded as earned by employees and recovered as paid, Property, plant, and equipment is stated at original cost generally within one year. less regulatory disallowances and impairments. Original (e) Recorded and recovered or amortized as approved by the Alabama PSC.

cost includes: materials; labor; minor items of property; (f) Fuel-hedging assets and liabilities are recorded over the life of appropriate administrative and general costs; payroll-the underlying hedged purchase contracts, which generally do related costs such as taxes, pensions, and other benefits; not exceed two years. Upon final settlement, actual costs and the interest capitalized and/or cost of funds used incurred are recovered through the fuel cost recovery clauses.

during construction.

32

NOTES (continued)

Alabama Power Company 2005 Annual Report The Company's property, plant, and equipment useful life. In addition, effective December 31, 2005, consisted of the following at December 31 (in millions): the Company adopted the provisions of FASB Interpretation No. 47, Conditional Asset Retirement 2005 2004 Obligations, which requires that an asset retirement Generation $ 7,971 $ 7,635 obligation be recorded even though the timing and/or Transmission 2,205 2,097 method of settlement are conditional on future events.

Distribution 4,115 3,922 Prior to December 2005, the Company did not recognize General 1,000 969 asset retirement obligations for asbestos removal and Plant acquisition adjustment 9 9 disposal of polychlorinated biphenyls in certain Total nlant in service $15,300 $14.632 transformers because the timing of their retirements was dependent on future events. The Company has received The cost of replacements of property -- exclusive of accounting guidance from the Alabama PSC allowing minor items of property -- is capitalized. The cost of the continued accrual of other future retirement costs for maintenance, repairs, and replacement of minor items of long-lived assets that the Company does not have a legal property is charged to maintenance expense as incurred or obligation to retire. Accordingly, the accumulated performed with the exception of nuclear refueling costs, removal costs for these obligations will continue to be which are recorded in accordance with specific Alabama reflected in the balance sheets as a regulatory liability.

PSC orders. The Company accrues estimated refueling Therefore, the Company had no cumulative effect to net costs in advance of the unit's next refueling outage. The income resulting from the adoption of Statement No.

refueling cycle is 18 months for each unit. During 2005, 143 or Interpretation No. 47.

the Company accrued $28 million and paid $19.7 million for an outage at Unit 2. At December 31, 2005, the The liability recognized to retire long-lived assets reserve balance totaled $7.5 million and is included in the primarily relates to the Company's nuclear facility, balance sheet in other regulatory liabilities. Plant Farley. The fair value of assets legally restricted for settling retirement obligations related to nuclear Depreciation and Amortization facilities as of December 31, 2005 was $467 million.

See "Nuclear Decommissioning" herein for further Depreciation of the original cost of depreciable utility information. In addition, the Company recognized plant in service is provided primarily by using composite asset retirement obligations related to various landfill straight-line rates, which approximated 2.9 percent in sites and underground storage tanks. In connection 2005, 3.0 percent in 2004, and 3.1 percent in 2003. with the adoption of Interpretation No. 47, the Depreciation studies are conducted periodically to update Company recognized additional asset retirement the composite rates and the information is provided to the obligations (and assets) of $35 million, related to Alabama PSC. When property subject to depreciation is asbestos removal and disposal of polychlorinated retired or otherwise disposed of in the normal course of biphenyls in certain transformers. The Company has business, its original cost, together with the cost of also identified retirement obligations related to certain removal, less salvage, is charged to accumulated transmission and distribution facilities and certain depreciation. Minor items of property included in the wireless communication towers. However, liabilities original cost of the plant are retired when the related for the removal of these assets have not been recorded property unit is retired. because the range of time over which the Company may settle these obligations is unknown and cannot be Asset Retirement Obligations reasonably estimated. The Company will continue to and Other Costs of Removal recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any Effective January 1, 2003, the Company adopted FASB difference between costs recognized under Statement Statement No. 143, Accounting for Asset Retirement No. 143 and Interpretation No. 47 and those reflected in Obligations, which established new accounting and rates are recognized as either a regulatory asset or reporting standards for legal obligations associated with liability, as ordered by the Alabama PSC, and are the ultimate costs of retiring long-lived assets. The reflected in the balance sheets.

present value of the ultimate costs of an asset's future retirement is recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's 33

NOTES (continued)

Alabama Power Company 2005 Annual Report Details of the asset retirement obligations included Sales of the securities held in the trust funds in the balance sheets are as follows: resulted in proceeds of $223.8 million, $249.0 million, 2005 2004 and $330.0 million in 2005, 2004, and 2003, (in millions) respectively, all of which were re-invested. Net Balance beginning of year $384 $359 realized gains (losses) were $9.9 million, $7.5 million Liabilities incurred 36 - and $(1.7) million in 2005, 2004, and 2003, Liabilities settled respectively. Realized gains and losses are determined Accretion 26 25 on a specific identification basis. In accordance with Cash flow revisions regulatory guidance, all realized and unrealized gains and losses are included in the regulatory liability for Balance end of year $446 $384 Asset Retirement Obligations in the balance sheets and are not included in net income or other comprehensive If Interpretation No. 47 had been adopted as of income. Unrealized gains and losses are considered December 31, 2004, the pro forma asset retirement non-cash transactions for purposes of the statements of obligations would have been $417 million. cash flow. Unrealized losses were not material in any period presented and do not represent any impairment Nuclear Decommissioning of the underlying investments.

The Nuclear Regulatory Commission (NRC) requires licensees of commercial nuclear power reactors to The NRC's minimum external funding requirements establish a plan for providing reasonable assurance of are based on a generic estimate of the cost to funds for future decommissioning. The Company has decommission only the radioactive portions of a nuclear external trust funds to comply with the NRC's unit based on the size and type of reactor. The Company regulations. Use of the funds is restricted to nuclear has filed plans with the NRC designed to ensure that, over decommissioning activities and the funds are managed time, the deposits and earnings of the external trust funds and invested in accordance with applicable will provide the minimum funding amounts prescribed by requirements of various regulatory bodies, including the the NRC. At December 31, 2005, the accumulated NRC, the FERC, and the Alabama PSC, as well as the provisions for decommissioning were as follows:

Internal Revenue Service (IRS). The trust funds are (in millions) invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are classified External trust funds, at fair value $467 as available-for-sale. The trust funds are included in Internal reserves 28 the balance sheets at fair value, as obtained from quoted Total $495 market prices for the same or similar investments.

Details of the securities held in these trusts at December Site study cost is the estimate to decommission the 31 are as follows: facility as of the site study year. The estimated costs of Unrealized Unrealized decommissioning, based on the most current study 2005 Gains Losses Fair Value performed in 2003 for Plant Farley were as follows:

(inmillions)

Equity $78.9 $(7.7) $275.3 Decommissioning periods:

Debt 1.3 (1.6) 106.1 Beginning year 2017 Other 17.0 - 85.6 Completion year 2046 Total $97.2 $(9.3) $467.0 (in millions)

Site study costs:

Unrealized Unrealized Radiated structures $892 2004 Gains Losses Fair Value Non-radiated structures 63 (inmillions)

Total $955 Equity $71.3 $(4.3) $258.1 Debt 3.2 (0.6) 95.5 Other 13.6 (0.2) 92.0 The decommissioning cost estimates are based on Total $88.1 $(5.1) $445.6 prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from The contractual maturities of debt securities at the above estimates because of changes in the assumed December 31, 2005 are as follows: $14.1 million in date of decommissioning, changes in NRC requirements, 2006; $55.2 million in 2007-2010; $27.1 million in or changes in the assumptions used in making these 2011-2015; and $8.3 million thereafter. estimates.

34

NOTES (continued)

Alabama Power Company 2005 Annual Report All of the Company's decommissioning costs for the assets, as compared with the carrying value of the ratemaking are based on the site study. Significant assets. If impairment has occurred, the amount of the assumptions used to determine these costs for ratemaking impairment recognized is determined by either the amount were an inflation rate of 4.5 percent and a trust earnings of regulatory disallowance or by estimating the fair value rate of 7.0 percent. Another significant assumption used of the assets and recording a loss if the carrying value is was the change in the operating license for Plant Farley. greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair In May 2005, the NRC granted the Company a 20- value less the cost to sell in order to determine if an year extension of the operating license for both units at impairment provision is required. Until the assets are Plant Farley. As a result of the license extension, disposed of, their estimated fair value is re-evaluated when amounts previously contributed to the external trust are circumstances or events change.

currently projected to be adequate to meet the decommissioning obligations. Therefore, in June 2005, Natural Disaster Reserve the Alabama PSC approved the Company's request to suspend, effective January 1, 2005, the inclusion in its In accordance with an Alabama PSC order, the Company annual cost of service of $18 million in decommissioning has established a natural disaster reserve (NDR) to cover costs and to also suspend the associated obligation to the cost of uninsured damages from major storms to make semi-annual contributions to the external trust. The transmission and distribution facilities. The Company Company will continue to provide site specific estimates may collect a monthly NDR charge per account that of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if consists of two components beginning January 1, 2006.

necessary, would seek the Alabama PSC's approval to The first component is intended to establish and maintain address any changes in a manner consistent with the NRC a reserve for future storms and is an on-going part of and other applicable requirements. The approved customer billing. This plan has a target reserve balance of suspension does not affect the transfer of internal reserves $75 million that could be achieved in five years. The (less than $1 million annually) previously collected from second component of the NDR charge is intended to allow customers prior to the establishment of the external trust. recovery of the deferred Hurricanes Dennis- and Katrina-related operation and maintenance costs and to set in place Allowance for Funds Used During Construction a mechanism to replenish the natural disaster reserve (AFUDC) should any future storms deplete the natural disaster reserve. The Alabama PSC order gives the Company In accordance with regulatory treatment, the Company authority to have a negative NDR balance when costs of records AFUDC. AFUDC represents the estimated debt uninsured storm damage exceed any established NDR and equity costs of capital funds that are necessary to balance. This second component allows for the recovery finance the construction of new regulated facilities. While of a negative balance over a 24-month period. The cash is not realized currently from such allowance, it maximum total NDR charge consisting of both increases the revenue requirement over the service life of components is $ 10 per month per account for non-the plant through a higher rate base and higher residential customers and $5 per month per account for depreciation expense. All current construction costs are residential customers.

included in retail rates. The composite rate used to determine the amount of AFUDC was 8.8 percent in 2005, As revenue from the natural disaster reserve charge is 8.6 percent in 2004, and 9.0 percent in 2003. AFUDC, net recognized, an equal amount of operation and of income tax, as a percent of net income after dividends maintenance expense related to the natural disaster reserve on preferred stock was 5.0 percent in 2005, 4.2 percent in will also be recognized. As a result, this increase in 2004, and 3.5 percent in 2003. revenue and expense will not have an impact on net income, but will increase the annual cash flow.

Impairment of Long-Lived Assets and Intangibles Environmental Cost Recovery The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the The Company has received authority from the Alabama carrying value of such assets may not be recoverable. The PSC to recover approved environmental compliance costs determination of whether impairment has occurred is through specific retail rate clauses. Within limits based on either a specific regulatory disallowance or an approved by the Alabama PSC, these rates are adjusted estimate of undiscounted future cash flows attributable to 35

NOTES (continued)

Alabama Power Company 2005 Annual Report annually. See Note 3 under "Retail Regulatory Matters - The estimated fair values of stock options granted in Rate Adjustment Procedures" for additional information. 2005, 2004, and 2003 were derived using the Black-Scholes stock option pricing model. The following table Cash and Cash Equivalents shows the assumptions and the weighted average fair values of stock options:

For purposes of the financial statements, temporary cash 2005 2004 2003 investments are considered cash equivalents. Temporary Interest rate 3.9% 3.1% 2.7%

cash investments are securities with original maturities of Average expected life of 90 days or less. stock options (inyears) 5.0 5.0 4.3 Expected volatility of Materials and Supplies common stock 17.9% 19.6% 23.6%

Expected annual dividends Generally, materials and supplies include the average cost on common stock $1.43 $1.40 $1.37 of transmission, distribution, and generating plant Weighted average fair value materials. Materials are charged to inventory when of stock options granted $3.90 $3.29 $3.59 purchased and then expensed or capitalized to plant, as appropriate, when installed. Financial Instruments Fuel Inventory The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of Fuel inventory includes the average costs of oil, coal, and certain fuel purchases, and electricity purchases and sales.

natural gas. Fuel is charged to inventory when purchased All derivative financial instruments are recognized as and then expensed as used. Emission allowances granted either assets or liabilities and are measured at fair value.

by the Environmental Protection Agency (EPA) are Substantially all of the Company's bulk energy purchases included in inventory at zero cost. and sales contracts that meet the definition of a derivative are exempt from fair value accounting requirements and Stock Options are accounted for under the accrual method. Other derivative contracts qualify as cash flow hedges of Southern Company provides non-qualified stock options anticipated transactions or are recoverable through the to a large segment of the Company's employees ranging Alabama PSC approved fuel-hedging program. This from line management to executives. The Company results in the deferral of related gains and losses in other accounts for its stock-based compensation plans in comprehensive income or regulatory assets and liabilities, accordance with Accounting Principles Board Opinion respectively, until the hedged transactions occur. Any No. 25. Accordingly, no compensation expense has been ineffectiveness arising from cash flow hedges is recognized recognized because the exercise price of all options currently in net income. Other derivative contracts are granted equaled the fair-market value of Southern marked to market through current period income and are Company's common stock on the date of grant. When recorded on a net basis in the statements of income.

options are exercised, the Company receives a capital contribution from Southern Company equivalent to the The Company is exposed to losses related to financial related income tax benefit. instruments in the event of counterparties' nonperformance. The Company has established controls For pro forma purposes, Southern Company generally to determine and monitor the creditworthiness of recognizes stock option expense on a straight-line basis counterparties in order to mitigate the Company's over the vesting period. Stock options granted to exposure to counterparty credit risk.

employees who are eligible for retirement are expensed at the grant date. The pro forma impact of fair-value accounting for options granted on earnings is as follows:

As Options Pro Net Income Reported Impact Forma (in thousands) 2005 $507,895 $(2,829) $505,066 2004 481,171 (2,575) 478,596 2003 472,810 (2,762) 470,048 36

NOTES (continued)

Alabama Power Company 2005 Annual Report The Company's other financial instruments for which 2. RETIREMENT BENEFITS the carrying amount did not equal fair value at December 31 were as follows: The Company has a defined benefit, trusteed, pension plan Carrying Fair covering substantially all employees. The plan is funded in Amount Value accordance with requirements of the Employee Retirement (in millions) Income Security Act of 1974, as amended (ERISA). In 2005, the plan was amended to provide an additional Long-term debt: monthly supplement to certain retirees. No contributions to 2005 $4,416 $4,403 the plan are expected for the year ending December 31, 2004 4,389 4,454 2006. The Company also provides certain non-qualified benefit plans for a selected group of management and The fair values were based on either closing market highly-compensated employees. Benefits under these non-price or closing price of comparable instruments. qualified plans are funded on a cash basis. In addition, the Comprehensive Income Company provides certain medical care and life insurance benefits for retired employees. The Company funds trusts to The objective of comprehensive income is to report a the extent required by the Alabama PSC. For the year ended measure of all changes in common stock equity of an December 31, 2006, postretirement trust contributions are enterprise that result from transactions and other economic expected to total approximately $24.9 million.

events of the period other than transactions with owners.

Comprehensive income consists of net income, changes in The measurement date for plan assets and obligations the fair value of qualifying cash flow hedges and is September 30 for each year.

marketable securities, and changes in additional minimum pension liability, less income taxes and reclassifications Pension Plans for amounts included in-net income.

The accumulated benefit obligation for the pension plans Variable Interest Entities was $1.3 billion in 2005 and $1.2 billion in 2004. Changes during the year in the projected benefit obligations, The primary beneficiary of a variable interest entity accumulated benefit obligations, and fair value of plan must consolidate the related assets and liabilities. The assets were as follows:

Company has established certain wholly-owned trusts Projected to issue preferred securities. See Note 6 under Benefit Obligations "Mandatorily Redeemable Preferred Securities/Long- 2005 2004 Term Debt Payable to Affiliated Trusts" for additional (in millions) information. However, the Company is not the primary Balance at beginning of year $1,325 $1,200 beneficiary of the trusts. Therefore, the investments in Service cost 33 30 these trusts are reflected as Other Investments, and the Interest cost 74 71 related loans from the trusts are reflected as Long-term Benefits paid (65) (64)

Debt Payable to Affiliated Trusts in the balance sheets. Plan amendments 8 1 See Note 6 under "Mandatorily Redeemable Preferred Actuarial (gain) loss 46 87 Securities/Long-Term Debt Payable to Affiliated Balance at end of year $1,421 $1,325 Trusts" for additional information.

Plan Assets Investments 2005 2004 (in millions)

The Company maintains an investment in a debt security Balance at beginning of year $1,676 $1,583 that matures in 2018 and is classified as available-for-sale. Actual return on plan assets 262 157 This security is included in the balance sheets under Other Employer contributions 4 4 Property and Investments-Other and totaled $4.4 million Benefits paid (67) (68) and $4.8 million at December 31, 2005 and 2004, Balance at end of year $1,875 $1,676 respectively. Because the interest rate resets weekly, the carrying value approximates the fair market value. In 2005, the projected benefit obligations for the qualified and non-qualified pension plans were $1.3 billion and $85 million, respectively. All plan assets are related to the qualified plan.

37

NOTES (continued)

Alabama Power Company 2005 Annual Report Pension plan assets are managed and invested in Future benefit payments reflect expected future accordance with all applicable requirements, including service and are estimated based on assumptions used to ERISA and the Internal Revenue Code of 1986, as measure the projected benefit obligations for the pension amended (Internal Revenue Code). The Company's plans. At December 31, 2005, estimated benefit payments investment policy covers a diversified mix of assets, were as follows:

including equity and fixed income securities, real estate, Benefit and private equity, as described in the table below. Payments Derivative instruments are used primarily as hedging tools (in millions) but may also be used to gain efficient exposure to the 2006 $ 65.2 various asset classes. The Company primarily minimizes 2007 66.6 the risk of large losses through diversification but also 2008 68.4 monitors and manages other aspects of risk. 2009 70.6 Plan Assets 2010 73.6 Target 2005 2004 2011 to 2015 $429.2 Domestic equity 36% 40% 36%

International equity 24 24 20 Postretirement Benefits Fixed income 15 17 26 Real estate 15 13 10 Changes during the year in the accumulated benefit Private equity 10 6 8 obligations and in the fair value of plan assets were as Total 100% 100% 100% follows:

The reconciliations of the funded status with the Accumulated accrued pension costs recognized in the balance sheets Benefit Obligations were as follows: 2005 2004 2005 2004 (in millions)

(in millions) Balance at beginning of year $465 $441 Funded status $454 $351 Service cost 7 7 Unrecognized prior service cost 79 80 Interest cost 26 24 Unrecognized net (gain) loss (52) 27 Benefits paid (21) (18)

Prepaid pension asset, net $481 $458 Actuarial (gain) loss 13 11 Balance at end of year $490 $465 The prepaid pension asset, net is reflected in the balance sheets in the following line items: Plan Assets 2005 2004 2005 2004 (in millions) (in millions)

Prepaid pension asset $515 $489 Balance at beginning of year $212 $186 Employee benefit obligations (67) (60) Actual return on plan assets 28 24 Intangible asset 10 10 Employer contributions 26 20 Accumulated other Benefits paid (21) (18) comprehensive income 23 19 Balance at end of year $245 $212 Prepaid pension asset, net $481 $458 Postretirement benefits plan assets are managed and Components of the pension plans' net periodic cost invested in accordance with all applicable requirements, were as follows: including ERISA and the Internal Revenue Code. The 2005 2004 2003 Company's investment policy covers a diversified mix of (in millions) assets, including equity and fixed income securities, real estate, and private equity, as described in the table below.

Service cost $ 33 $ 30 $ 27 Derivative instruments are used primarily as hedging tools Interest cost 74 71 68 but may also be used to gain efficient exposure to the Expected return on plan assets (139) (138) (138) various asset classes. The Company primarily minimizes Recognized net (gain) loss 2 (3) (12) the risk of large losses through diversification but also Net amortization 9 4 3 monitors and manages other aspects of risk.

Net pension cost (income) $ (21) $ (36) $ (52) 38

NOTES (continued)

Alabama Power Company 2005 Annual Report Plan Assets Benefit Subsidy Target 2005 2004 Payments Receipts Total Domestic equity 49% 53% 46% (in millions)

International equity 11 11 13 2006 $ 24.5 $ (2.6) $ 21.9 Fixed income 29 28 33 2007 25.6 (3.1) 22.5 Real estate 7 6 5 2008 27.8 (3.5) 24.3 Private equity 4 2 3 2009 30.4 (3.8) 26.6 Total 100% 100% 100% 2010 32.9 (4.1) 28.8 2011 to 2015 $180.2 $(27.7) $152.5 The accrued postretirement costs recognized in the balance sheets were as follows: Actuarial Assumptions 2005 2004 (in millions) The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations Funded status $(245) $(253) and the net periodic costs for the pension and Unrecognized transition obligation 29 33 postretirement benefit plans were as follows:

Unrecognized prior service cost 64 68 Unrecognized net loss (gain) 85 87 2005 2004 2003 Fourth quarter contributions 12 9 Discount 5.50% 5.75% 6.00%

Accrued liability recognized in the Annual salary increase 3.00 3.50 3.75 balance sheets $ (55) $ (56) Long-term return on plan assets 8.50 8.50 8.50 Components of the postretirement plans' net periodic The Company determined the long-term rate of return cost were as follows: based on historical asset class returns and current market 2005 2004 2003 conditions, taking into account the diversification benefits i (in millions) of investing in multiple asset classes. I Service cost $ 7 $ 7 $ 6 Interest cost 26 24 25 An additional assumption used in measuring the Expected return on plan assets (16) (18) (17) APBO was a weighted average medical care cost trend Net amortization 11 9 9 rate of 10.25 percent for 2005, decreasing gradually to Net postretirement cost $ 28 $ 22 $ 23 4.75 percent through the year 2014, and remaining at that level thereafter. An annual increase or decrease in the In the third quarter 2004, the Company assumed medical care cost trend rate of 1 percent would prospectively adopted FASB Staff Position (FSP) 106- affect the accumulated benefit obligation and the service 2, Accounting and Disclosure Requirements related to and interest cost components at December 31, 2005 as the Medicare Prescription Drug, Improvement, and follows:

Modernization Act of 2003 (Medicare Act). The I Percent 1 Percent Medicare Act provides a 28 percent prescription drug Increase Decrease subsidy for Medicare eligible retirees. FSP 106-2 (in millions) requires recognition of the impacts of the Medicare Act in the accumulated postretirement benefit obligation Benefit obligation $40 $35 (APBO) and future cost of service for postretirement Service and interest costs 3 2 medical plans. The effect of the subsidy reduced the Company's expenses for the six months ended Employee Savings Plan December 31, 2004 and for the year ended December 31, 2005 by approximately $3.2 million and $8.7 The Company also sponsors a 401(k) defined contribution million, respectively, and is expected to have a similar plan covering substantially all employees. The Company impact on future expenses. provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching Future benefit payments, including prescription drug contributions made to the plan for 2005, 2004, and 2003 benefits, reflect expected future service and are estimated were $14 million, $13 million, and $12 million, based on assumptions used to measure the accumulated respectively.

benefit obligation for the postretirement plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Act as follows:

39

NOTES (continued)

Alabama Power Company 2005 Annual Report

3. CONTINGENCIES AND REGULATORY participating in mediation with respect to the EPA's MATTERS claims.

General Litigation Matters The Company believes that it complied with applicable laws and the EPA regulations and interpretations in effect at The Company is subject to certain claims and legal actions the time the work in question took place. The Clean Air Act arising in the ordinary course of business. In addition, the authorizes maximum civil penalties of $25,000 to $32,500 Company's business activities are subject to extensive per day, per violation at each generating unit, depending governmental regulation related to public health and the on the date of the alleged violation. An adverse outcome environment. Litigation over environmental issues and in this matter could require substantial capital expenditures claims of various types, including property damage, that cannot be determined at this time and could possibly personal injury, and citizen enforcement of environmental require payment of substantial penalties. This could affect requirements such as opacity and other air quality future results of operations, cash flows, and possibly standards, has increased generally throughout the United financial condition if such costs are not recovered through States. In particular, personal injury claims for damages regulated rates.

caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such FERC Matters pending or potential litigation against the Company cannot be predicted at this time; however, for proceedings not Market-BasedRate Authority specifically reported herein, management does not anticipate that the liabilities, if any, arising from such The Company has authorization from the FERC to sell proceedings would have a material adverse effect on the power to nonaffiliates at market-based prices. The Company's financial statements. Company also has FERC authority to make short-term opportunity sales at market rates. Specific FERC Environmental Matters approval must be obtained with respect to a market-based contract with an affiliate.

New Source Review Actions In December 2004, the FERC initiated a proceeding In November 1999, the Environmental Protection Agency to assess Southern Company's generation dominance (EPA) brought a civil action in the U.S. District Court for within its retail service territory. The ability to charge market-based rates in other markets is not an issue in the Northern District of Georgia against the Company, that proceeding. In February 2005, Southern Company alleging that the Company had violated the New Source submitted responsive information. In February 2006, Review (NSR) provisions of the Clean Air Act and related the FERC suspended the proceeding to allow the parties state laws with respect to coal-fired generating facilities at to conduct settlement discussions. Any new market-the Company's Plants Miller, Barry, and Gorgas. The based rate transactions in its retail service territory EPA concurrently issued to the Company a notice of entered into after February 27, 2005 are subject to violation relating to these specific facilities, as well as refund to the level of the default cost-based rates, Plants Greene County and Gaston. In early 2000, the EPA pending the outcome of the proceeding. The impact of filed a motion to amend its complaint to add the violations such sales to the Company through December 31, 2005 alleged in its notice of violation. The civil action requests is not expected to exceed $3.6 million. The refund penalties and injunctive relief, including an order period covers 15 months. In the event that the FERC's requiring the installation of the best available control default mitigation measures for entities that are found technology at the affected units. The Northern District of to have market power are ultimately applied, the Georgia granted the Company's motion to dismiss for lack Company may be required to charge cost-based rates of jurisdiction in Georgia. The EPA refiled its claims for certain wholesale sales in the Southern Company against the Company in the U.S. District Court for the retail service territory, which may be lower than Northern District of Alabama. On June 3, 2005, the U.S. negotiated market-based rates. The final outcome of District Court for the Northern District of Alabama issued this matter will depend on the form in which the final methodology for assessing generation market power a decision in favor of the Company on two primary legal and mitigation rules may be ultimately adopted and issues in the case; however, the decision does not resolve cannot be determined at this time.

the case, nor does it address other legal issues associated with the EPA's allegations. In accordance with a separate court order, the Company and the EPA are currently 40

NOTES (continued)

Alabama Power Company 2005 Annual Report In addition, in May 2005, the FERC started an preside over the hearing in this proceeding and that the investigation to determine whether Southern Company testimony and exhibits presented in that proceeding be satisfies the other three parts of the FERC's market-based preserved to the extent appropriate. Hearings are rate analysis: transmission market power, barriers to entry, scheduled for September 2006. Effective July 19, 2005, and affiliate abuse or reciprocal dealing. The FERC revenues from transactions under the IIC involving any established a new refund period related to this expanded Southern Company subsidiaries are subject to refund to investigation. Any and all new market-based rate the extent the FERC orders any changes to the IIC.

transactions both inside and outside Southern Company's retail service territory involving any Southern Company The Company believes that there is no meritorious subsidiary, including the Company, will be subject to basis for these allegations and is vigorously defending refund to the extent the FERC orders lower rates as a result itself in this matter. However, the final outcome of this of this new investigation, with the 15-month refund period matter, including any remedies to be applied in the event beginning July 19, 2005. The impact of such sales to the of an adverse ruling in this proceeding, cannot now be Company through December 31, 2005, is not expected to determined.

exceed $8.9 million, of which $2.6 million relates to sales inside the retail service territory discussed above. The 15- Generation Interconnection Agreements month refund period will end on October 19, 2006. The FERC also directed that this expanded proceeding be held In July 2003, the FERC issued its final rule on the in abeyance pending the outcome of the proceeding on the standardization of generation interconnection agreements Intercompany Interchange Contract (TIC) discussed below. and procedures (Order 2003). Order 2003 shifts much of the financial burden of new transmission investment from The Company believes that there is no meritorious the generator to the transmission provider. The FERC has basis for this proceeding and is vigorously defending itself indicated that Order 2003, which was effective January 20, 2004, is to be applied prospectively to interconnection in this matter. However, the final outcome of this matter, agreements. Subsidiaries of Tenaska, Inc., as including any remedies to be applied in the event of an counterparties to two previously executed interconnection adverse ruling in this proceeding, cannot now be agreements with the Company, have filed complaints at determined. the FERC requesting that the FERC modify the agreements and that the Company refund a total of $ 11 IntercompanyInterchangeContract million previously paid for interconnection facilities, with interest. These proceedings are still pending at the FERC.

The Company's generation fleet in its retail service The Company has also received similar requests from territory is operated under the IIC, as approved by the other entities totaling approximately $7 million. The FERC. In May 2005, the FERC initiated a new Company has opposed all such requests. The impact of proceeding to examine (1) the provisions of the IIC among Order 2003 and its subsequent rehearings on the Company Alabama Power, Georgia Power, Gulf Power, Mississippi and the final results of these matters cannot be determined Power, Savannah Electric, Southern Power, and SCS, as at this time.

agent, under the terms of which the power pool of Southern Company is operated, and, in particular, the Retail Regulatory Matters propriety of the continued inclusion of Southern Power as a party to the IIC, (2) whether any parties to the IIC have The following retail ratemaking procedures will remain in violated the FERC's standards of conduct applicable to effect until the Alabama PSC votes to modify or utility companies that are transmission providers, and (3) discontinue them.

whether Southern Company's code of conduct defining Southern Power as a "system company" rather than a Rate RSE "marketing affiliate" is just and reasonable. In connection with the formation of Southern Power, the FERC The Alabama PSC has adopted a Rate Stabilization and authorized Southern Power's inclusion in the IIC in 2000. Equalization plan (Rate RSE) that provides for periodic The FERC also previously approved Southern Company's annual adjustments based upon the Company's earned code of conduct. The FERC order directs that the return on end-of-period retail common equity. Prior to administrative law judge who presided over a proceeding January 2007, annual adjustments are limited to 3 percent.

involving approval of PPAs between Southern Power, Rates remain unchanged when the return on common Georgia Power, and Savannah Electric be assigned to equity ranges between 13.0 percent and 14.5 percent. On October 4, 2005, the Alabama PSC approved a revision to 41

NOTES (continued)

Alabama Power Company 2005 Annual Report Rate RSE. Effective January 2007 and thereafter Rate million and approximately 1.2 percent in 2006, or $43 RSE adjustments are made based on forward-looking million.

information for the applicable upcoming calendar year.

Rate adjustments for any two-year period, when averaged Fuel Cost Recovery together, cannot exceed 4.0 percent per year and any annual adjustment is limited to 5.0 percent. The range of The Company has established fuel cost recovery rates return on common equity, on which such adjustments are approved by the Alabama PSC. The Company can change based, remains unchanged. If the Company's actual return the retail energy cost recovery rate after submitting to the on common equity is above the allowed equity return Alabama PSC an estimate of future energy costs and the range, customer refunds will be required; however, there current over or under recovered balance. In response to is no provision for additional customer billings should the such a request, the Alabama PSC may conduct a public actual return on common equity fall below the allowed hearing prior to its ruling. Alternatively, the retail energy equity return range. The Company will make its initial cost recovery rates requested by the Company will submission of projected data for calendar year 2007 by become effective 45 days after the initial request.

December 1, 2006. In conjunction with the Alabama PSC approval of a rate mechanism to recover retail costs In December 2005, the Alabama PSC approved the associated with environmental laws and regulations in Company's request to increase the retail energy cost October 2004, the Company agreed to a moratorium on recovery rate to 2.400 cents per kilowatt-hour, effective retail rate increases under Rate RSE through 2006. See with billings beginning January 1, 2006.

"Rate CNP" herein for additional information.

NaturalDisasterCost Recovery Rate CNP In September 2004, Hurricane Ivan hit the Gulf Coast of The Alabama PSC has also approved a rate mechanism Florida and Alabama and continued north through the that provides for adjustments to recognize the placing of Company's service territory causing substantial damage.

new generating facilities in retail service and for the The related costs charged to the Company's NDR were recovery of retail costs associated with certificated $57.8 million. During 2004, the Company accrued $9.9 purchased power agreements (Rate CNP). In October million to the reserve and at December 31, 2004, the 2004, the Alabama PSC approved a request by the reserve balance was a regulatory asset of $37.7 million.

Company to amend Rate CNP to provide for the recovery of retail costs associated with environmental laws and In February and December 2005, the Company regulations. Environmental costs to be recovered include requested and received Alabama PSC approval of an operation and maintenance expenses, depreciation and a accounting order that allowed the Company to return on invested capital. This component of Rate CNP immediately return certain regulatory liabilities to the began operation in January 2005. retail customers. These orders also allowed the Company to simultaneously recover from customers an accrual of To recover certificated purchased power costs under approximately $48 million to primarily offset the costs of Rate CNP, increases of 2.6 percent in retail rates, or $79 Hurricane Ivan and restore a positive balance in the million annually were effective July 2003 and 0.8 percent natural disaster reserve. The combined effects of these in retail rates, or $25 million annually were effective July orders had no impact on the Company's net income in 2004 for certificated purchase power cost. In April 2005, 2005.

an adjustment to Rate CNP decreased retail rates by approximately 0.5 percent, or $19 million annually. In On July 10, 2005 and August 29, 2005, Hurricanes April 2006, an annual true-up adjustment to Rate CNP is Dennis and Katrina, respectively, hit the coast of Alabama expected to increase retail rates by approximately 0.5 and continued north through the state, causing significant percent, or $19 million annually. damage in parts of the service territory of the Company.

Approximately 241,000 and 637,000 of the Company's The retail rates associated with the recovery of retail 1.4 million customer accounts were without electrical costs associated with environmental laws and regulations service immediately after Hurricanes Dennis and Katrina, under Rate CNP are adjusted annually in January. Retail respectively. The Company sustained significant damage rates increased approximately 1.0 percent in 2005, or $33 to its distribution and transmission facilities during these storms.

42

NOTES (continued)

Alabama Power Company 2005 Annual Report In August 2005, the Company received approval from cancel upon two year's notice. The Company's share of the Alabama PSC to defer the Hurricane Dennis storm- purchased power totaled $90 million in 2005, $86 million related operation and maintenance costs (approximately in 2004, and $87 million in 2003 and is included in

$28 million). In October 2005, the Company also "Purchased power from affiliates" in the statements of received similar approval from the Alabama PSC to defer income. The Company accounts for SEGCO using the the Hurricane Katrina storm-related operation and equity method.

maintenance costs (approximately $30 million). The NDR balance at December 31, 2005 was a regulatory asset of In addition, the Company has guaranteed

$50.6 million. unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain In December 2005, the Alabama PSC approved a pollution control facilities at SEGCO's generating units, request by the Company to replenish the depleted NDR pursuant to which $24.5 million principal amount of and allow for recovery of future natural disaster costs. The pollution control revenue bonds are outstanding. Also, the Alabama PSC order gives the Company authority to Company has guaranteed $50 million principal amount of record a deficit balance in the NDR when costs of unsecured senior notes issued by SEGCO for general uninsured storm damage exceed any established reserve corporate purposes. Georgia Power has agreed to reimburse balance. The order also approved a separate monthly the Company for the pro rata portion of such obligations NDR charge consisting of two components beginning corresponding to its then proportionate ownership of stock January 2006. The first component is intended to of SEGCO if the Company is called upon to make such establish and maintain a target reserve balance of $75 payment under its guaranty.

million for future storms and is an on-going part of customer billing. The Company currently expects that the At December 31, 2005, the capitalization of SEGCO target reserve balance could be achieved within five years. consisted of $60 million of equity and $89 million of debt The second component of the NDR charge is intended to on which the annual interest requirement is $3.2 million.

allow recovery of the existing deferred hurricane related SEGCO paid dividends totaling $7.7 million in 2005, $12.0 operation and maintenance costs and any future reserve million in 2004, and $2.3 million in 2003, of which one-half deficits over a 24 month period. The maximum total NDR of each was paid to the Company. In addition, the charge consisting of both components is $ 10 per month Company recognizes 50 percent of SEGCO's net income.

per non-residential customer account and $5 per month In addition to the Company's ownership of SEGCO, per residential customer account. the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December As revenue from the NDR charge is recognized, an 31, 2005 is as follows:

equal amount of operation and maintenance expense Total related to the NDR will also be recognized. As a result, this increase in revenue and expense will not have an Megawatt Company impact on net income, but will increase the annual cash Facility (Type) Capacity Ownership flow. Greene County 500 60.00% (1)

Plant Miller Units I and 2 1,320 91.84% (2)

4. JOINT OWNERSHIP AGREEMENTS (1) Jointly owned with an affiliate, Mississippi Power.

(2) Jointly owned with Alabama Electric Cooperative, Inc.

The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric Company Accumulated generating units with a total rated capacity of 1,020 Facility Investment Depreciation (inmillions) megawatts, as well as associated transmission facilities.

The capacity of these units is sold equally to the Company Greene County $115 $ 60 and Georgia Power under a contract which, in substance, Plant Miller requires payments sufficient to provide for the operating Units 1 and 2 940 374 expenses, taxes, interest expense and a return on equity, At December 31, 2005, the Company's Plant Miller whether or not SEGCO has any capacity and energy portion of construction work in progress was $4.4 million.

available. The term of the contract extends automatically for two-year periods, subject to either party's right to 43

NOTES (continued)

Alabama Power Company 2005 Annual Report The Company has contracted to operate and maintain Details of the income tax provisions are as follows:

the jointly owned facilities as agent for their co-owners.

The Company's proportionate share of its plant operating 2005 2004 2003 expenses is included in operating expenses in the (in millions) statements of income. Federal --

Current $151 $ 44 $111 Deferred 81 219 137

5. INCOME TAXES 232 263 248 State --

Southern Company files a consolidated federal income Current 27 16 26 tax return and combined income tax returns for the Deferred 34 16 26 State of Georgia and the State of Alabama. Under a joint consolidated income tax allocation agreement, 53 50 42 each subsidiary's current and deferred tax expense Total $285 $313 $290 is computed on a stand-alone basis and no subsidiary is allocated more expense than would be paid if they filed The tax effects of temporary differences between the a separate income tax return. In accordance with IRS carrying amounts of assets and liabilities in the financial regulations, each company is jointly and severally statements and their respective tax bases, which give rise liable for the tax liability. to deferred tax assets and liabilities, are as follows:

In 2004, in order to avoid the loss of certain federal 2005 2004 income tax credits related to the production of synthetic (in millions) fuel, Southern Company chose to defer certain deductions Deferred tax liabilities:

otherwise available to the subsidiaries. The cash flow Accelerated depreciation $1,626 $ 1,524 benefit associated with the utilization of the tax credits Property basis differences 440 416 was allocated to the subsidiary that otherwise would have Premium on reacquired debt 42 45 claimed the available deductions on a separate company Pensions 148 136 basis without the deferral. This allocation concurrently Fuel clause under recovered 138 48 reduced the tax benefit of the credits allocated to those Storm reserve 26 20 subsidiaries that generated the credits. As the deferred Other 46 36 expenses are deducted, the benefit of the tax credits will Total 2,466 2,225 be repaid to the subsidiaries that generated the tax credits. Deferred tax assets:

At December 31,2005 and 2004, the Company had $20.4 Federal effect of state deferred taxes 114 112 million and $21.4 million in accumulated deferred State effect of federal deferred taxes 87 110 income taxes and $2.0 million and $2.3 million in accrued Unbilled revenue 22 22 taxes - income taxes, respectively, payable to these Pension and other benefits 20 16 subsidiaries, on the balance sheets. Other comprehensive losses 19 16 Other 69 36 At December 31, 2005, the Company's tax-related Total 331 312 regulatory assets and liabilities were $389 million and Total deferred tax liabilities, net 2,135 1,913

$102 million, respectively. These assets are attributable to Portion included in current (liabilities) tax benefits flowed through to customers in prior years, to assets, net (64) (28) taxes applicable to capitalized interest, and to Accumulated deferred income taxes deferred taxes previously recognized at rates different in the balance sheets $2,071 $1,885 than the current enacted tax law. These liabilities are  ; ,

primarily attributable to unamortized investment tax In accordance with regulatory requirements, deferred credits. investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income.

Credits amortized in this manner amounted to $8.8 million in 2005, $1 1 million in 2004, and $11 million in 2003. At December 31, 2005, all investment tax credits available to reduce federal income taxes payable had been utilized.

44

NOTES (continued)

Alabama Power Company 2005 Annual Report A reconciliation of the federal statutor y income tax rate contract, the Company received payments from AMEA to the effective income tax rate is as followis: representing the net present value of the revenues 2005 2004 2003 associated with the capacity entitlement, discounted at an Federal statutory rate 35.0% 35.0% 35.0% effective annual rate of 11.19 percent. These payments were recognized as operating revenues and the discount State income tax,

-4.0 3.5 was amortized to other interest expense as scheduled net of federal deduction 4.2 capacity was made available over the terms of the Non-deductible book depreciation 1.1 1.1 1.2 contract.

Differences in prior years' To secure AMEA's advance payments and the deferred and current tax rates (4.1) (0.8) (0.9)

Company's performance obligation under the contracts, Other (1.3) (1.0) (1.6) the Company issued and delivered to an escrow agent first Effective income tax rate 34.9% 38.3% 37.2% mortgage bonds representing the maximum amount of liquidated damages payable by the Company in the event In accordance with Alabama PSC orders, the of a default under the contracts. No principal or interest Company returned approximately $30 million of excess was payable on such bonds unless and until a default by deferred income taxes to its ratepayers in 2005, resulting the Company occurred. As the liquidated damages in causing 3.6 percent of the "Difference in prior years' declined, a portion of the bond equal to the decrease was deferred and current tax rates" in the table above. See returned to the Company. At December 31, 2005, the Note 3 to the financial statements under "Retail bonds that were previously held in escrow were returned Regulatory Matters - Natural Disaster Cost Recovery" for to the Company due to the fulfillment of the contract additional information. obligation.

Pollution Control Bonds

6. FINANCING Pollution control obligations represent installment Mandatorily Redeemable Preferred Securities/ purchases of pollution control facilities financed by funds Long-Term Debt Payable to Affiliated Trusts derived from sales by public authorities of revenue bonds.

The Company has formed certain wholly owned trust The Company is required to make payments sufficient for subsidiaries for the purpose of issuing preferred securities. the authorities to meet principal and interest requirements The proceeds of the related equity investments and of such bonds. With respect to $92.8 million of such preferred security sales were loaned back to the Company pollution control obligations, the Company has through the issuance ofjunior subordinated notes totaling authenticated and delivered to the trustees a like principal

$309 million, which constitute substantially all assets of amount of first mortgage bonds as security for its these trusts and are reflected in the balance sheets as obligations under the installment purchase agreements.

Long-term Debt Payable to Affiliated Trusts. The No principal or interest on these first mortgage bonds is Company considers that the mechanisms and obligations payable unless and until a default occurs on the relating to the preferred securities issued for its benefit, installment purchase agreements.

taken together, constitute a full and unconditional guarantee by it of the respective trusts' payment Senior Notes obligations with respect to these securities. At December The Company issued a total of $250 million of unsecured 31, 2005, preferred securities of $300 million were senior notes in 2005. The proceeds of these issues were outstanding. See Note I under "Variable Interest Entities" used to repay short-term indebtedness, and for other for additional information on the accounting treatment for general corporate purposes.

these trusts and the related securities.

At December 31, 2005 and 2004, the Company had First Mortgage Bonds

$3.6 billion and $3.5 billion of senior notes outstanding, The Company had a firm power sales contract with the respectively. These senior notes are subordinate to all Alabama Municipal Electric Authority (AMEA) entitling secured debt of the Company which amounted to AMEA to scheduled amounts of capacity (up to a approximately $246 million at December 31, 2005.

maximum 80 megawatts). Under the terms of the 45

NOTES (continued)

Alabama Power Company 2005 Annual Report Securities Due Within One Year The Company borrows through commercial paper programs that have the liquidity support of committed At December 31, 2005 and 2004, the Company had bank credit arrangements. In addition, the Company scheduled maturities and redemptions of senior notes due borrows from time to time through extendible commercial within one year totaling $547 million and $225 million note programs and uncommitted credit arrangements. As respectively. of December 31, 2005, the Company had $136 million in commercial paper outstanding, $55 million in extendible Debt serial maturities through 2010 applicable to total commercial notes outstanding, and $125 million in loans long-term debt are as follows: $547 million in 2006; $669 outstanding under an uncommitted credit arrangement. As million in 2007; $410 million in 2008; $250 million in of December 31, 2004, the Company had no extendible 2009; and $100 million in 2010. commercial notes and no commercial paper outstanding.

During 2005, the peak amount outstanding for short-term Assets Subject to Lien borrowings was $315 million and the average amount outstanding was $31 million. The average annual interest The Company's mortgage, as amended and supplemented, rate on short-term borrowings in 2005 was 4.04 percent.

securing the first mortgage bonds issued by the Company, Short-term borrowings are included in notes payable in the constitutes a direct lien on substantially all of the balance sheets.

Company's fixed property and franchises.

At December 31, 2005, the Company had regulatory Bank Credit Arrangements approval to have outstanding up to $1.4 billion of short-term borrowings.

The Company maintains committed lines of credit in the amount of $878 million (including $563 million of such Financial Instruments lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds), of which The Company enters into energy-related derivatives to

$428 million will expire at various times during 2006. hedge exposures to electricity, gas, and other fuel price

$251 million of the credit facilities expiring in 2006 allow changes. However, due to cost-based rate regulations, for the execution of one-year term loans. All of the credit the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The arrangements require payment of a commitment fee based Company has implemented fuel-hedging programs at on the unused portion of the commitment or the the instruction of the Alabama PSC. The Company maintenance of compensating balances with the banks. also enters into hedges of forward electricity sales.

Commitment fees are less than 1/4 of I percent for the There was no material ineffectiveness recorded in Company. Because the arrangements are based on an earnings in 2005, 2004, and 2003.

average balance, the Company does not consider any of its cash balances to be restricted as of any specific date. For At December 31, 2005, the fair value of derivative syndicated credit arrangements, a fee is also paid to the energy contracts was reflected in the financial agent banks. statements as follows:

Amounts Most of the Company's credit arrangements with (in thousands) banks have covenants that limit the Company's debt to 65 Regulatory liabilities, net $29,044 percent of total capitalization, as defined in the Net income (66) arrangements. For purposes of calculating these Total fair value $28,978 covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. The fair value gain or loss for hedges that are Exceeding this debt level would result in a default under recoverable through the regulatory fuel clauses are the credit arrangements. At December 31, 2005, the recorded in the regulatory assets and liabilities and are Company was in compliance with the debt limit recognized in earnings at the same time the hedged covenants. In addition, the credit arrangements typically items affect earnings. The Company has energy-related contain cross default provisions that would be triggered if hedges in place up to and including 2008.

the Company defaulted on other indebtedness (including guarantee obligations) above a specified threshold. None The Company also enters into derivatives to hedge of the arrangements contain material adverse change exposure to changes in interest rates. Derivatives clauses at the time of borrowings. related to variable rate securities or forecasted 46

NOTES (continued)

Alabama Power Company 2005 Annual Report transactions are accounted for as cash flow hedges. As construction expenditures related to contractual the derivatives employed as hedging instruments are purchase commitments for uranium and nuclear fuel generally structured to match the critical terms of the conversion, enrichment, and fabrication services hedged debt instruments, no material ineffectiveness included under "Fuel Commitments" herein. The has been recorded in earnings. construction programs are subject to periodic review and revision, and actual construction costs may vary At December 31, 2005, the Company had from the above estimates because of numerous factors.

$1.3 billion notional amount of interest rate swaps These factors include: changes in business conditions; outstanding with net fair value gains of $25.3 million as revised load growth estimates; changes in follows: environmental regulations; changes in existing nuclear plants to meet new regulatory requirements; changes in Weighted Average Fair FERC rules and regulations; increasing costs of labor, Fixed Value equipment, and materials; and cost of capital. At Rate Notional Gain/ December 31, 2005, significant purchase commitments Maturity Paid Amount (Loss) were outstanding in connection with the construction (in millions) program. The Company has no generating plants under 2006 1.89 $195 $2.5 construction. Construction of new transmission and 2007 2.01* 536 7.3 distribution facilities and capital improvements, 2016 4.82 300 3.0 including those needed to meet environmental 2016 4.42 300 12.5 standards for existing generation, transmission, and

• Hedged using the Bond Market Association Municipal Swap Index. distribution facilities, will continue.

The fair value gain or loss for cash flow hedges is Long-Term Service Agreements recorded in other comprehensive income and is reclassified into earnings at the same time the hedged The Company has entered into several Long-Term items affect earnings. In 2005,2004, and 2003, the Service Agreements (LTSAs) with General Electric Company settled gains (losses) of $(21.4) million, $5.5 (GE) for the purpose of securing maintenance support million and $(8.0) million, respectively, upon termination for its combined cycle and combustion turbine of certain interest derivatives at the same time it issued generating facilities. The LTSAs provide that GE will debt. These gains (losses) have been deferred in other perform all planned inspections on the covered comprehensive income and will be amortized to interest equipment, which includes the cost of all labor and expense over the life of the original interest derivative, materials. GE is also obligated to cover the costs of which approximates to the underlying related debt. unplanned maintenance on the covered equipment subject to a limit specified in each contract.

For the years 2005, 2004 and 2003, approximately

$3.5 million, $(6.3) million, and $(11.3) million, In general, these LTSAs are in effect through two respectively, of pre-tax gains/(losses) were reclassified major inspection cycles per unit. Scheduled payments from other comprehensive income to interest expense. to GE are made at various intervals based on actual For 2006, pre-tax gains of approximately $9.4 million are operating hours of the respective units. Total payments expected to be reclassified from other comprehensive to GE under these agreements for facilities owned are income to interest expense. The Company has interest- currently estimated at $263 million over the term of the related hedges in place through 2016 and has gains/losses agreements, which are approximately 12 to 14 years per that are being amortized through 2035. unit. At December 31, 2005, the remaining balance was approximately $181 million. However, the LTSAs contain various cancellation provisions at the option of

7. COMMITMENTS the Company. I Construction Program Payments made to GE prior to the performance of any planned maintenance are recorded as either The Company is engaged in continuous construction prepayments or other deferred charges and assets in the programs, currently estimated to total $0.9 billion in balance sheets. Inspection costs are capitalized or 2006, $1.1 billion in 2007, and $1.1 billion in 2008.

These amounts include $18 million, $11 million, and'$9 charged to expense based on the nature of the work million in 2006, 2007, and 2008, respectively, for performed.

47

NOTES (continued)

Alabama Power Company 2005 Annual Report Purchased Power Commitments Company GAS may be jointly and severally liable. The creditworthiness of Southern Power and Southern The Company has entered into various long-term Company GAS is currently inferior to the creditworthiness commitments for the purchase of electricity. Total of the retail operating companies. Accordingly, Southern estimated minimum long-term obligations at December Company has entered into keep-well agreements with the 31, 2005 were as follows: Company and each of the other retail operating companies Commitments to insure the Company will not subsidize or be responsible Non- for any costs, losses, liabilities, or damages resulting from Year Affiliate d Affiliated Total the inclusion of Southern Power or Southern Company (in millions) GAS as a contracting party under these agreements.

2006 $ SO $ 37 $ 87 2007 50 38 88 Operating Leases 2008 50 39 89 1 2009 50 40 190 The Company has entered into rental agreements for coal 2010 12 23 35 rail cars, vehicles, and other equipment with various terms l 2011 and thereafter 2 2 and expiration dates. These expenses totaled $27.3 Total commitments $212 $179 $391 million in 2005, $28.3 million in 2004, and $29.5 million in 2003. Of these amounts, $17.8 million, $16.3 million, Fuel Commitments and $19.4 million for 2005, 2004, and 2003, respectively, relates to the rail car leases and are recoverable through To supply a portion of the fuel requirements of its the Company's Rate ECR. At December 31, 2005, generating plants, the Company has entered into various estimated minimum rental commitments for long-term commitments for the procurement of fossil and noncancellable operating leases were as follows:

nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels, Rail Vehicles and other financial commitments. Natural gas purchase Year Cars & Other Total commitments contain given volumes with prices based on (in millions) various indices at the time of delivery. Amounts included 2006 $16.2 $7.4 $23.6 in the chart below represent estimates based on New York 2007 8.9 6.1 15.0 Mercantile Exchange future prices at December 31, 2005. 2008 8.6 4.9 13.5 Total estimated minimum long-term commitments at 2009 4.8 4.6 9.4 December 31, 2005 were as follows: 2010 3.5 4.1 7.6 Natural Nuclear 201 1 and thereafter 24.0 5.1 29.1 Year Gas Coal Fuel Total minimum paments $66.0 $32.2 $98.2 (in millions) 2006 $ 545 $1,065 $18 In addition to the rental commitments above, the 2007 269 1,027 11 Company has potential obligations upon expiration of 2008 145 524 9 certain leases with respect to the residual value of the 2009 26 442 3 leased property. These leases expire in 2006 and 2009, 2010 19 422 6 and the Company's maximum obligations are $66 million 2011 and thereafter 89 324 26 and $20 million, respectively. At the termination of the Total commitments $1,093 $3,804 $73 leases, at the Company's option, the Company may Additional commitments for fuel will be required to negotiate an extension, exercise its purchase option, or the supply the Company's future needs. property can be sold to a third party. The Company expects that the fair market value of the leased property SCS may enter into various types of wholesale energy would substantially eliminate the Company's payments under the residual value obligations.

and natural gas contracts acting as an agent for the Company and all of the other Southern Company retail operating companies, Southern Power, and Southern Guarantees Company GAS. Under these agreements, each of the retail operating companies, Southern Power, and Southern At December 31,2005, the Company had outstanding guarantees related to SEGCO's purchase of certain 48

NOTES (continued)

Alabama Power Company 2005 Annual Report pollution control facilities and issuance of senior notes, as The following table summarizes information about discussed in Note 4, and to certain residual values of options outstanding at December 31, 2005:

leased assets as described above in "Operating Leases." Dollar Price Range of Options 13-21 21-28 28-35

8. STOCK OPTION PLAN Outstanding:

Shares (in thousands) 700 2,266 2,262 Southern Company provides non-qualified stock Average remaining options to a large segment of the Company's employees life (in years) 4.3 6.3 8.6 ranging from line management to executives. As of Average exercise price $17.30 $26.05 $31.17 December 31, 2005, 1,106 current and former Exercisable:

employees of the Company participated in this stock Shares (in thousands) 700 1,897 346 option plan. The maximum number of shares of Average exercise price $17.30 $25.68 $29.59 Southern Company common stock that may be issued under the plan may not exceed 55 million. The prices of options granted to date have been at the fair market value of the shares on the dates of grant. Options 9. NUCLEAR INSURANCE granted to date become exercisable pro rata over a maximum period of three years from the date of grant. Under the Price-Anderson Amendment Act (Act), the Options outstanding will expire no later than 10 years Company maintains agreements of indemnity with the after the date of grant, unless terminated earlier by the NRC that, together with private insurance, cover Southern Company Board of Directors in accordance third-party liability arising from any nuclear incident with the stock option plan. Activity from 2003 to 2005 occurring at Plant Farley. The Act provides funds up to for the options granted to the Company's employees $10.8 billion for public liability claims that could arise under the stock option plan is summarized below: from a single nuclear incident. Plant Farley is insured Shares Average against this liability to a maximum of $300 million by Subject Option Price American Nuclear Insurers (ANI), with the remaining to Option per Share coverage provided by a mandatory program of deferred Balance at December 31, 2002 5,693,923 $19.72 .

premiums that could be assessed, after a nuclear incident, Options granted 1,201,469 27.98 against all owners of nuclear reactors. The Company Options canceled (6,726) 23.11 could be assessed up to $ 101 million per incident for each Options exercised (1,043,013) 16.16 licensed reactor it operates but not more than an aggregate Balance at December 31, 2003 5,845,653 22.05 of $15 million per incident to be paid in a calendar year I Options granted 1,168,140 29.50 for each reactor. Such maximum assessment, excluding Options canceled (3,379) 28.82 any applicable state premium taxes, for the Company is Options exercised (1,252,277) 18.07 $201 million per incident but not more than an aggregate Balance at December 31, 2004 5,758,137 24.42 ---.

of $30 million to be paid for each incident in any one year.

Options granted 1,180,491 32.70 Options canceled (1,973) 30.10 The Company is a member of Nuclear Electric Options exercised (1,708,670) 21.95 Insurance Limited I(NEIL),

11INUIMILor, 111111LUU lNnll a LHULUdl I. U mutual 11INUICL insurer CMUMINIMU established toLU Balance at December 31, 2005 5,227,985 $27.09 provide property damage insurance in an amount up to

$500 million for members' nuclear generating facilities.

Options exercisable:

At December 31, 2003 3,171,383 At December 31, 2004 3,404,264 Additionally, the Company has policies that currently At December 31, 2005 2,943,134 provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.3 billion for losses in excess of the $500 million primary coverage.

This excess insurance is also provided by NEIL.

NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant.

Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a 49

NOTES (continued)

Alabama Power Company 2005 Annual Report maximum per occurrence per unit limit of $490 million. 10. QUARTERLY FINANCIAL INFORMATION After this deductible period, weekly indemnity payments (UNAUDITED) would be received until either the unit is operational or until the limit is exhausted in approximately three years. Summarized quarterly financial information for 2005 and The Company purchases the maximum limit allowed by 2004 are as follows:

NEIL and has elected a 12-week waiting period. Net Income After Under each of the NEIL policies, members are subject Dividends to assessments if losses each year exceed the accumulated Quarter Operating Operating on Preferred funds available to the insurer under that policy. The Ended -

Revenues Income Stock current maximum annual assessments for the Company (in millions) under the NEIL policies would be $41 million.

March 2005 $ 970 $157 $ 93 Following the terrorist attacks of September 2001, June 2005 1,086 253 122 both ANI and NEIL confirmed that terrorist acts against September 2005 1,458 443 236 commercial nuclear power plants would, subject to the December 2005 1,134 161 57 normal policy limits, be covered under their insurance.

Both companies, however, revised their policy terms on a March 2004 $ 960 $202 $ 91 prospective basis to include an industry aggregate for all June 2004 1,059 239 104 "non-certified" terrorist acts, i.e., acts that are not certified September 2004 1,246 415 220 acts of terrorism pursuant to the Terrorism Risk Insurance December 2004 971 164 66 Act of 2002, which was renewed in 2005. The aggregate The Company's business is influenced by seasonal for all NEIL policies, which applies to non-certified weather conditions.

property claims stemming from terrorism within a 12 month duration, is $3.2 billion plus any amounts available through reinsurance or indemnity from an outside source.

The non-certified ANI nuclear liability cap is a $300 million shared industry aggregate during the normal ANI policy period.

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

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

50

SELECTED FINANCIAL AND OPERATING DATA 2001-2005 Alabama Power Company 2005 Annual Report 2005 2004 2003 2002 2001 Operating Revenues (in thousands) $4,647,824 $4,235,991 $3,960,161 $3,710,533 $3,586,390 Net Income after Dividends on Preferred Stock (inthousands) $507,895 $481,171 $472,810 $461,355 $386,729 Cash Dividends on Common Stock (inthousands) $409,900 $437,300 $430,200 $431,000 $393,900 Return on Average Common Equity (percent) 13.72 13.53 13.75 13.80 11.89 Total Assets (inthousands) $13,689,907 $12,781,525 $12,099,575 $11,591,666 $11,303,605 Gross Property Additions (in thousands) $890,062 $786,298 $661,154 $645,262 $635,540 Capitalization (in thousands):

Common stock equity $3,792,726 $3,610,204 $3,500,660 $3,377,740 $3,310,877 Preferred stock 465,046 465,047 372,512 247,512 317,512 Mandatorily redeemable preferred securities - - 300,000 300,000 347,000 Long-term debt payable to affiliated trusts 309,279 309,279 - - -

Long-term debt 3,560,186 3,855,257 3,377,148 2,872,609 3,742,346 Total (excluding amounts due within one year) $8,127,237 $8,239,787 $7,550,320 $6,797,861 $7,717,735 Capitalization Ratios (percent):

Common stock equity 46.7 43.8 46.4 49.7 42.9 Preferred stock 5.7 5.6 4.9 3.6 4.1 Mandatorily redeemable preferred securities - - 4.0 4.4 4.5 Long-term debt payable to affiliated trusts 3.8 3.8 - - -

Long-term debt 43.8 46.8 44.7 42.3 48.5 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 AA- AA- A+ A+ A+

Preferred Stock -

Moody's Baal Baal Baal Baal Baal Standard and Poor's BBB+ BBB+ BBB+ BBB+ BBB+

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 i A Fitch A+ A+ A A A Customers (year-end):

Residential 1,184,406 1,170,814 1,160,129 1,148,645 1,139,542 Commercial 212,546 208,547 204,561 203,017 196,617 Industrial 5,492 5,260 5,032 4,874 4,728 Other 759 753 757 789 751 Total 1,403,203 1,385,374 1,370,479 1,357,325 1,341,638 Employees (year-end) 6,621 6,745 6,730 6,715 6,706 51

SELECTED FINANCIAL AND OPERATING DATA 2001-2005 (continued)

Alabama Power Company 2005 Annual Report 2005 2004 2003 2002 2001 Operating Revenues (in thousands):

Residential $1,476,211 $1,346,669 $1,276,800 $1,264,431 $1,138,499 Commercial 1,062,341 980,771 913,697 882,669 829,760 Industrial 1,065,124 948,528 844,538 788,037 763,934 Other 17,745 16,860 16,428 16,080 15,480 Total retail 3,621,421 3,292,828 3,051,463 2,951,217 2,747,673 Sales for resale - non-affiliates 551,408 483,839 487,456 474,291 485,974 Sales for resale - affiliates 288,956 308,312 277,287 188,163 245,189 Total revenues from sales of electricity 4,461,785 4,084,979 3,816,206 3,613,671 3,478,836 Other revenues 186,039 151,012 143,955 96,862 107,554 Total $4,647,824 $4,235,991 $3,960,161 $3,710,533 $3,586,390 Kilowatt-Hour Sales (in thousands):

Residential 18,073,783 17,368,321 16,959,566 17,402,645 15,880,971 Commercial 14,061,650 13,822,926 13,451,757 13,362,631 12,798,711 Industrial 23,349,769 22,854,399 21,593,519 21,102,568 20,460,022 Other 198,715 198,253 203,178 205,346 198,102 Total retail 55,683,917 54,243,899 52,208,020 52,073,190 49,337,806 Sales for resale - non-affiliates 15,442,728 15,483,420 17,085,376 15,553,545 15,277,839 Sales for resale - affiliates 5,735,429 7,233,880 9,422,301 8,844,050 8,843,094 Total 76,862.074 76,961,199 78,715,697 76,470,785 73,458,739 Average Revenue Per Kilowatt-Hour (cents):

Residential 8.17 7.75 7.53 7.27 7.17 Commercial 7.55 7.10 6.79 6.61 6.48 Industrial 4.56 4.15 3.91 3.73 3.73 Total retail 6.50 6.07 5.84 5.67 5.57 Sales for resale 3.97 3.49 2.88 2.72 3.03 Total sales 5.80 5.31 4.85 4.73 4.74 Residential Average Annual Kilowatt-Hour Use Per Customer 15,347 14,894 14,688 15,198 13,981 Residential Average Annual Revenue Per Customer $1,253 $1,155 $1,106 $1,104 $1,002 Plant Nameplate Capacity Ratings (year-end) (megawatts) 12,216 12,216 12,174 12,153 12,153 Maximum Peak-Hour Demand (megawatts):

Winter 9,812 9,556 10,409 . 9,423 9,300 Summer 11,162 10,938 10,462 10,910 10,241 Annual Load Factor (percent) 63.2 63.2 64.1 62.9 62.5 Plant Availability (percent):

Fossil-steam 90.5 87.8 85.9 85.8 87.1 Nuclear 92.9 88.7 94.7 93.2 83.7 Source of Energy Supply (percent):

Coal 59.5 56.5 56.5 55.5 56.8 Nuclear 17.2 16.4 17.0 17.1 15.8 Hydro 5.6 5.6 7.0 5.1 5.1 Gas 6.8 8.9 7.6 11.6 10.7 Purchased power -

From non-affiliates 3.8 5.4 4.1 4.0 4.4 From affiliates 7.1 7.2 7.8 6.7 7.2 Total 100.0 100.0 100.0 100.0 100.0 52

DIRECTORS AND OFFICERS Alabama Power Company 2005 Annual Report Directors Officers Whit Armstrong Charles D. McCrary Myrna J. Pittman President, Chairman and CEO, President and Chief Executive Vice President The Citizens Bank Officer Donald W. Reese David J. Cooper, Sr. Art P. Beattie Vice President President, Executive Vice President, Chief R. Michael Saxon Cooper/T. Smith Corporation Financial Officer and Treasurer Vice President, Southeast Division R. Kent Henslee C. Alan Martin Julia H. Segars Managing Partner, Executive Vice President Vice President Henslee, Robertson, Strawn &

Steve R. Spencer Julian H. Smith, Jr.

Knowles, L.L.C. Executive Vice President Vice President John D. Johns Rodney 0. Mundy Chairman, President and CEO, W. Ronald Smith Senior Vice President and Counsel Vice President, Eastern Division Protective Life Corporation Robert Holmes, Jr. Zeke W. Smith Carl E. Jones, Jr. Senior Vice President Chairman, Vice President Regions Financial Corporation Robin A. Hurst Cheryl A. Thompson Senior Vice President Vice President, Mobile Division Patricia M. King President and CEO, Michael L. Scott Terry H. Waters Sunny King Automotive Group Senior Vice President Vice President, Western Division James K. Lowder Jerry L. Stewart Robert Cole Giddens Chairman, Senior Vice President Assistant Comptroller The Colonial Company Philip C. Raymond E. Wayne Boston Wallace D. Malone, Jr. Vice President and Comptroller Assistant Secretary and Vice Chairman, William E. Zales, Jr. Assistant Treasurer Wachovia Corporation Vice President, Corporate Ceila H. Shorts Charles D. McCrary Secretary and Assistant Treasurer Assistant Secretary President and CEO, Christopher T. Bell Alabama Power Company Kay 1. Worley Vice President Assistant Secretary Dr. Malcolm Portera Robert A. Bell' Chancellor, The University of J. Randy DeRieux Vice President Alabama System Assistant Treasurer Willard L. Bowers Robert D. Powers Yice President President, The Eufaula Agency All information as of Larry R. Grill December 31, 2005 David M. Ratcliffe Vice President except as noted below Chairman, President and CEO Southern Company Donald R. Horsley 2

' Elected 1/06 Vice President C. Dowd Ritter 2 Elected 3/05 Chairman, President and CEO, Gerald L. Johnson 3 Resigned 2/06 AmSouth Bancorporation Vice President, Birmingham Division James H. Sanford Chairman, HOME Place Farms, Inc. William B. Johnson Vice President John Cox Webb, IV President, Webb Lumber Company, Barbara J. Knight Inc. Vice President Ellen N. Lindemann3 James W. Wright Chairman, President and CEO, Vice President First Tuskegee Bank Gordon G. Martin Vice President, Southern Division 53

CORPORATE INFORMATION Alabama Power Company 2005 Annual Report General This annual report is submitted for general The Flexible Money Market and 5.30% Series information and is not intended for use in Class A Preferred Stock connection with any sale or purchase of, or The Bank of New York any solicitation of offers to buy or sell 101 Barclay Street securities. New York, NY 10286 Profile Number of Preferred Shareholders of The Company operates as a vertically record as of December 31, 2005 was 1,701.

integrated utility providing electricity to retail customers within its traditional service area Form 10-K located within the State of Alabama and to A copy of the Form 10-K as filed with the wholesale customers in the Southeast. The Securities and Exchange Commission will Company sells electricity to more than 1.4 be provided upon written request to the million customers within its service area of office of the Corporate Secretary. For approximately 45,000 square miles. In 2005, additional information, contact the office of retail energy sales accounted for 72 percent of the Corporate Secretary at (205) 257-3385.

the Company's total sales of 77 billion Alabama Power Company kilowatt-hours.

600 North 18th Street The Company is a wholly owned Birmingham, AL 35203 subsidiary of The Southern Company, which is (205) 257-1000 the parent company of five retail operating www.alabamapower.com companies. There is no established public Auditors trading market for the Company's common Deloitte & Touche LLP stock. 417 North 20 'h Street Trustee, Registrar and Interest Paying Agent Suite 1000 All series of First Mortgage Bonds, Birmingham, AL 35203 Senior Notes and Trust Preferred Securities JPMorgan Chase Bank, N.A. Legal Counsel Institutional Trust Services Balch & Bingham LLP 4 New York Plaza, 15k" Floor P.O. Box 306 New York, NY 10004 Birmingham, AL 35201 Registrar, Transfer Agent and Dividend Paying Agent All series of Preferred Stock and Class A Preferred Stock except the Flexible Money Market and 5.30% Series Class A Preferred Stock Southern Company Services, Inc.

Stockholder Services P.O. Box 54250 Atlanta, GA 30308-0250 (800) 554-7626 54